山脈資源 (RRC) 2010 Q2 法說會逐字稿

Welcome to the Range Resources second quarter 2010 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 fact 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 statement. 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, Sr. Vice President of Range Resources. Please go ahead, sir.

Thank you, Operator. Good morning and welcome. Range reported results for the second quarter of 2010 with record production, and reduction in our unit costs in most of the major cost categories. Second quarter marked our 30th consecutive quarter of sequential record production growth. As our operations continue to become more efficient, we are able to spend capital more efficiently and realize greater returns. Range is committed to maximizing per share growth values as we grow the Company. I think you'll hear the same themes 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'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's now available on the home page of our website or you can access it using the SEC's Edgar system. In addition, we've posted on our website supplemental tables which will guide you in the calculation of 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. We've also added tables which will guide you in forecasting our future realized prices for natural gas, crude oil, and natural gas liquids. Detailed information of our current hedge position by quarter is also available on the website.

Second, we'll be participating in several conferences in August. Check out our website for a complete listing for the next several months. We will be at Tudor Pickering's Energy Conference on August the 12th, (inaudible) Brother's Energy Conference in New York on August the 18th, and the Entercom 15th Annual Oil and Gas conference in Denver on August the 23rd. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the second quarter financial results, I'll take a little time to review the key second quarter accomplishments. On a year-over-year basis, second quarter production rose 9% materially beating the high end of our guidance. If we adjust for the asset sales, first quarter production growth would have been about 13%, 14%. This marks the 30th consecutive quarter sequential production growth, as Rodney mentioned, and obviously a great milestone for our Company. After closing the Ohio sale right at the end of March and losing roughly 25 men a day of production, our analysis indicated we would not overcome the entire Ohio loss in the second quarter and therefore this would snap our consecutive record of production growth. However, our operating teams proved the analysis wrong and made it happen and our growth record continues which I'm ecstatic about. It was truly a team effort with all of our divisions contributing. The Marcellus division was the largest contributor. They continue to drive up production by drilling just some outstanding wells.

The 9% increase in production was more than offset by an 18% decrease in realized prices. As a result, second quarter natural gas NGL and oil revenues were 11% lower than the prior year period. We are most pleased on the cost side. On a per unit of production basis, three out of the four of our major cost categories were lower than the prior period. Direct operating costs came in at $0.68 per MCFE, that's 21% lower than the prior year period. DD&A expense, per MCFE, came in 6% lower than last year, while interest expense per unit saw a 4% decrease. G&A saw a $0.07 increase over the last year. As you all know we are still building out the Marcellus team and we will continue to see the impact for another couple of quarters or so before we begin to see a decline in a unit of production basis with regard to G&A.

With regard to the Marcellus shale play, we continued to make significant headway during the quarter as we drill some fantastic wells, filling our acreage position, test other shale formations both above and below the Marcellus, and continue to build out our infrastructure. As I previously noted, we continue to add to our high quality technical team in Pittsburgh which now totals roughly 220 people.

Right at the end of the first quarter we completed the initial closing of our Ohio asset sale which generated $300 million of proceeds. The sale included roughly 3,300 wells and over 13,000 leases. In June, we completed the second final closing for $23 million. In total we recorded a $79 million book gain. We placed the sales proceeds in a 1031 exchange account with the hope of deferring all or some of the tax gain. We were very fortunate to find a terrific use for a portion of the 1031 exchange account. Late in the second quarter we closed on a modest property purchase whereby we acquired Chesapeake's properties in the Nora/Haysi area of Virginia for $135 million. We are pretty excited about the acquisition. It literally fits hand in glove with our other Virginia properties. The transaction is NAV per share acretive and we see substantial upside in the properties. Jeff will go into more detail as to the specifics of the properties we acquired.

All in all I couldn't be more pleased on how much we accomplished in the second quarter. It was a real testimony for the entire Range team. With that I'll turn the call over to Roger to review the financial results.

Thanks, John. The second quarter of 2010 has shaped up to be a bit of a sequel to the first quarter this year. Production against all odds and asset sales hit a new record high and we completed the sale of our Ohio tight sand gas properties.

