Rodney L. Waller – Senior Vice President and Assistant Secretary Jeffrey L. Ventura – President and Chief Executive Officer Roger S. Manny – Executive Vice President and Chief Financial Officer Ray N. Walker, Jr. – Executive Vice President and Chief Operating Officer Chad L. Stephens – Senior Vice President-Corporate Development

Gil K. Yang – DISCERN Investment Analytics, Inc. Neal D. Dingmann – SunTrust Robinson Humphrey Holly Stewart – Howard Weil Ronald E. Mills – Johnson Rice & Co. LLC Jack N. Aydin – KeyBanc Capital Markets, Inc. Phillips Johnston – Capital One Securities, Inc.

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. Rodney L. Waller: 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. Jeffrey L. Ventura: 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 sizable position, sizable acreage position in the core area one on the key plays such as the Marcellus. The second is the ability to consistently execute well; and the third is having a strong forward thinking marketing team. The first item is critical because the application of the technology of horizontal drilling in multiple stage hydraulic fracturing has been applied to most of the domestic basins. Therefore most of the major plays have probably already been identified and leased. The key then is to already have a large concentrated acreage position in the core one of the key plays. The economics are very different in the core versus non-core portions due to the differences in raw quality and its impact on productivity of wells. It’s also interesting to note that in shale plays, the core areas usually represent a small fraction of the play, somewhere around 6% to 17% of the total shale acreage. The non-core then totaled 83% to 94% of the play. Fortunately, we have a huge position in the core of the Marcellus, which is the best gas play in North America, maybe the world, given the economics of the Marcellus and the rest elsewhere. I also believe the ability to consistently execute at a high level, we came in 2014. In 2013 for instance, simply drilling a horizontal well and announcing a high fee rate will sometimes efficient to increase the Company’s stock price. At this point in time, those plays and resource potential are considered known and I believe they are reflected in the stock price. The key now will be to consistently drive our foreign gas production from these plays. Fortunately, Range has a 10 year track record of consistently meeting or exceeding its targets, a 10 year period with a 20% CAGR. Although past performances is no guarantee of the future, we have created a team and culture that consistently performs and meets or exceeds targets. Time after time, rather than succumbing to events like freezing weather, hurricanes and significant infrastructure delays our team finds ways to overcome and achieve its targets. Third, for 2014 and beyond having a strong forward-looking marketing team will be vital. Given the renaissance of the U.S oil and gas business, supply is temporarily ahead of demand although I firmly believe demand growth is coming. We believe that Range is very well positioned in this category too. The best evidence for this again is our performance, after discovering the Marcellus in 2004 and bringing the first well on line in 2005. We knew the quality of our gas was very high BTU and would not meet pipelines classifications because it contains so much ethane. Early on some in the industry viewed gas this rich is a negative, we were approached by some companies who want the Range to pay a fee to them in order to fix our ethane problem. Rather than accept this solution our team was very creative in building a diversified portfolio three ethane contracts based on three different pricing formulas that will not only ensures our gas net pipeline quality specifications, but would also provide market diversification and enable Range to grow production to greater than 3 Bcfe per day. Very importantly rather than these solutions costing us money our team solution enhances the value of the project. If all three marketing arrangements were fully operational today Range’s ethane revenue would increase by 25% compared to leading ethane in the gas stream. That’s net of all transportation and processing cost and including additional propane recovery. I believe this is the best ethane sales portfolio for any company in the U.S. that’s a direct result of our team doing the hard work to make a reality for many people felt could not be done, such as selling ethane to companies in Norway and Canada. The same is true for our propane marketing. In addition to supplying propane into good markets in the Northeast in the winter, we can now seasonally export propane to Central and South America and Europe in the summer. Our marketing team has also ahead of the curve in making sure that we can move and market our natural gas. In addition to marketing gas in the Northeast, in 2013 we added 25 new customers in the South, Southeast, Mid-Atlantic and Midwest, secured firm transportation and firm sales to get the gas to the customers and enhance pricing basis. We have tied the sales price of our gas to approximately nine different industries creating a strong diversified natural gas sales