山脈資源 (RRC) 2011 Q1 法說會逐字稿

Welcome to the Range Resources first quarter 2011 earnings conference call. This call is being recorded.

(Operator Instructions)

Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements.

After the speakers' remarks there will be a question and answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, Operator. Good afternoon, and welcome. Range reported results in the first quarter of 2011 with record production and improving unit costs. The first quarter marked our thirty-third consecutive quarter of sequential production growth. Range has a very large inventory and base of reserves that will continue to drive our growth in production in reserves. At Range we're focused on growth at low cost on a per share basis to maximize shareholder value. I think you will hear those same things reiterated from each of our speakers today.

On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John, I would like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It is now available on the home page of our website, or you can access it using the SEC's EDGAR system. In addition, we 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 our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you detailed information of our current hedge position by quarter, including our new NGL hedges.

Second, we'll be participating in several conferences in May. Check our website for a complete listing in the next several months. Our annual stockholders' meeting is being held in Fort Worth on May 18. We hope that each stockholder has received their proxy materials, and we urge each stockholder to vote for the proposals being submitted by the proxy. Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews our first quarter financial results, I'll review some of the key accomplishments we put together in the first quarter. On a year-over-year basis, first quarter production rose 17%, reaching the midpoint of our guidance; and also production on a per share basis also rose 17%. As Rodney mentioned, this is the thirty-third consecutive quarter of sequential production growth. If you adjust for the asset sales, first quarter 2011 production growth would have been over 20%. Our drilling program was on schedule throughout the quarter, as we drilled 63 wells. We had 100% success rate. We continue to be extremely pleased with the drilling results. Despite the low natural gas prices, we're generating some very attractive returns from the projects where we're spending our money. We currently have 20 rigs in operation. The 17% increase in production was partially offset by a 2% decrease in realized prices. As a result, first quarter oil and gas revenues were up 15%, compared to the prior year period. Cash flow was also up 11% compared to last year.

On the cost side, we were pretty pleased. In particular, we saw a 10% decrease in our 5 largest cost categories combined. The only disappointment was that direct operating costs came in at $0.75 per Mcfe, $0.02 higher than last year. This was due to the extremely cold weather that we incurred throughout the first quarter, and primarily February, and also due to some higher water handling costs in the Marcellus Shale. With regards to our Marcellus Shale play, we made significant headway in the quarter as we continued to drill just some fantastic wells. We continue to fill in our acreage position and build out our pipeline processing infrastructure. In addition, we continued to hire some really high quality people that work on our Marcellus team. In Pittsburgh now, or at Southpointe, we now have over 300 people working on the Marcellus, and very exciting to see that team. Lastly, we completed the due diligence phase of the Barnett sale, and we're just a few day away from closing the sale. All in all, I am very pleased with how much we accomplished in the first quarter. I complement the entire Range team for a job well done. With that, I will turn the call over to Roger Manny to review our financial results.

Roger?

Thank you, John. The first quarter was a busy period for the accounting and finance team, as we closed the new bank credit facility, supported the Barnett sale process, and reclassified our current and historical results for the Barnett sale assets as discontinued operations. We expect to soon file an 8-K that effectively amends our 2010 Form 10-K to reflect the Barnett assets as discontinued operations. The last time we worked through discontinued operations accounting was following the offshore Gulf of Mexico sale back in early 2007. Now remember that reclassifying our historical financial statements, reflecting discontinued operations, was a source of confusion, as investors attempted to reconcile year-over-year and quarter to quarter performance, when our historical results had been changed due to the asset sale. And for this reason, the financial results I will be presenting on the call will include the historical results of the Barnett assets, including the first quarter of 2011; and these will match the supplemental non-GAAP figures in the press release. There are tables included in the press release and posted on our website that reconcile the discontinued operations results that appear in our 10-Q to the continuing operations results.

Now, starting with the income statement, oil and gas revenue, including cash settled derivatives, was $268 million for the first quarter, 15% higher than 2010. Cash flow for the first quarter was $163 million, 11% higher than last year, and higher than the fourth quarter of last year. In fact, this was the third consecutive quarter of improving cash flow. Per share cash flow for the quarter was $1.02, even with the analyst consensus estimate. First quarter EBITDAX was $198million, 12% higher than last year, and like cash flow, the third consecutive quarter of improvement. Cash margin for the first quarter was $3.29 in Mcfe, up $0.23 from the fourth quarter of last year, but down $0.20 from last year's first quarter, due mostly to lower price realizations, and to a lesser extent, higher operating costs. Quarterly earnings calculated using analyst methodology for the first quarter, which excludes certain nonrecurring and non-cash items, was $35.2 million, or $0.22 per fully diluted share. That's $0.03 higher than the analyst consensus estimate of $0.19.

As Rodney mentioned earlier, we would like you to reference the Range Resources website for any questions concerning the reconciliation of these non-GAAP figures, including cash flow, EBITDAX, cash margins, and analyst earnings. Looking at the cost structure this quarter, we saw another significant drop in our DD&A rate, from $2.12 in Mcfe the first quarter of last year, to $1.65 per Mcfe in the first quarter of this year. We anticipate the DD&A rate for continuing operations in the second quarter will be approximately $1.84 per Mcfe. Now this projected $0.19 increase in the DD&A rate next quarter is not a step back in our drive for greater capital productivity, but it is due to one of the peculiarities of asset sale accounting. When an asset is held for sale as a discontinued operation at fair value, that asset is no longer depreciated or depleted. In the case of the Barnett, the assets were deemed held for sale at the end of February, so in accordance with accounting rules, there was no Barnett depletion booked for the month of March, even though we recorded production from the assets. The mathematical result of this accounting treatment is a peculiar nonrecurring reduction in the DD&A rate. Now, we look forward to continued progress driving down this non cash expense the rest of the year, and we predict that by year end the DD&A rate really will be $1.65 per Mcfe, unaided by asset sale accounting treatment.

As John mentioned, direct cash operating expense before non-cash comp, but including workovers for the first quarter, was $0.75 per Mcfe. That's up $0.02 from last year, and up $0.03 from last quarter. Part of the reason for exceeding expense guidance on this item was reduced production from cold weather. For example, if you are running a compressor, and that compressor is not running due to a frozen wellhead, unit costs will suffer. And we also saw increases in water handling expense up in the Marcellus, and increased expense at various non-operated well operations. Direct operating expense declined each month during the quarter, so while the total was higher than expected, we remain encouraged by the trend towards lower costs.

Listeners may anticipate cash direct operating expense in the second quarter to be approximately $0.71 to $0.73. We still believe we can push this cost down to the low $0.60 range by the end of the fourth quarter. Production taxes for the first quarter were $0.16 in Mcfe; that's down $0.01from last quarter and down $0.03 from the first quarter of 2010. Production taxes are expected to drop another $0.01 in the second quarter. G&A expense, adjusted for non cash stock comp and other nonrecurring items, was $0.55; down $0.02 from last quarter, but up $0.06 from the first quarter of last year, due to higher legal fees and higher public relations expense. We performed favorable to guidance on this cost item during the first quarter, and that offset higher than anticipated direct operating costs. Now for the second quarter of 2011 our estimate is that G&A expense will be in the $0.56 to $0.59 range.