Also like last quarter, direct operating costs were again reduced on both an absolute and unit cost basis. Natural gas, NGL and oil sales for the second quarter, including cash settled derivatives, totaled $217 million, down 11% from last year. A 9% increase in quarterly production over last year could not overcome the 18% decline in realized prices. Year to date, natural gas, NGL and oil revenue, including cash settled derivatives, totaled $450 million. Cash flow for the second quarter was $129 million, 17% below last year. Cash flow per share for the quarter is $0.82 , $0.01 below the analyst consensus estimates of $0.83. The lower realized prices caused that $0.01 variance. Year to date cash flow totaled $277 million. EBITDAX for the second quarter is $156 million, 16% lower than the second quarter of last year. EBITDAX for the year to date period is $332 million.

Even though cash expenses were 6% less than the second quarter of last year, an 18% lower realized MCFE price reduced our cash margins to $2.92 per MCFE in the second quarter. In order to better equip analysts and our investors to make estimates of our natural gas, NGL and oil price realizations, as Rodney mentioned, his team has done a great job and they put three new financial guidance tables, those appear as tabs 6, 7 and 8, out there on the website under the quarterly supplemental financial tables section of our financial information portion of the website. So please feel free to contact Rodney or me with any questions you have about these new tables.

Also, like the first quarter of this year, we had a few out of the ordinary revenue and expense items worthy of mention. We completed a second closing associated with the sale of the Ohio tight gas sand properties netting a pretax gain on sale of $10 million. Non-cash mark to market derivative losses for the second quarter came in at $12.4 million and our deferred compensation plan posted non-cash income of $14.1 million reflecting the mark to market valuation adjustment of stock held in the plan. Quarterly earnings calculated using analyst methodology for the second quarter, and that excludes non-recurring items such as asset sales and unrealized derivative mark to market entries, that was $14.1 million or $0.09 per fully diluted share. That's $0.02 less than the analyst consensus estimate of $0.11 a share. And like cash flow, the $0.02 variance from analyst consensus earnings was due to lower realized prices. Please reference the Range Resources website for a full reconciliation of these non-GAAP measures including cash flow, EBITDAX, cash margins and analyst earnings.

And while the second quarter financial performance was dragged down a bit by lower gas prices, our operating performance was, again, very strong. Second quarter cash direct operating expense including workovers is $0.68 in MCFE. That's down $0.05 from the first quarter this year and down $0.18 or 21% from last year. Looking back two years, second quarter direct operating expense is down $0.37 from the second quarter of 2008. That's a 35% reduction in this critical cost metric over just the past two years. It's one thing to ride the unit cost curve down as your production ramps up but in the case of direct operating costs, it's really worth noting that over the past two years direct operating cost has not only declined on a unit cost basis but on an absolute basis as well.

In the second quarter of 2008, our direct operating cost was $36.5 million on average daily production of 381 million cubic feet equivalence. In the second quarter of 2010, direct operating cost is $29.1 million, on average daily production of 472 million cubic feet equivalence. So, even though direct operating expense is largely a production dependent variable cost, costs are down 20% while production is up 24%. Paired with our improving capital efficiency, this cost comparison illustrates the benefit of continually hy grading our assets in drilling inventory which has the added benefit of positioning Range well for the current period of low natural gas prices. Looking forward to the rest of 2010, we expect direct operating costs to decline further into the low $0.60 Range.

Production taxes for the second quarter are flat with the second quarter of last year and also flat with the first quarter of this year at $0.19 an MCFE. General and administrative expense, adjusted for non-cash stock comp, but including non-recurring legal expenses is $0.58 per MCFE for the second quarter of 2010, that's up $0.07 from the second quarter of last year. This increase stems primarily from $2.6 million in legal expenses, and those were incurred to successfully defend one suit and successfully settle two other legal claims. This type of G&A expense is difficult to predict but the elimination of this type of uncertainty on favorable terms is always a good thing. For the rest of 2010, we anticipate G&A expense to remain steady for the second quarter as we continue to staff up the Marcellus shale division.

Interest expense for the second quarter of 2010 is $0.72 an MCFE and that's flat with the first quarter of this year, $0.03 lower than the second quarter of last year. Interest expense should remain relatively flat for the third quarter as we deploy the remaining idle cash proceeds from the Ohio asset sale. Exploration expense for the second quarter of 2010, excluding non-cash stock comp, came in at $13.4 million, that's dead even with the first quarter, $3 million higher than the second quarter of last year. The main reason for this increase over last year is higher delay rental payments. Quarterly expiration expense, excluding non-cash comp, should fall in the $16 million to $18 million slot during the third quarter as delay rentals declined but seismic expenditures are expected to increase.