portfolio for Range. We are currently selling our Appalachian gas to customers in Florida, Georgia, Mississippi, Tennessee, Virginia, Louisiana, Texas, Ohio, Pennsylvania, New York, New Jersey, Massachusetts, Delaware, Maryland, Washington D.C., Connecticut, North and South Carolina, Indiana and Illinois. By 2017, our marketing team is working to have the capability of selling our Appalachian gas to customers as far west as Wisconsin, on Atlantic South of Texas, east of Florida and north, the main were projecting that we could be able to move four to five Bcf per day of Appalachian gas where two-thirds of the current U.S. consumption exists. For 2014, there will most likely will be intermittent challenges in Appalachian moving gas and in basis differentials for some in the industry. By 2015, we expect as the market improves, the Texas Eastern turns part of the pipeline around the flow gas south and by late that year Transco is expected to having serve partial reversal to move gas out of Appalachian as well. In 2016, we believe we will see more Transco, Columbia, Dolphin, Texas Eastern capacity going backwards as compared to the original flows. And in 2017 is projected all of the major pipelines will be bidirectional. I believe that our marketing team assets as well positioned as anyone in the basin and better than a lot of the competition. Capacity constrains in basis differential do not impact all producers equally. The priority of transportation capacity in the markets and pipeline where the production is coming from and moving to, are the key differentiators. Range has been or will remain focused on finding creative and effective solutions for marketing our production. On the financial front, we have a strong flexible balance sheet to fund our operating strategy. Range continues to build economies of scale and our structure continues to enhance our competitiveness. Range has continued operational success, use of embedded call options in our debt and the macroeconomic environment and lower interest rates has provided greater access to lower-cost capital. Overall, for 2014, I believe that we’re well-positioned. We have a large footprint in the core of the best gas play in the U.S., a technical and operations team that has demonstrated it can execute well and a strong marketing team with a demonstrated track record. As always, we’ll stay focused on safely executing our plan of being good steward to the environment. I’ll now turn the call over to Ray to discuss operations. Ray N. Walker, Jr.: 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 and our cost per foot of lateral drilled has decreased by 24%. Today we average about 98 frac stages per crew per month, which is 87% more than we averaged four years ago. And our facilities cost per well is 3% cheaper, while importantly cutting construction time in half and deploying design improvements to enhance facility safety, operations and to exceed emission reduction requirements. Needless to say, I can go on and on demonstrating how we’ve achieved tremendous improvement across many metrics while always meeting or exceeding our targets. We believe our track record speaks for itself and again the expectation that improvements will continue year after year is supported by that track record. We own the largest net acreage position in the core of the highest hydrocarbon in place within the basin when considering the Utica/Point Pleasant, the Upper Devonian and the Marcellus. Like Jeff said, having a large acreage position in the core of a top-tier play will be important going forward. And thirdly, having an effective team to handle the evolving logistics of gas and liquids marketing in the basin is of critical importance. As discussed in our earnings release and just now by Jeff in his comments, we are well-positioned for several years to move all of our gas and liquids. Marcellus and Utica/Point Pleasant volume growth by industry in the region does not affect these plans and commitments. Range has current firm transportation and/or firm sales in place totaling 1.1 Bcf per day to the key regions previously mentioned and we have 1.6 Bcf per day lined out through 2016, designed to match our planned volume growth. Keep in mind that we’ve also built a broad network of strong relationships with primary buyers in these markets and will continue to maximize the opportunity to sell our gas to them under their firm transportation capacity. Importantly, we are one of the very few companies that kept all of our customers hold during the recent polar vortex storms when others could not, due to the extreme weather conditions. We were able to do this as a result of some really innovative facility designs coupled with our operations team going 24x7 and so forth. Teaming up with our midstream partners and led by our marketing group, no Range customer went without product and that fact is really paying dividends. As we continue to grow our wet gas volumes, we work closely with our midstream partner, MarkWest to assure that we have adequate gathering, processing and fractionation capacity. Our inventory of wells waiting on infrastructure continues to be one of the lowest in the basin. As Jeff discussed, our marketing team has been