First quarter interest expense was $0.73 in Mcfe; that's flat with the previous two quarters. Interest expense should decline slightly this year, once the Barnett sale proceeds are applied to pay off the outstanding bank debt. But once quarterly production volumes reflect the Barnett sale, interest unit costs are expected to be up $0.01 next quarter, but declining later by year end. Now exploration expense for the first quarter of 2011, excluding non-cash stock comp, was $26 million. That's up considerably from prior quarters due to higher seismic expense, and to a lesser extent, higher delay rental expense. Seismic spending is always somewhat sporadic, but based on our budget for this year, we continue to estimate total exploration expense at approximately $25 million to $26 million per quarter in 2011. Abandonment and impairment of unproved properties for the first quarter was $16.5 million. That's down significantly from last quarter, and spot on with last quarter's expense guidance. Acreage value estimates can change unpredictably, but the rest of 2011 should see unproved impairment running $15 million to $18 million a quarter.

As our capital spending currently exceeds cash flow, Range continues to generate excess intangible drilling cost deductions for tax purposes. Now, we expect to actually end the year with a larger NOL carry-forward than we entered, due to IDCs generated by our drilling program. So, there will be no tax leakage of the Barnett sale proceeds and no significant diminution, if at all, of our NOL.

Range has continued to add to its hedge position, with 80% of our 2011 gas production hedged at a floor price of $5.40 in MMBTU, following the Barnett sale. Now for 2012, we have approximately 190 million cubic feet a day hedged at a floor price of $5.32. And in 2013, we now have 100 million cubic feet per day hedged with collars at 5 by $5.73 per MMBTU. We've also hedged a portion of our 2011 and 2012 liquids production, with 7000 barrels per day hedged in the third and fourth quarter of 2011 at $104.17 per barrel, and we have 5,000 barrels per day of 2012 liquids hedged at $102.59 per barrel. Please see the hedging tables attached to the press release and the more detailed tables on the website if you need some additional hedging information.

In summary the first quarter of 2011 brought continued increases in production and cash flow, with reductions in our aggregate cost structure, and the path is cleared for the Barnett sale later this week, and we look forward to the balance sheet improvement in future funding certainty that that sale will provide. John, back to you.

Thanks, Roger. Now let's turn the call over to Jeff Ventura to review our operations. Jeff.

Thanks, John.

This year we will focus about 86% of our capital in the Marcellus Shale. Given the large de-risk acreage position we have in the play, 2011 should be an exceptional year. Even with the Barnett sale we still expect it will achieve double-digit reserves growth in 2011. We anticipate achieving 10% production growth. We believe we will overcome the production sold in the Barnett sale. Barnett production is approximately 110 million cubic feet equivalent per day. We exited the Marcellus at a net rate of approximately 200 million per day last year, and we are on target to exit the Marcellus at a net rate of 400 million equivalent per day this year. Currently we have nine drilling rigs in the southwest portion of the play, and four in the northeast part of the play. I believe we will have sufficient production capacity from the wells we have drilled and will drill this year, to achieve our targeted goal of 400 million cubic feet per day net. I also believe we'll have adequate processing and gathering capacity.

Let me take a few minutes to discuss processing and gathering capacity for 2011. In southwest Pennsylvania, we currently have processing capacity of 170 million cubic feet per day at the [Houston 1 and 2] plants. The [Houston 3] plant is expected to come online tomorrow, and ranges capacity in that plant will be 165 million per day, which will increase our total processing capacity at that site to 335 million cubic feet per day. At the Majorsville 1 plant, Range's current processing capacity is 30 million per day. By mid-third quarter, the Majorsville 2 plant is planned to be in service. Once online, this will increase Range's processing capacity at that site to 70 million per day. Therefore, our total processing capacity under contract with [Mark West] is growing to 390 million per day.

In addition to our processing capacity in southwest Pennsylvania, our gathering capacity is 375 million per day, and is planned to be expanding well ahead of production volumes throughout the year. We are well-positioned to be able to move the gas from the wellhead to the processing plant. In Lycoming County, our current gathering system capacity in Phase I is 50 million per day. The remainder of Phase I and Phase II gathering systems are planned to be completed in the third quarter, and at that point in time, our gathering capacity will be 200 million per day in Lycoming County.

So in total, by year end 2011, between the northeast and southwest, our processing capacity for the wet gas is expected to be 390 million per day, and our gathering capacity, which is pipelines and compression, is expected to be more than 575 million per day. We have planned, and should have in place, processing and gathering in all areas to meet our needs this year, with plans to stay well ahead of our projected production ramp over the next few years. In southwest Pennsylvania, Range's gas flow for 2011 is covered by firm pipeline capacity or long-term sales contracts with primary capacity holders. In northeast Pennsylvania, Range's gas flow for 2011 is covered by long-term sales to customers who have firm capacity on the Transco-[Lidey] line. Except for force majeure events or unexpected pipeline maintenance, we have the proper downstream capacity, and/or sales in place, to move our production to market in 2011 and 2012. Range has also entered into two MOUs with ethane consumers, with the intent to negotiate long-term arrangements to sell ethane into the marketplace.

We are staying focused on the Marcellus Shale, and are on target to meet our goals there of driving up production to 400 million per day with one of the best cost structures and one of the best rate of return plays. We continue to see great well results in the Marcellus. During the quarter, we brought online 15 new wells in the liquids-rich portion of the Marcellus, with an average initial production rate of 10.1 million cubic feet per day equivalent, which consists of 7.4 million per day of natural gas and 452 barrels of NGLs and condensate per day.

Our plan for 2011 is to drill moderate lateral lengths, fewer wells per pad, and retain our acreage in this prolific play, for not only the Marcellus potential but also for the Upper Devonian and Utica shales. However, we'll continue to undertake some interesting tests this is year. The tests consist of different stepout drilling, targeting, and/or new completion approaches in multiple areas this year. The first is in the Upper Devonian Shale. We brought online in the first quarter our first two Upper Devonian Shale wells. The first well, which was previously announced, had an IP of 5.1 million per day, and was a dry gas well. The second well came online under constrained conditions, at a rate of 2.5 million per day, which is comprised of 1.9 million cubic feet of gas and 91 barrels of liquids. The decline rate of the second well is significantly flatter than the first well, and the second well has a higher EUR than the first well. For our first two horizontal wells in the Upper Devonian Shale, we're encouraged about the results and the potential it has for unlocking the Upper Devonian Shale resource potential.