Depletion, depreciation and amortization per MCFE for the second quarter of 2010 is $2.12 compared to $2.25 last year. For all of 2009, our DD&A rate was $3.34 per MCFE -- $2.34 per MCFE, excuse me. Just as declining direct operating costs signals improving operating efficiency, declining DD&A rates signal improving capital efficiency as we see the benefits of high grading our assets and drilling inventory. Looking forward to the remainder of 2010, we expect to see the DD&A rate continue to fall as better drilling results and better well performance manifest themselves in even lower DD&A rates. The DD&A rate is expected to drop another $0.07 to $0.10 in the third quarter and decline toward to the $2 mark by year end.

Abandonment and impairment of unproved properties for the second quarter was $13.5 million. That is a $27.5 million reduction from the second quarter of 2009. And while this non-cash expense fluctuates, we are beginning to see this expense normalize a bit in 2010 compared to last year. Unproved abandonment and impairment for the third quarter of this year is anticipated to be between $20 million and $22 million. That reflects lower natural gas prices and the continued shift in our capital allocation among our drilling opportunities, which, of course, impacts unproved property carrying values.

All of our $6.5 million in federal income tax liability for the second quarter is deferred, and we continue to hold a $322 million NOL carry forward to help shield future taxable income. Our effective tax rate the rest of the year is anticipated to be 39% with all cash federal tax payments deferred. Investors may have noticed that we successfully deployed, as John mentioned, $139 million of the Ohio asset sales proceeds that we had placed in a like-kind exchange account, to the Virginia acquisition. In addition to the benefits Jeff will speak of shortly, this core area acquisition allows us to defer approximately half of the taxable gain from the Ohio asset sale on an acquisition that is highly acretive in its own right. The remaining exchange account cash is earmarked for budgeted 2010 acreage transactions in specifically selected areas but is also completely unrestricted. So, if the acreage is unavailable, we may move the funds out of the account any time we choose.

For the remainder of 2010, Range has approximately 75% of its gas production hedged with collars at a floor price of $5.56 per MMBTU and a cap of $7.20 per MMBTU. We have increased our 2011 hedge position as our increased guidance reduced our percentage hedge from 51% to 48%, we have added hedges and now have 61% of our anticipated 2011 gas production hedged with collars at a floor price of $5.57 per MMBTU and a ceiling price of $6.54 per MMBTU. In addition to adding to our 2011 hedge position, we have commenced hedging 2012 volumes with 60 million cubic feet per day of natural gas hedged with collars at $5.50 by $6.25.

On the oil side we have 1,000 barrels per day hedged in 2010 using collars at $75 a barrel by $93.75 and we have 5,200 barrels a day hedged in 2011 with a collar of $70 by $90. Lastly we've added 2,000 barrels of 2012 oil volume hedged at $70 by $80 in a collar.

The balance sheet remains in great shape. Our debt to cap ratio, net of the cash in the 1031 is right at 40%. We expect this to drift up a bit slightly during the remainder of the year as we increase our spending, but we remain committed to maintaining the strong balance sheet.

To summarize, the second quarter of 2010 continued to demonstrate a very strong and resilient operating performance. Production loss from asset sales was fully replaced through drilling, operating costs continue to decline on both an absolute and unit cost basis, and the DD&A rate is dropping reflecting higher capital productivity. We believe that these are exactly the things an ENP Company should be doing in the face of low prices. So, we enter the second half of the year with our big 2010 asset sale done, the balance sheet in great shape, the majority of our 2010 and 2011 production favorably hedged plus adding our first 2012 hedges, but most important of all we have a highly focused team of employee-owners that are dedicated to increasing net asset value per share and bringing it forward as prudently and rapidly as possible. John, that's it for

Thanks, Roger. Terrific update. I will now turn the call over to Jeff to review our operations.

Thanks, John. I'll start the operations update with the Marcellus Shale. As we get more production data from our horizontal wells, the high quality nature of the wells is being confirmed. Our midyear estimate for all of our horizontal wells that are online averages 5 BCFE per well. Updates of our zero time slots have been posted on our website in the current Company presentation. The 5 BCFE average is based on 95 horizontal wells that all have greater than 30 days of production and they're all in the southwest part of the play. Our estimate of reserves per well for our acreage has been 4 to 5 BCFE. To date, we are clearly at the high end of that range.