extremely innovative as demonstrated by our three ethane projects, which again – when all three projects are fully served, Range’s ethane revenue would increase by over 25% as compared to leaving the ethane in the gas stream and selling it as Btus. For 2014 our CapEx budget will be $1.52 billion with 87% of that directed to the Marcellus. There is detailed breakdown of that allocation in our earnings release and in our investor presentation on the website. Most importantly, with this CapEx budget we’ve elected to drill our Marcellus wells with significantly longer laterals and more stages than previously announced. This will drive greater EURs and better capital efficiencies that will primarily flow through in 2015 and we expect those lateral links to get even longer as we further and continue to optimize our plans. Production guidance for the first quarter should be right at 1.05 Bcf equivalent per day with approximately 30% to 35% of that being in liquids. While able to supply all our customers during the winter storms we did not go completely unscathed when it comes to production growth. There were times when we simply had to shutdown frac operations due to the extreme cold over the last couple of months and we did experience some production downtime. That downtime will impact first quarter growth in volumes as has been the case historically. This is nothing new and was forecasted in our growth trajectory just as we’ve been in the past. For the year, our production guidance remains 20% to 25% year-over-year as we previously stated. Going to the southern Marcellus division, we’ve updated the production from the super-rich wells in 2013 in our investor presentation. We now have a zero time plot of all the wells as compared to the 2013 type curve. The takeaway is that the super-rich area wells are performing above our expectations and getting better as we go. I should also point out that we furnished the zero time plot because the six-month production data provided by the state only shows wellhead gas and condensate and some people continue to miss that distinction. This is really important. For example, in the super-rich area you would miss as much as 1.2 million or more barrels of NGL that are really valuable and often represent half or more the total EUR of the well. In 2013, in the super-rich area, we had an average lateral length of 3,853 with 20 stages. In 2014, we expect to drill wells with average lateral lengths 38% longer at 5,300 with 26 stage completions resulting in an average EUR of 2.05 million Boe per well. For 2015, the lateral lengths in our current plan average 5,600 feet with 28 stages and an average EUR of 2.23 million Boe. In the wet area in 2013 our average lateral was 3,200 feet was 16 stages and for 2014 we are planning a 4,200 feet with 21 stages resulting in an expected average EUR of 12.3 Bcf equivalent. For 2015, the lateral lengths in our current plan averaged 4,800 feet with 24 stages and an expected average EUR of 14 Bcf equivalent. In the dry gas area of the Marcellus and Southwest Pennsylvania in 2014 we are planning 5,200 foot laterals with 26 stage completions resulting in an average expected EUR of 13.4 Bcf. This is up significantly from 2013 which averaged 2,950 feet with 14 stages. And for 2015, the lateral lengths of today are identical to 2014. Although that EURs, lateral lengths and number of stages are updated in our investor presentation and we have upgraded the type curves and the economics to reflect our current plans for 2014 based on recent well performance in each of these areas. Again, I want to point out that we do expect that these lateral lengths will get longer and thereby resulting in higher EURs and higher returns as we continue to optimize those plans. We’ve talked about improving capital efficiencies in the past and I would like to point out a tangible example of that occurring this year. And in Southwest Pennsylvania our plan is to go back on to five producing pads and drill approximately 14 more wells. Just in pad construction alone and not counting all the other already present infrastructure such as compression, gathering, watering roads for the well planned on most pads we estimate that will save over $200,000 per well just in pad construction alone. Even more importantly the real efficiency comes from the savings in time. We essentially save 9 to 12 months in preparation and permitting best brand new significant production volumes from these 14 wells online 9 to 12 months earlier. As we do this more and more over the coming years the increase in capital efficiencies will be significant, and this is a tangible example of just one of those improvements. There are many more factors that should also significantly improve our capital efficiency in value going forward. Just a few examples would be improved recoveries of hydrocarbon in place, better completion designs, longer laterals, closer space laterals, development of multiple horizons from the same pad and the list goes on and on, again making that inventory of resource potential more and more valuable return. Also of note, we are planning to drill a Point Pleasant well in what we believe is the core of the play underneath our Marcellus position in