The combined IPs of the first two Upper Devonian wells average 3.8 million cubic feet equivalent per day net. To provide perspective, in the Marcellus Shale, we did not see an IP of 3.8 million per day until we completed our seventh horizontal well. Reserves for the first two Upper Devonian Shale wells look like they're in the range of 2.5 Bcfe to 3.5 Bcfe per well. This is significantly ahead of where we were in the Marcellus at this point in time. Overall, the gas in place per section is similar to the Marcellus. Key future wells will focus on determining the optimum place to land the laterals within the section, optimum lateral length, and number of stages. We plan two to four additional Upper Devonian tests this year. Importantly, like the Marcellus, a significant portion of the Upper Devonian Shale potential in our acreage should be wet gas. Of course we have tremendous upside, not only in the Upper Devonian Shale, but also in the Utica Shale in Pennsylvania. Our next horizontal Utica well will be late this year, followed by a third well early next year; however, I expect multiple wells in both of these plays from others in industry to continue to prove up our acreage.

Next is the liquids-rich portion of the Marcellus. Our average wells in the wet portion of the play make about 5 Bcfe, which is comprised of 3.6 Bcf of gas and 239,000 barrels of liquids, mostly with 8-stage fracs. We recently tested a 3,500-foot effective lateral with a 12-stage frac in one of our wettest areas, and to date it looks like the well will produce 6.7 Bcfe, which is split between 4.1 Bcf of gas and 425,000 barrels of liquids. We plan to go back into the liquids-rich area with new wells and test additional longer laterals, pump more stages per lateral, and try to achieve higher conductivities in the prop fractures. Given the huge acreage position we have in the liquids-rich portion of the play, this could be very impactful. With we'll also look at the effect of adding more stages and drilling longer laterals on a few of our wells in Lycoming County.

In short, some portions of the Marcellus play, that's wet versus dry, may be more efficiently developed in slightly different ways. The tests we're doing for the purpose of finding the optimal rate of return for our entire Marcellus program and to improve Range's cash flow. In addition to the 790,000 net acres we had at the beginning of the year in the Marcellus Fairway, we have about 285,000 net held by production acres in northwest Pennsylvania. The Marcellus in northwest Pennsylvania is about 4,000 feet to 4,500 feet deep, more similar to the Fayetteville in terms of depth and pressure; however, within the wet portion of the Marcellus. Given the huge HPP position here, and potentially significant impact, we'll drill a horizontal Marcellus well in that area this summer.

Turning to the Mid-Continent, the horizontal Mississippian play in northern Oklahoma continues to show promise. Of our first five wells completed in the play, 30-day rates have averaged 340 barrels of oil equivalent per day, with peak rates averaging 550 barrels of oil equivalent per day. This includes 1 short lateral drilled early in the program. The first well of a 4-well program in 2011 has been turned to sales at early rates of 380 barrels of oil equivalent per day, with the well restricted due to pipeline capacity issues. Plans are now underway to improve takeaway capacity in the area. In addition, two wells are undergoing completion, while the fourth well has commenced drilling. Our play area continues to expand, with over 28,400 net acres, and potential for over 140 horizontal wells. We currently are estimating unrisked reserve potential of 300,000 barrels to 500,000 barrels per well.

Up in the Texas Panhandle we had excellent success with our first horizontal St. Louis well. It came online at 13.8 million cubic feet of gas per day, and 903 barrels of liquids, or about 19.2 million cubic feet equivalent per day. After producing for about three months, it is still making 13 million cubic feet of gas per day and 900 barrels of liquids. Payout was within weeks. We'll be drilling three additional horizontal St. Louis wells this year.

At this point, I will turn the call back on over to John. I will be happy to answer your questions in the Q&A.

Thanks, Jeff. Great update.

Looking to the remainder of 2011, we see continued strong operating results. For the second quarter of 2011, we're looking for production to average 500 million to 505 million per day. Factored into the second quarter production guidance is the Barnett sale, which we anticipate will close in a few days. So, we'll have the Barnett production for approximately one month in the second quarter. The Barnett, as Jeff mentioned, is currently producing approximately 110 million a day. When you average the loss of 110 million a day for 2 months in the second quarter, it equates to losing 73 million a day over the entire quarter on average. Assuming we hit the mid-range of our guidance for the second quarter, it will represent a 7% year-over-year increase. This 7% increase does not adjust for the Barnett sale. If you adjust for the Barnett sale, the year-over-year growth would be 22%.

We are looking to make up about half of the sole Barnett production by the end of the second quarter, and the other half by the end of the third quarter. For the entire year, we still expect to achieve 10% production growth despite the Barnett sale. We expect to exit 2011 with the Marcellus Shale at 400 million a day; and with total Company production, exiting the year at over 600 million a day. Now that we're nearing the closing of the Barnett property sale, I will take a moment to look at the impact of our divestiture program. Including the Barnett sale, our divestiture efforts have yielded nearly $2 billion in sales proceeds. It has also reduced our well count by over 6,000 wells. This represents roughly 60% of our original well count. The properties that we sold were our more mature, higher cost properties. The good news is that, while we were selling our more mature properties, we were focusing our capital on higher-return projects.

Despite the asset sales, our production reserves have consistently increased during this period. As a result, Range is now a much more efficient Company. We are doing more with less. By less, I mean less wells, lower find development costs, lower operating costs, et cetera. The first quarter results reflect the lower costs. Over the medium to long term, this will have a significant impact on our per share value. This is critical to generating attractive returns in a low gas price environment as well. In addition, by having fewer wells and properties and a more compact asset base, we can better focus our technical team on higher return projects, and making those projects even better. Lastly, one of Range's hallmarks is to keep things simple; and having fewer wells and properties, Range is a simpler Company, allowing the Range team to focus more on its efforts of driving up reserves and production on a per share basis.

Turning to the Barnett sale, as mentioned previously, we anticipate closing the sale in a few days. This is a hugely important event for our Company. First, the sales proceeds will be more than sufficient to retire all of our outstanding bank debt, with excess proceeds available to help fund our 2011 capital program. As a result, Range will have by far the strongest balance sheet in its history. Second, the sales proceeds generated by the sale will be a catalyst for Range becoming internally funded by 2013. Between now and then, we know exactly how we're going to fund our growth. Importantly, our shareholders, you now know specifically how we're going to fund our future growth. Having a strong balance sheet and knowing how we're going to fund our growth puts us in a position of strength. We can now focus all of our energy on executing our business plan of driving up production reserves on a per share basis at top quartile cost structure.

The driver of this growth is our drilling inventory, which I believe is exceptional. We have the drilling projects in place that at low commodity prices generate outstanding rates of return. As Jeff mentioned, our operating teams are continuing to enhance and improve our well results, while maintaining our stellar safety record. While clearly biased, I am convinced we have an exceptional asset base and drilling inventory, as well as an exceptional team of people driving our performance. Our management team is keenly focused on enhancing our asset base and improving our team's performance. Selling our Barnett properties was somewhat of a bold move, as the Barnett properties currently comprise about 20% of our production. After careful study and deliberation, we were convinced that it best served our strategy of growth at low cost. Most importantly, we believe it best served Range's shareholders, as it provides a clear path for capital funding, and allows Range's existing shareholders to retain 100% of our 35 Tcf to 52 Tcf of current resource potential.