In the southwest part of the play, given our current average lateral length of 3,050 feet with 10 frac stages, our completed well cost is about $4 million. The rate of return for our wells in southwest Pennsylvania, which is in the wet gas area, assuming that we spend $4 million to get 5 BCFE and that the gas price is $4 per MCF flat forever, is 60%. At $5 flat forever, the rate of return is 79% and at $6 flat it increases to 100%. I believe that this is one of the highest, if not the highest rate of return gas play in the United States. Again, the qualifiers that we are drilling in the core portion of the wet gas area of the play in the southwest Pennsylvania. By far Range has the dominant position in this area.

The build out of the infrastructure continues on plan. We currently expect crowd capacity will be increased by MarkWest from 155 million per day today to 350 million per day by the second quarter of 2011, and then up to 390 million per day by the third quarter of 2011. Dry gas gathering and compression capacity in the southwest is planned to be increased from 20 million per day today to 65 million per day by late 2010, then up to 100 million per day by late 2011. Dry gas gathering and compression capacity in the northeast through our PVR contract is on track to come online late this year and should be 120 million per day by late 2011. In aggregate by late 2011, we have firm plans that will give us infrastructure capacity of 610 million per day. This is well in excess of our stated target exit rate for 2011, so we are in great shape.

We are currently running 13 drilling riggs in the Marcellus play. Six of the rigs are the larger rigs which drill the horizontal portion of the wells with mud and the other seven rigs are smaller rigs which drill the vertical portion of the hole with air. The drilling team continues to get more efficient and, as a result, these rigs will drill 18 more wells than what was initially planned for 2010. Keeping all of these rigs working and drilling these 18 additional wells will result in our capital budget being increased by $31 million. As a result of having drilled more wells, we plan on completing 15 of these additional 18 wells prior to year end.

Some of these wells will not come online until 2011. That additional completion cost adds another $34 million to our 2010 budget. Given the strong rate of return of this project and our extensive land position, we believe that this accelerated drilling and completion is the right thing to do even at today's gas price. We also believe that we should fast forward some of the cost of our 2011 drilling into 2010. We will prebuild some of our 2011 drilling location, roads and infrastructure in 2010. Combined, this will increase our 2010 budget by $73 million. The total cost of this project is the same. But this accelerated drilling allows us to accelerate production.

Finally, we will be adding $40 million to our budget in 2010 for land, and $7 million for seismic. This land will all be in the core area where the chance of success for drilling is essentially 100%. Again, given the strong economics and low risk we believe that this is the right thing to do for our shareholders. The seismic helps to further define the 2011 drilling program. One other way that we are fast forwarding our Marcellus program, is that we are combining about 14,000 net acres in Eastern Bradford county with Talisman's acreage there. Talisman will operate and we'll have about a 33% working interest in this industry joint venture. Talisman has done a good job of operating here and has a dominant acreage position in this area. Combining with them will allow us to more efficiently develop this part of the play utilizing their technical team and their drilling rigs. We're estimating that this joint venture adds $25 million to our 2010 capital spending. In total, we will be adding $210 million in the Marcellus to our capital budget for 2010, all of which is for faster, more efficient development of our Marcellus acreage position. 80% of the Company's 2010 budget is now targeted for the Marcellus. I want to make it clear that, even at today's gas price, the returns on the additional capital are very attractive.

Given the increased capital, we are revising our 2010 Marcellus exit rate from $180 million to $200 million per day net to $200 million to $210 per day net. We're also revising our expected 2011 Marcellus exit rate from $360 million to $400 million per day net to $400 million to $420 million per day net. We have a first class team of 220 people located in Pennsylvania focused on this project. In addition, we now have a focused very experienced and talented Barnett team on this project as well. Given our team, our acreage and the infrastructure we have in place or in the works, we are well positioned to meet or exceed our plans for the Marcellus.

We have also drilled and tested one horizontal upper Devonian well and one horizontal Utica well in Pennsylvania. This is the first horizontal Utica well in the entire Appalachian basin, and the first horizontal upper Devonian shale well in Pennsylvania. Both wells successfully tested gas and we are encouraged by the results. However, we plan to keep the results confidential for a while due to competitive reasons.

Before I move on to the next topic, I want to take a few minutes and focus on our progress in the Marcellus play. Let me compare where we were one year ago with where we are today. This time last year we were producing about 50 million per day net. Today we are producing about 160 million per day net. We have organically grown production by 110 million net over the last 12 months.