Washington County. The well should start this spring and the current plan would yield us production test prior to year end. Based on our expensive high quality 3D and Trenton/Black River test in the immediate area we already know a lot about the rock. The Point Pleasant is expected to be approximately 130 foot thick with around 10% porosity. Gas in place is expected to be as high as 140 Bcf or more per square mile and we expect around a 1,000 [indiscernible] exceptional year. We have strong indications that the reservoir pressure to be extremely high thereby resulting in really high gas in place and really high productive. And the TBD will be about 11,500 foot which is very workable. The plan is to drill a long lateral and complete it with an RCS style completion. We have all the ingredients for a highly productive well including thickness, the right maturity, very high gas in place, exceptional rock quality, high pressure, a 3D survey and a set of very reasonable and workable debt. Shifting to the Northern Marcellus the team continues to maintain our position while drilling some really impressive dry gas well as listed in our earnings release. For 2014, the division will average lateral length of 4,600 foot and 23 frac stages. The team recently brought on line a three new wells on a pad that together came to a little over 4 Bcf at 90 days. One of those wells have a lateral length of 6,300 and 53 feet with 32 stages, it’s first 30 days production to sales averaged over 23 million a day, and it has a projected EUR of right at 18 Bcf. We have a 100% working interest and an NOI of 86% in that well. Again, we believe our position in Lycoming County is a prime dry gas area that is essentially HBP-ed and ready for us to ramp up when the time is right. In the Midcontinent division, we remain focused on delineating and testing our Mississippian Chat acreage on the Nemaha Ridge along with developing our St. Louis production in Texas Panhandle. For the Chat play we are continuing with our larger stimulation designs and those are updated in our investor presentation, while it’s still early these results are encouraging, as we analyze our recent 3D data in the Oklahoma portion of the play, we expect to make good progress and developing our understanding of the reservoir and its delineation throughout 2014. For the Southern Appalachian division, the horizontal Huron shale wells drilled in 2013, where our best ever. The CVM wells continue to improve resulting in positive revisions, and a vertical tight gas sands wells continue to outperform our forecast in two of those wells, being the best we’ve drilled to-date. The team continues to hold production on a minimal decline with very limited capital essentially holding production flat. In closing, 2013 was a great year and we have a plan that will make 2014 in many years into the future also great. Range has about 1 million net acreage and one of the best plays out there with a lot of that provision in the core of the highest hydrocarbon in place in the Appalachian basin. We believe we can execute as well as anyone and we have the people and the track record to support that belief. And we have a marketing and logistics team that’s been innovative and class lean while positioning us to remain confident in our ability to consistently grow production 20% to 25% year-over-year and leverage shareholder growth in many years into the future. Now over to Roger. Roger S. Manny: 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 our capital and cost efficiency are clearly flowing through to the Range bottom line. One of the most visible indicators of improving capital efficiency is our DD&A rate per Mcfe. The DD&A is the most significant cost item flowing through the income statement and in the fourth quarter of each year we’ve reached out our DD&A rate all in completion of our year end proved reserve. The DD&A rate for the fourth quarter of 2013 was a $1.36 per Mcfe down 7% from the $1.46 in the fourth quarter of last year. And as Ray and Jeff mentioned the DD&A rate is down 38% from 2009, not from ceiling test rate down, but from real improvement in capital efficiency, unproved property impairment for the quarter at $6 million was unusually light inflecting a year end true up. However we do expect this expense to be significantly lower in 2014 than prior years, with first quarter unproved property expense, coming in between $12 million and $14 million as we continued to block up and high grade our acreage positions. Likewise cash exploration expense for the fourth quarter at $13 million came in significantly below guidance as we experienced fewer dry holes and less delay rental expense than planned. The first quarter of 2014 reflecting a reloaded 2014 seismic budget, should see exploration expense return to the $17 million to $19 million range. All other quarterly expense items came in at or below guidance, although I should mentioned that unlike prior quarters, direct operating expense guidance is going to be flat to slightly higher in the first quarter of 2014 at $0.37 to $0.39 per Mcfe. A bit pause in the quarterly reduction again in operating expense is due primarily to the 24x7 shift coverage by our lease operators and improving