From an investor's point of view, I believe Range is somewhat of a unique proposition. Because of our high quality drilling inventory and low cost structure, we can generate attractive returns at today's low natural gas prices. This provides substantial downside protection. On the other hand, because of the extraordinary resource potential of the Marcellus Shale and our other projects, we have one of the largest per-share upsides of any company in our peer group. With the capital funding issue being clarified by the Barnett sale, we're extremely excited and motivated. We appreciate the support and confidence that our shareholders have shown in us, and we look forward to the remainder of 2011.

With that, Operator, why don't we turn the call open to questions.

Thank you, Mr. Pinkerton. (Operator Instructions) Our first question is from David Heikkinen with Tudor, Pickering, Holt. Please go ahead with your question.

Good afternoon, guys. John, given you expect to be free cash positive in 2013, can you walk us through two things, first, your capital budget expectations for 2012 and 2013, and second what your commodity price expectations are for that plan?

The price expectations, we were using roughly $4.50 NYMEX for 2011, $5.00 for 2012, and $5.25 for 2013. In terms of capital budgets, the next year's budget will be similar to this year, and in 2013 we'll probably spend a couple hundred million more than what we're spending for 2011 and 2012. And there are some things baked into it, obviously, into those capital budgets. We expect to become more efficient in terms of some of our drilling. We'll be able to spend more on drilling as time goes by, versus on things that are non-drilling expenditures.

And the other thing is as we build out the infrastructure and as you move through 2011, 2012, and 2013, a great number of wells we're drilling this year won't get hooked up until next year, but as we get bigger and we get more outreach of our pipeline system, we'll be able to connect more wells faster. So you will see some production growth, more efficiency in terms of that than you're seeing, let's say, for the past two or three years. So all of that is baked in there. We have done a lot of work on it, and we're pretty confident that we can make all of that work.

So thinking about activity levels, so you've got CapEx flat as rig count goes up by roughly four rigs. Is that all efficiency, or do you expect capital costs to come in as you go into development mode and get more concentrated, or can you just maybe walk through some specifics around well costs or something along those lines?

We think well costs will come down with time as we've got - - we're a little over a couple hundred wells into the program of what could be 5000 wells to 10,000 wells. As we continue to drill wells and it becomes more and more manufacturing, I think it is not unreasonable to think that within time if we keep the same design, that we may be able to knock maybe $500,000 a well off. It may take us two or three years to get there, but we can move towards that as we get more into that mode.

Of course the other thing we'll do is continue to look at how to optimize completions and rate of return, and there is a variety of things. It may be that we tweak lateral length stages, where is we land them, and all of those things could lead to efficiencies. It may be that if we stick with the same design a half million per well comes off, or it could mean with the more optimum design it costs a little more, but the rate of return is higher and we're more capital efficient. Either way, I think we'll get better with time.

Okay, and then just one specific question on your NGL hedges. You locked in C-5 plus. Can you talk about realizations or expectations for realizations and production volumes for the C-4 minus side that you haven't hedged?

Well we believe that the C-5 is a good proxy for C-2s and lighters, and so what we'll simply do is we're hedging that [into] a very liquid market, but we will modify the amount that we hedged to account for the difference in a dollar change in those commodity prices as we go forward.

So out of your total NGL barrel, how much is C-5 plus and how much isn't then, just trying to get to a split?

If you look at the slide in the flip books on 33 for the Marcellus, your C-5s are going to run about 6% of that barrel, and it will be a little bit less than that in the Mid-Continent area, but if you look at the correlation, David, those C-5s and C-4's all correlate within $0.50 of each other.

Okay, so still thinking that normal kind of 50-ish percent of total TI on everything else then, on the blend?

I'm sorry, I didn't hear the question.

[It means] 33 is still guiding to a 51% of WTI realization; you just locked in the C-5 plus?

That's right.

Thanks. That was it.

The next question is from David Kistler with Simmons & Company. Please go ahead with your question.

Good afternoon, guys.

Hi, David.

Real quickly, following up on the CapEx before we get to 2012 and 2013, looking at '11, drill bit was about $267 million this quarter with a target of about 1.38 for the year. Can you walk us through the ramp up? I think it is significantly heavier in 3Q and 4Q, but if you could just help us through that, that would be great.

When you look at production, it is clearly going to follow that way in completions, but it's definitely going to be a little more weighted towards the third and fourth quarters.

Can you give us a breakdown of how that - - in terms of percentage-wise we should be modeling that out?

Maybe what we can do the best thing is talk to Rodney and [Leif] and David, and they can give you a little more granularity. We don't have that right in front of us, but they can give it to you after the call.

No problem. And then speaking a little bit to the wells that were drilled and waiting on completion or tie-in, there were about 51 this quarter on a gross basis, when we start thinking about that and comparing it to previous quarters, or kind of what target rates are going forward, could you give us some sort of sequential comparison, so we know what you're going to be anticipating the flow through over time?

You know, part of the issue there is we're doing drilling now up in the northeast and in the southwest. To give you a little clarity there, once we get the rest of Phase I on and Phase II, we're looking at bringing 29 wells online towards the end of the third quarter in Lycoming County and an additional 11 in the fourth quarter. So what is that, 40 of those wells are going to be skewed towards the late third quarter and fourth quarter, so we feel comfortable. We entered the year at about 200 million per day net; we'll exit the year at about 400 million per day net, but it's going to be skewed towards the third and fourth quarters.

Okay. And what should we anticipate is just sort of a typical backlog that you would have of drill down completed wells, just so we can get a sense of what's being held up by infrastructure or just service constraints at this point?

Well, in terms of service constraints, there isn't, because what we tend to do is lock in. We have our rigs locked in, we have frac crews locked in. We're not waiting on a frac crew to pop open from another company in order to complete our wells. What do you have a little bit, though is, like I said you have - - we're waiting on the rest of Phase I and 2 in Lycoming County, and there are different events, and I mentioned in terms of Majorsville and [Houston] 3 and all of those different things coming on. We have a number of wells waiting on completion, and that should get better with time as we continue to build out infrastructure.

Like John said ultimately, once we finally delineate and have what we have, have all of that stuff in place, it'll come down. In terms of real specific guidance, I don't have that in front of me. That's another thing we can look at with time, but that's why rather than trying to give you rigs and when they come on, we're trying to give you the rigs that we currently have and what the rigs look like going forward in terms of the Marcellus, but we're also trying to give you the exact - - we're giving you production guidance for this year at 10%, next year at 25% to 30%, exit this year or enter this year at 200 in the Marcellus and exit the year at 400, exit 2012 at 600. So we're giving you the production numbers that go with it. I think that's a lot simpler thing to do, rather than you guys trying to time when the wells are going to come on, and I think if you follow the guidance it is a better way to do it.