A year ago during the second quarter call, I stated that our average development well in the southwest part of the play cost $3.5 million to drill and complete, and our average well, based on 24 wells at that time with adequate production history, was projected to recover 4.4 BCFE. At $5 flat gas price forever, that generated a 50% rate of return. Today our costs to drill and complete is $4 million, given we are now drilling laterals that are about 3,050 feet versus 2500 feet last year. In addition, we are now completing the wells with ten stage fracs versus eight a year ago. Today, our average wells reserves are projected to be 5 BCFE based on 95 horizontal wells. Spending $4 million to recover 5 BCFE and assuming a $5 flat gas prices generates a 79% rate of return versus the 50% rate of return we projected at this time last year. Not only have we driven up net production substantially, we have done it in a much more cost effective way which results in stronger economics and a much higher rate of return.

Last year at this time we estimated that our 900,000 acres in the fairway had a resource potential of 15 to 22 TCFE net from the Marcellus. Today we are estimating that our 900,000 acres has resource of 20 to 27 TCFE net. Importantly, given the successful drilling by Range and other companies across the play, the probability of this acreage being prospective is significantly higher today than it was at this time last year. In fact, we believe all of this acreage is highly perspective. Last year we were just talking about the upside of the upper Devonian and Utica shales on our acreage. Today we have successfully drilled and completed one well in each formation.

Finally, we have focused our Marcellus team and Barnett teams on fast forwarding this development. In addition, we are teaming up with Talisman on some of the acreage we have in Bradford County. All of this will result in pulling forward the net present value of this project. MarkWest is doing a great job of building out the infrastructure in the southwest and has made great progress over the last year.

At this time last year we had not drilled in the northeast. Since then we have completed two horizontal wells in Lycoming County for rates of 13.6 million and 13.3 million per day. Last year we had no infrastructure in place to produce these wells and develop this area. Since then, we have an agreement in place with PVR and we're well on our way to bring production on line by the end of this year and to ramp up development there next year.

I am extremely pleased with the accomplishments of our team and the industry partners we are working with. Last year, I believe that we had the potential to possibly reach 2 BCFE per day of net production in the Marcellus. Today I believe the production upside could reach beyond that and could possibly approach 3 BCFE per day net. Range is in a very enviable position.

I have been in the business for 31 years and have worked all over the US and the world. During the last 31 years, I have only seen very few, extremely few companies who have organicaIly grown production in the US from zero in a particular play to a net rate of 2 to 3 BCFE per day. Again, I am talking about growing production through drilling only, not through acquisitions. Arco's interest in Prudhoe Bay is the best example I can think of. Arco discovered Prudhoe Bay and the peak production from the field was 1.5 million barrels per day, or 9 BCFE per day. Arco's net production at the peak I believe was about 2.7 BCFE per day. So organically, they grew to approximately 2.7 BCFE per day.

The only other example I can think of is Southwestern in the Fayetteville. They discovered the field and to date, have grown production from zero to about 1 BCF per day net and my understanding is that they expect to peak at about 2 BCF per day net. Range discovered the Marcellus like Arco Prudhoe Bay and Southwestern discovered the Fayetteville. Range, like both of those companies, has the potential to grow to 2 BCFE per day net and perhaps beyond. That is pretty exciting stuff.

One other project I want to discuss today is our acquisition of additional properties in Virginia. These properties are a great fit with our existing Nora/Haysi properties in Virginia. In fact, a portion of this acquisition directly overlaps with our Nora/Haysi area. In Haysi, we currently operate and have a 70% working interest in the CBM and only a royalty on the rest of the formations which are the tight gas sands in the Huron shale. This acquisition will give us a 100% working interest and a 100% net revenue on all of the Haysi pays. As good as the Nora and CBM has been economically, the tight gas sands are even better. We have included a new graph on our website that shows the rate of return of the Nora tight gas sands versus the CBM. For a $5 flat NYMEX forever, the rate of return for a tight gas sand well is 40% and for $6 flat forever, it increases to 56%. That's for an average Nora well which is drilled on 112-acre spacing and averages about 450 million cubic feet of gas per well. The Haysi wells that we're acquiring are even better than the Nora wells. The Haysi wells average about 550 million per day and are drilled on an average spacing of 224 acres to date. There are clearly a lot of very low risk drilling opportunities with great economics in this area and we have a very talented and accomplished team who can efficiently and effectively develop the properties, and we are pleased to have the opportunity to add to our holdings here.