weather conditions that Ray mentioned. We expect direct operating expense to resume its gradual drift downward after we get to the first quarter. Please reference our year-end 2013 press release for additional first quarter 2014 expense style of guidance. Our balance sheet at year-end was right on plan, with our trailing fourth quarter debt-to-EBITDAX ratio at 2.8 times that’s down from the 3.2 times figure at year-end 2012. Leverage continues to decline as our cash flow grow outpaces our growth and leverage and with $500 million and bank debt outstanding we’ve ended the year with approximately $1.2 billion an unused committed availability, under our $1.75 billion bank facility. Fourth quarter was another active quarter for hedging, thus Range adding natural gas, NGL and low hedges for 2014, 2015 and for the first time 2016. The Range website in press release tables contained detailed hedge volumes and prices, by product that investors may use in preparing their updated forecasts. In summary, 2013 reflected another year of improving unit costs and capital efficiency and holds a strong double-digit in our production and reserve growth. 2014 looks to be similar and off to a really good start. Higher natural gas price in two of our long-term NGL offtake contracts up and running [indiscernible]. Also unit cost continue to decrease while we project another year of steady production growth of between 20% and 25%. Jeff, over to you. Jeffrey L. Ventura: 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? Jeffrey L. Ventura: 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? Jeffrey L. Ventura: 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? Jeffrey L. Ventura: 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? Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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? Jeffrey L. Ventura: .: 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? Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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? Ray N. Walker, Jr.: 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. Jeffrey L. Ventura: 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. Jeffrey L. Ventura: Good morning. Holly Stewart - Howard Weil: 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? Chad L. Stephens: 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. Holly Stewart - Howard Weil: 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? Roger S. Manny: 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. Holly Stewart - Howard Weil: Perfect, thanks gentlemen. Jeffrey L. Ventura: 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? Ray N. Walker, Jr.: 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 goes along, but I don’t think, we are ever going to a point where we can just sell right through. The really cold weather in January and February is a blessing and we certainly are very appreciative this year that we had cold weather and polar vortex storms and all that, especially since I don’t have to live in Pittsburgh any more, it’s really great. But the fact that it is cold, it’s hard to have operations going consistently through January and February, and it’s going to be that way forever. So, I think you are always going to see the first quarter down. We forecast and in our numbers, we’ve done that as far back as I remember. And it’s going to always be that way. So, I think that is just part of it. But did I tell you about those super-rich wells that we’ve been drilling lately. It has turned really well, [indiscernible]. Ronald E. Mills – Johnson Rice & Co. LLC: And then, when you talk about the going back existing producing pads, one just to make sure I understood, will you go back to five currently producing pads this year and drilling 14 more wells. I am assuming the 14 is an aggregate number. I guess number one, and then number two, you had the excitement or the description of why you’re so excited about the Utica on your acreage, came through loud and clear. But do any of – are you also doing any other stack pay test? Are you continuing to test Upper Devonian and some of these areas, and/or is that part of what you’re going to do on some of these producing pads, you go back into? Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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. Ray N. Walker: 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. Chad L. Stephens: 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? Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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? Roger S. Manny: 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… Jeffrey L. Ventura: And the wells drill – will be drill of in existing Marcellus? Roger S. Manny: Yes, I add and there is room for additional wells, so it could really be great upside for us. Ray N. Walker, Jr.: 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? Ray N. Walker, Jr.: No, we currently don’t have any plans right now in the schedules. Phillips Johnston – Capital One Securities, Inc.: Okay. Thanks guys. Jeffrey L. Ventura: 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. Jeffrey L. Ventura: 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.