Okay, I appreciate that clarification. And then, as we just jump over to one last thing, the ethylene agreements that you or John mentioned on the call and in the ops update, can you give us any kind of color on size of those, timing, because obviously those will kind of add a different hedge in place at some point?

(inaudible) confidentiality agreements, and I think Dow has given you more information than what we were allowed to give earlier, until you get to these long-term agreements in place. We have two memorandums of understanding that we'll be going to two different directions regionally. We have more proposals than we think that we could actually satisfy with us and the other producers there, but that will just simply come out over time, but once we have the fractionator in place in late 2011, then we'll be able to get our extractions [as to] where we want them. All the ethylene and the ethane production is going to be governed by probably a [sonoko] line going to Sarnia, and the producer, the petrochemical companies in Ontario will have to retrofit, so that will probably be third or fourth quarter of 2012 at the earliest that we can actually start production.

Great. That clarification is very helpful, Rodney. I appreciate it. Thanks, guys.

Thank you.

Thanks, David. David, you know, in terms of some of those detailed questions, in terms of the wells on things, just holler at Rodney and he will be able to put some clarity around those for you.

The next question is from Gil Yang with Bank of America Merrill Lynch. Please go ahead with your question.

Good afternoon. A couple of questions. Just to be clear, John, your comment that you will be internally funded by 2013, so just that sort of eliminates the need in your view with those assumptions for any equity going forward. Is that fair?

Gil, as you know, our view on equity has been and will continue to be for years and years and years, is that we will issue equity if we have a clear use of proceeds, and that is still our view of equity. Right now, there is clearly not a clear use of proceeds, and we tried to make that perfectly clear that with the Barnett we don't have the need, but I am not going to promise you that we'll never issue equity again.

There are certainly opportunities out there that we look at from time to time, and to the extent that we choose to seize on one of those opportunities and believe it is clearly accretive on a per share value, then we'll try to seize that opportunity, and if that generates a clear use of proceeds, then we will issue equity. That being said, obviously from our perspective, it is pretty clear to us what we need to be working on. We have a huge opportunity in the Marcellus and in some of the other projects like Jeff talked about, in terms of some of the things we're doing up in the Texas Panhandle, and Mississippi in-line project up in northern Oklahoma, and some of the projects we have in the Permian. We have got a huge opportunity base, and so we'll continue to do that.

We do also have a scout team that's out looking at other opportunities, and there are some exciting things they're looking at, nothing I think that's on the horizon that would qualify us to rush out and do anything. But again, I think the key and I said and I will say it again, is I think the Barnett sale does a number of things. But it really puts us in a position of strength and that we don't have to do anything in terms of that or equity, in terms of the pace we're on.

Again, that being said, if an opportunity presents itself that we think is in our shareholders' best interest, what you pay us to do is to seize that opportunity, and we'll be disciplined in terms of the balance sheet, how we raise - - to the extent that we issue equity. So, still same game plan, same theory, same strategy, nothing has changed in terms of that.

Okay. Great. Thanks for that complete answer. In terms of the commodity price forecasts for that, do you assume any ability for you to strategically lock in, as I say 525 over the next going forward beginning 2013, do you assume any ability to lock in hedges at a slight premium to that price?

Absolutely. Absolutely.

So that's sort of built into your expectation of cash flows?

No. It is not built into our expectations. I sure as hell hope it happens, though.

Just to be clear, and it is on our website the numbers John gave you for gas price, I think it was the February 3rd strip, that's what that's based on. That's the point in time that we put that slide out.

And let me tell you at least the way I look at it, and I think we look at it, is that to the extent - - we got now, in a week or so, we'll have a balance sheet where we have a bunch of cash and we have nothing outstanding on a billion and-a-half dollars credit facility, where we have the borrowing capacity to take that up to $2 billion if we choose to, and our friends at the banks, I think, are perfectly happy to do that assuming we pay them the appropriate fees. We have got enormous liquidity, so the really the leverage here is that to the extent the prices move up and we can lock them in, and we will do that, you have seen what the, quite frankly, with the little issue in Japan, we saw gas prices move up [in] 2012 and 2013, and we took advantage of that and locked in some 2013 gas I think at pretty good prices, so we'll be very opportunistic there.

So to the extent that we can lock those in, that's great and everything else, but at the end of the day if gas prices move down a little bit, we have got this balance sheet and this credit facility that we can draw down on to the extent that we need it. So again, I think it puts us in a position of strength. We have a great balance sheet.

Like Roger always says, we've worked really hard, and he has done a fantastic job of being CFO, of creating this really strong balance sheet, and to the extent that there is no use in creating it if you are never going to use it. So to the extent that we need to use it, if gas prices are a little lower than we need, then we'll take advantage of it. To the extent that it is not, then we'll be able to obviously increase our capital a little bit more or do some other things with it that we didn't anticipate either. It gives us lots of levers that we can pull, but I think the thing that's important for the shareholders is that to the extent, and I obviously talk, and Jeff and I and Roger and Rodney and the rest, we talk to a lot of shareholders, and I think one of the things that's really important is it puts real clarity into between now and 2013, and it really focuses us and management to really just get after it, drill the wells, get them on, focus, focus, focus, be disciplined, disciplined and just continue to drive it up as Jeff said.

We're looking at 25% to 30% growth next year, given what we're doing, and our team is doing a great job, and so I think they will hit the ball out of the park and if they do, then we'll hopefully exceed those numbers and proverbially kick some butt. So again, it just puts us in a position of strength, and I think it's really important and it gives clarity to all the shareholders. I think that's the other important thing.

Thanks very much. I will hop on at the end of the queue for other questions. Thanks.

Thanks.

The next question is from Mike Scialla with Stifel Nicolaus. Please go ahead with your question.

Good afternoon, guys. I think you talked in the past about drilling 2,500-foot to 3,000-foot laterals with eight frac stages, which you said is not optimal, but that's the recipe you're going to use to hold acreage, and Jeff, you talked about the results you got from this 3,500-foot lateral with twelve fracs. I am just wondering, is there any thoughts of doing a pilot where you try to get more aggressive and really optimize good development to just see what that might look like? Would that change your plans going forward, or is that not a concern right now?

Well, I'm going to take some time to answer that question. It is a good question. First of all, what we're doing this year like I said, is we're going to drill in that, call it 2,500-foot, 2,700-foot useable lateral with roughly eight stages for almost all of our wells, and what we know is to date is the average of 139 wells, primarily in or all that are on production in the southwest part of the play, the average of all of them, the good, the bad and the ugly is 5 Bcfe. In a development mode, that design well costs about $4 million, and today we're not far from that, we're at $4.1 million, $4.2 million, so we're very close to it.

So spending with that design, spending $4 million to get 5 Bcfe under, and strip pricing right now, I think the 10-year strip is somewhere $5.00 to $5.50. But if you take a $5.00 flat gas price forever at 5 Bcfe, that's a 99% rate of return. So that may or may not be optimal, but it is pretty darn good. So we're happy with that, and we know if we stay today, keep that same design and go to fewer wells per pad, we can drill more wells, we can hold more acreage and still generate really strong rates of return.

That being said, we have also done a number of experiments in the past, and we'll continue to do some going forward. And that's everything from longer laterals and more stages, to where we land the well, we think, is really important, whether you are high, low, or in the middle of the section, and that varies depending on where you are in the play, even where you are within a county, we believe. So there is a lot of different things that go into optimally developing it. And plus at this point in time in the play, early on when we started back to Range pioneering the play and carrying 100% of the science, we're not doing that anymore, and early on it was very competitive, and for different reasons companies didn't share a lot of information, as everybody was building their acreage position.

At this point in time, I think companies are more cooperative than they are competitive, so not only is it Range doing experiments, but we have other companies out there that have drilled laterals up to 9,000 feet and put a bunch of stages in them, so we can learn not only from our wells but other people, and we'll look at optimizing going forward. So where we are today is, we think we have, like John said, one of the best plays out there, even at $4.00 flat gas forever, it's a 74% rate of return at $5.00 it's 99%, and it can go beyond.

So we'll look at can we get better than where we are today, and I believe we can. We'll either get better by drilling and completing the wells better, which I think will happen, or we're really going to drive the costs down. Either of those are really significant upsides to the play.

The other thing that's I think important to look at is not only does it vary north, east, south, west, or vary within a county, I think whether you're wet or dry is important too. If you look at the liquids-rich part, which we really dominate and have a tremendous position in, and like I said, the wells are that 5 Bcfe is 3.6 B's of gas and 239,000 barrels of liquids. We did experiment in one of the wetter areas, and we have a lot of wet area to continue to drill in. And it so happens that that one well that had a 3,500-foot lateral and 12 stage frac made 6.7 Bcfe, which is 4.1 B's and 425,000 barrels of liquid. So that's a big increase going from 239 to 425 maybe by more optimally landing it or completing it, or some of those things that I've said we're going to test, maybe we can turn that into 500,000-barrels a well with the gas with the associated gas, so that would really drive economics and it really drives rate of returns, particularly where oil prices are relative to gas prices. I

f you look at our potential, John talked about, in aggregate, we have 35 to 52 Tcf of upside, we're a 4.1 Tcf Company. Out of that, 20 to 31 T's is in the Marcellus and 15 to 23 Tcf of that is in the southwest part of the play. But again, if you break it down, you're looking at 13.5 to 20.5 Tcf of gas; that's 307 million to 463 million barrels of liquids, net the range. In my mind, if you look at our performance year after year after year and we put all of our horizontal wells in there in terms of zero time plots, you can see the performance climbing with time. So I would expect the performance could continue to climb with time as we get better and better about what we're doing. So it is not unreasonable to think we'll reach the high-end of those reserves, which is at 20.5 T's just in the southwest, with 463 million barrels of liquids.

The other key part of that is that is leaving all the ethane in the gas. Once we start extracting ethanes, it's going to double our liquid yield, so the 463 million barrels becomes 926 million barrels, net the range. And then if we can get better about where we land and how we drill and complete, really you're approaching a billion barrels of liquids net the range, so we think it is really exciting upside, we have a dominant position in it, and a great team working on it. That was a really long answer, but I think it is important to look at, I think, where we were, where we are today, and where we might be going in the future.

I appreciate that. Wanted to ask you too on the upper Devonian did I hear you right, you said the gas in place is similar to the Marcellus?

Yes. If you think, and this, and predominantly we think the upper Devonian is most perspective in that west to really the southwest part of the play, it doesn't exist overall of the areas, but it does stack in the southwest part of the play. If in a particular area, the gas in place is 100 Bcfe per section in the Marcellus, the gas in place in the upper Devonian in aggregate would be about 100 Bcf, so it about doubles what you have in that area.

How does the rock quality between the two compare?

It is really early. I mean, and that's something we need to look at, and that's why I tried to put in perspective, after a couple of wells in the Marcellus, where were we, after a couple of wells in the upper Devonian where were we. We need more data, but the neat part is we know we have hydrocarbon, we know we have wet gas, we know it can produce at commercial rates even off our first two tries. It is highly unlikely that we landed it right in the optimal intervals on our first two tries.

I can give you examples in the Marcellus where right next to each other, and it is easy to take our first few tries in the Marcellus, where in a particular area we landed our first well low in the section, the second one in the middle, and the third one at the top. Progressively as we got higher, the wells got higher. I mean they went from 20 Mcf a day to about a million, and then we just moved it a little bit above the section and got 3.6 and now in the same area we're getting 10, 15; our best well was 26 million per day. And that's just moving where you land the well in a section; it has nothing to do with lateral length or frac stages, so I think the same thing will be true of upper Devonian. Understanding the rock and the quality of the rock and how to optimally land it is really important, but we're off to a better start really in the upper Devonian than we were in the Marcellus.

Great, Jeff. Thank you.

Thank you.

Our next question is from Ron Mills with Johnson Rice. Please go ahead with your question.

Hey guys, just one clarification on Utica and upper Devonian. It looks like one of your upper Devonian was more dry gas, one had liquids component. Would you expect, though, on average, the upper Devonian where you are in a more liquids portion of the Marcellus that you would also have liquids in the upper Devonian?

Yes. The wet dry area for the upper Devonian more or less should exactly or approximately mirror the Marcellus.

And you mentioned your acreage up in northwest Pennsylvania. You start testing potentially later this year with horizontal wells. Do you think at that point that, to the extent the Utica is present in northwest Pennsylvania, that you may actually bring some of the Utica into the liquids portion of the window as well?

It is possible. The difference, though, when you look at the different horizons, there is now thousands of wells that are drilled to the Marcellus and each Marcellus well has to drill through the upper Devonian because it is right on top of it. If you go down to the Utica, very few wells in the basin penetrate the Utica, so yes, it could be that a portion of that acreage is prospective for the Utica as well, and we have great Utica potential on our acreage in big reserve outside, but you're right, a lot of it is going to be dry. To the extent that stuff in the northwest works in the Utica, then it could be wet or would be wet.

Any update - - ?

One other thing I would say, too, the other neat part of where our acreage is predominantly in the southwest you can stack upper Devonian, Marcellus and Utica. If you go way to the east , you're going to lose the Utica. If you go way to the west, you lose the Marcellus and upper Devonian. There aren't like, think of [co-encentric] circles and working to line them all up. That's the one part where you can line up those plays, so a lot of our acreage in the southwest could have stacked pay potential in all three

Okay. Just any update or any more information? You had mentioned I think on one of the your latest calls that you'll test the Pennsylvania shale in the Permian. What's the timing of that, and have there been any other tests of that formation in the Permian to date?

Yes. On our Konger field area out in the Permian Basin we have about 91,000 to 92,000 net acres. We drilled a couple of vertical wells into it a few years back, and they made on the order of 15 barrels to 20 barrels of oil per day out of a vertical well, so we have a nice thick shale section that's full of oil, and we know there is oil in it because we had a couple of vertical wells [in it] on our acreage and we know it will flow oil. Not very good for a vertical well, but the question is if you drill that horizontally what will it do.

To my knowledge, there is only one well in the entire Permian Basin that's drilled horizontally into that section and it is probably 10 miles to 15 miles away from our acreage, and that well had an IP of 350 barrels per day and fell off pretty steeply. But the question is, [it is] it's first well, and it is a ways away; on our acreage we know we have a thick section full of oil. Can we make it commercial with horizontal drilling, and we've drilled in [and] cased our first well. We'll probably frac it sometime in the summer and test it and probably have results in the fall.

But we have a nice big block [HPC] position. Konger has been a great area for us. It is typical of what Range likes. It's stacked pays, it's hydrocarbon rich, hydrocarbon charged, good technical team working it, so it fits the model of things we like to work on.

Okay. And in the Mississippian line, it sounds like since you first talked about it, you have almost doubled your acreage position. You've drilled fewer wells than what operators to the west have drilled, but comparing your thoughts, or how would you compare your expectations for the play versus what the operators to the west have outlined in terms of well costs and/or EURs as you accelerate your activity there?

We have gone from 14,000 acres to 28,000 acres, and we're continuing to pick up acreage, and we'll continue to update that number. It has been a good play for us. It is a field we started redeveloping a while back, so we're looking at, we think, well cost there $2.1 million, EURs of 300,000 barrels to 500,000 barrels. 140 locations on the acreage we have and like I said, that will grow, so it's a nice play for us. To the west of us predominantly is Sand Ridge and Chesapeake, and they're having good success in the play. And IPAA, fortunately there were a lot of people that wanted to meet with us, so we were in one-on-ones and breakout rooms and such, or running around New York, so I didn't get to sit through their presentations, but from what I hear, I think they're claiming that similar range of reserves, 300,000 barrels to 500,000 barrels is I think what they're claiming. I think the well costs they're claiming are similar, but I would encourage you to ask Chesapeake and Sand Ridge. But it's a good play, and it is oil, and it has worked real well for us and we like it.

And then, if you can say anything else on the MOUs, on the ethane sales, there have been discussions not just of taking it to Sardinia, but there has also been discussions of pipeline reversals to the Gulf Coast and/or getting the ethane out to Philly, which then becomes a world commodity. These MOUs that you are going to be working towards getting agreements in place over the next coming months, I am assuming all of those different options are in the mix in terms of leveraging your position and/or ethane pricing?

Yes. When you look at kind of going up to 100,000 feet, we first looked at the play, the ethane we thought long-term was going to be a gain item in terms of just being able to ramp up our production. We put a team on it several years ago to work on this, and they have done a great job. Greg Davis and Kurt [Tipkin] and the other guys have just done a fabulous job, along with Rodney who helps and is a big player in that team as well, and where we have really gotten to is a couple of things.

One, pretty early on we made the conclusion that instead of us just working it alone, it made sense to team up with the other wet gas producers. So we've kind of [covied] up, created our own little ethane group, and so we're really, while the companies are working individually, we're also working on a collective basis so we can use our collective purchasing power, if you want to call it that, to leverage what we're doing with the users of the ethane. And I think that was really strategic and really well thought out, and that's really helped us, all of us, all the ethane producers.

The other thing that's happened is the confidence that the ethane users are starting to have that this is going to be a heck of a lot of ethane, and what relative value they have of having that ethane produced in the US, and the relative value that creates in terms of them being able to take that ethane and make the products they want to produce, that most of the products are used in the US. So to the extent that now they can buy the ethane in the US, create the projects in the US, and sell it in the US, things like transportation costs and all the other things that they had to deal with get taken off the table, so I think it is one of those things where I think they're getting more comfortable.

Clearly, the Dow Chemical press release was pretty bullish on their view of that, and I think it is just taken time for those users of the ethanes to really get their arms around how much we were going to have and whatnot in getting confidence in that what they were being told by the producers made sense and that something they could, quote, hang their hat on and whatnot. And that's part of what they're going to continue to have to get comfortable on as we go from the MOU stage to the definitive agreement stage, which is a natural progression.

But I think overall the good news is that the number of potential customers for the ethane continues to go up almost daily, and so it is a very competitive situation, and at the end of the day we'll get gas plus for the ethanes, which is something that we never thought of was going to happen two years ago. So we were hoping it was, but now it is clearly going to happen, and as Jeff mentioned, once you start stripping that out, it has a huge impact in terms of our liquids volumes, and it will have a big impact on our realizations and our margins, and it will obviously just enhance the intrinsic rate of return on the project.

Great. I appreciate the color.

The next question is from Leo Mariani with RBC Capital Markets. Please go ahead with your question.

Good afternoon here, guys. A couple questions for you on the upper Devonian. Trying to get a sense of the lateral lengths on those first couple wells and number of frac stages you guys have drilled.

Yes. They were the standard 2,500-foot effective lateral with eight stage frac, so again, it could be that there is a more optimum place to land them; I am absolutely convinced there is, and it could be that longer laterals and more stages can make a difference and we'll see with time, but encouraged by where we are so far.

Okay. And you guys made a comment you thought the second well is going to have a better EUR. That's just based on kind of what you're seeing in production history there, I imagine, and did you do something different with the second well?

Yes, the second well was constrained when we brought it on, but just looking at the production history that we have so far, it has a flatter decline, so it projects out to a higher recovery, and again we'll continue to look at those numbers with time. And it's interesting if you look at our reserves with time over the last few years, they have tended to come up with time which has been very positive, too. So we'll continue to watch and look at that. In terms of completions, they were the same, and I'll just leave it at that.

Okay. And how far apart were those first two wells that you guys drilled?

They were a long ways apart. I don't have the exact distance, but probably going to be at least on the order of five miles or more, five to eight miles, something like that.

Okay.

And we really haven't put a well into the real wet area of the upper Devonian either yet.

Okay. I guess just in terms of your acreage in southwest PA, you've got 550,000 acres there, just trying to get a sense of how much of that you think is potentially in the dry gas area?

I will use a simple cut off. If you use something like 1,000 BTU, and say anything over 1000 BTU is a plus, because we get paid for that and eventually it grades up to where it is over 1,400 BTU, so you have probably have roughly on the order of about two-thirds of the acreage would be greater than 1,000 BTUs. And again, you're looking at not just the Marcellus but the upper Devonian, so you have two horizons there, so you get two for one.

Got you.

A little bit like the Men's Wearhouse there. It is a two-fer.

All right. That's all I had. Thanks, guys.

Thank you.

We're nearing the end of today's conference. We will go to Dan McSpirit from BMO Capital Markets for our last question.

Gentlemen, good afternoon.

Hello, Dan.

Roger spoke about exploration expense at the top of the call and it being driven by higher seismic expense in the period. Where was that seismic shot, mostly?

Most of the seismic is in the Marcellus. We have acquired seismic now, either through group chutes or spec chutes over almost everything we have or we will have by the end of the year up in the northeast, but we're also acquiring a lot of seismic in the southwest. We started drilling early on without 3-D and clearly you can do that, but like I said, the more we shoot 3-D there is a lot you can get out of it, and you can apply it not only to the Marcellus but you can apply it to the upper Devonian and to the Utica, more optimally placing the wells and understanding the better areas, and things we can see from seismic we think will really help to continue to drive our well results up. But it's Marcellus.

Okay, great. And the second question here if we could return to the St. Louis well, what is it about that well that the rates are still strong after 12 weeks of production? Is it more about the rock, the completion technique here, and are you getting contribution from another horizon maybe?

No, it's just a really high quality rock. It's a really interesting play. When you look at that off of conventional well logs, you can't really see it, it's a play that people have drilled through for years. And it's interesting, you think a lot of those, call it bypassed or missed play type things, tend to be low quality rock that either needs better technology or something to make it work. In this case, it was recognition that the interval was productive, and then once you see it, then you can take that concept and expand off of it.

But basically it is you've got a really highly permeable rock and a lot of it, so you have a lot of KH, and then when you put a horizontal well on it you have a lot of KH, so even though the initial rate was a little over 13 million per day and over 900 barrels of liquids per day, that was with about 10% draw down. So we were making 19 million per day with about 10% draw down, so as we continue to produce it, you are only taking 10% of the productive capacity of the well to get that rate, so you can produce at a flat rate for a relatively long period of time.

Okay. Do you have the name of that well handy by chance?

No, because all of our competitors are also on the phone. I am sure they're already looking at all state records and everything to figure it out and then to try to figure out - - because we're continuing to lease as well, and we're picking up leases up there for that kind of potential.

I understand. And then if we could, one last question here return to the ethane sale agreements here, recognizing that you have a CA in place and that you're limited in what it is you can relay to us. But if you could take a step back here and just give some context on what gave rise to the contemplated agreements, and that is how did the option originate, and what's the precedent for the agreement?

I guess I am not following you, Dan. Can you be a little bit more specific? What do you mean in terms of precedent?

What is this agreement based on? Is there an industry agreement out there that you are basing the terms of your agreement with Dow or another company on?

All our agreements will be simple purchase agreements for ethane that you would typically have anywhere along the Gulf Coast or another kind of product. The challenge is we're the producer, they're the end-user.

Right.

How are we going to get the ethanes to them. That is going to have multiple ways in which you could solve that problem. We can deliver to Dow under two or three different arrangements. Obviously, you would have a cost impact as to which one you use. So we'll work with Dow to figure out which way to get them their ethanes at the lowest price of transportation to them, but what is happening is, as John was speaking about, as there is more confidence that there really are ethanes here, and you have a global economy that's using naphtha, now you have this huge push of how do I get [off the] naphtha and get the ethane. So I think what you see is this global movement to the cheapest feed stock that you can, and you'll do all the ethane that you can and then you'll start doing propanes to get off the naphtha, so we have a huge source of customers that become much more familiar with what we have to offer.

Range's benefit is that we actually now have so many competing offers that the ethane price that we will realize keeps going up, so therefore as Greg Davis told me this morning, our biggest negotiating factor has been in the last year is simply saying no, and you get more offers at better prices. So we're just having to methodically go through there, because again, all the infrastructure will need to come through, and it will have implications as to where the ethanes will be going for the next ten or fifteen years, so it is a big, huge opportunity for us. We're going to maximize that, but some of the unknown ability that people don't appreciate is that once you put the fractionator in and we're actually fractionating and taking the ethanes out, we'll have 12% greater recovery on the propanes. And that's going to add to our propane margins simply because of now trying to fractionate and get propanes because of the quality in which we have to deliver the propanes, we are not fully extracting all the propanes.

Got it.

We'll get another 12% recovery on propanes once we extract the ethanes. It is a plus, plus, plus, and the story continues to get better as you look at all the alternatives and you've got a global demand for this product.

Right. Right, and in any of these agreements do you expect to be held to any minimum delivery volume or other such commitment?

You will probably have a minimum delivery that you would have under any agreement, but we will also provide for swing volumes over that minimum agreement so to be able to work that effectively.

Got it. Thank you again.

Thank you. This concludes today's question and answer session. I would like to turn the call back over to Mr. Pinkerton for his concluding remarks.

I know we have gone over a little bit so we apologize for that, but we really wanted to take as many questions as we could. To the extent that you did push the buttons and lined up and weren't able to get through the queue here, I apologize, but Jeff and I and Roger and Rodney and the team will be around the rest of this week, so feel free to call us and we'll be happy to answer any questions, or try to answer any questions that you may have. We really appreciate everybody being on the call.

Kind of summarizing, I think the first quarter was an exceptional quarter for us, a 17% increase in production volumes and during terrible winter season, some of the worst that I have ever seen, and a 17% increase in per share production, which is what, quite frankly, all I care about, is what we do on a per share basis, I think is exceptional. I think again on the cost side, we're continuing to beat that and focus on it every day. As I mentioned in my call notes, our decision is to sell the Barnett, and I had a couple of people say you have to be crazy, but I think it was bold, but I think it was an appropriate move, I mean, clearly from the opportunity we have in the Marcellus. And what drove that decision is the Marcellus is getting better, the upper Devonian is getting better, the Utica is starting to - - that bloom is starting to open, and clearly our success in the Mississippian play, line play up in northern Oklahoma, is encouraging, the St. Louis play that we have got is clearly - - that's the best well this Company has ever drilled. That's fantastic. We have some opportunities to expand that play.

The upside from the Pennsylvania project out in the Konger clearly has a lot of risk to it, but that's just a question I think our guys over time will figure - - unlike that, and then we didn't even talk about Nora and some of the horizontal drilling in the [Berea and the [Heron] there. Nora continues to be one of my favorite fields. So the decision to sell the Barnett was really from a position of strength in terms of the drilling portfolio and also creates a position from strength from a balance sheet perspective. So I think again, I think that sale is huge for our Company.

And when you look at Range today post that, compared to where we were five years ago, it is just amazing to see the transformation of the Company, but [it] all comes down to the quality of people that we have that are doing it every day. So it is really I think a testimony to the entire Range team, and like I said, we are extraordinarily excited and extraordinarily motivated. This Company has enormous value, as Jeff just went through some of the liquids issues, in terms of where the liquids component is in this Company.

We have an extraordinary opportunity, and the thing I can assure all our shareholders, we are focused 150% of our efforts to ensure that existing shareholders get every bit of that value that we can possibly squeeze out of this onion. So that's what we're focused on, and again, we look forward to reporting our second and third and fourth quarter results, and it is a really exciting time for us, and we appreciate your continued support, and we'll see you either on the road or on the second quarter call. So thank you very much.

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