In addition to the Haysi properties, this block of acreage extends to the north/northeast. All told, it's about 115,000 acres, and we believe that this acreage contains a resource potential of appoximately 800 BCF net. In essence, the acreage is surrounded by production in all directions and is in the center of a very large gas accumulation. The acreage that we acquired is prospective for all horizons including the Huron shale, which has only had very limited vertical development here. In the other traditional horizons, the wells are drilled on about double the spacing of surrounding fields. We believe that there is a lot of low risk strong economic wells to drill. In addition to the acquisition capital, we will be spending about $5 million on these properties in the second half of 2010. We have included in our updated Company presentation a map showing the new acreage in the surrounding wells.

At Range our strategy is to grow production with one of the best all-in cost structures in the business and to build and high grade our inventory. In addition to adding high quality plays, like the Marcellus, Nora and the Barnett to our portfolio, we have sold out of the Gulf of Mexico, Ohio, New York, Fuhrman Mascho and other fields. The net result is shown on our website in our latest IR presentation. Since 2007, we have decreased our well count by 50% while increasing our production by 52%. Bottom line, we are a much more efficient Company. The combination of adding higher quality plays and focusing our people and capital there, while selling relatively high cost, low growth areas has led to better production and reserve replacement, lower F&D, lower LOE and better rates of return. This, in addition to our resource potential which is 10 times our current reserve base, coupled with one of the best teams in the business, will lead to an exciting future for Range. Back to you, John.

Thanks, Jeff. Terrific update. Before we look to the remainder 2010, I will spend a few minutes just summarizing what we've accomplished so far in the first half of the year. As we discussed, production in the first half exceeded expectations due to better than expected drilling results. And due to these results and the small Virginia acquisition, we are increasing our production guidance for the year from 12% to 14%, and this does include the impact of the asset sales.

On the cost side, we continue to drive down our unit cost, in particular the reduction in direct operating costs and DD&A are particularly encouraging. The good news is that these are not one time events. We expect unit costs to continue and decline in the quarters ahead. Another significant accomplishment was completing the Ohio sale early in the year when gas prices were higher and importantly by completing the initial closing in the first quarter, we were able to lock down our drilling plans for the year.

Next the Virginia acquisition we completed in June, couldn't have come along at a better time. We are excited about the potential of the properties as Jeff has mentioned. Acquiring the properties at good price and using the 1031 account proceeds was a home run. As I've said many times, I love the Nora area. It's our Energizer bunny, in that it keeps on going and going, and gets better and better.

The most significant achievement in the first half of 2010 is clearly the progress we continue to make in the Marcellus shale play. As Jeff mentioned, our well performance continues to improve. Our returns continue to improve. The infrastructure build-out is right on track. The quality and depth of field service partners continues to improve and the regulatory environment is becoming more predictable.

While we haven't said much about the other formations due to competitive reasons, we made progress identifying and quantifying the potential of the other formations and are extremely excited about their potential. Bottom line is that we are even more convinced today versus at the beginning of the year that we have found a giant gas field that generates very attractive returns at very low natural gas prices. Importantly, we have accumulated an extremely large attractively located acreage position in the play. Every month more and more of our acreage is being derisked and we really like what we see.

Lastly, given the most that our capital spending in 2010 is focused in the Marcellus shale play, the results there will drive our production reserve results for the year. Due to the excellent drilling in the first half of the year in the Virginia acquisition, as I noted before, we have increased our production guidance. With regard to reserves, we currently believe we are on track to record an all-in finding development cost of less than $1 per MCFE for 2010. This will be the first time in our history to go below $1. This is key as it clearly indicates the quality of the Marcellus and its superior economics.

Looking to the remainder of 2010, we see continued strong operating results. For the third quarter, we are looking for production to average 495 million to 500 million a day, representing a 14% increase year-over-year. The third quarter production will reflect the sale of both the New York properties we sold last December and the New York properties we sold in March of this year, so the 14% third quarter target equates to 19% after adjusting for the asset sales.

Now that we have closed the Ohio property sale, I'll take a moment to look at the impact of our divestiture program. Over the past years, we've reduced our well count by roughly 6,000 wells. As Jeff mentioned, this represents 50% of our well count but it only represents approximately 9% of our production reserves. The properties we sold were more mature, higher cost properties. The good news is that while we were selling our more mature higher cost properties, we were refocusing our capital in our high return projects like the Marcellus, the Nora area and the Barnett shale. As a result, despite the asset sales, our production reserves continued to increase rapidly.

Over the same three-year period where you have seen our well count decline 50%, our production has risen by over 50%. As a result, Range is a much more efficient Company. We like to say we are doing more with less. By less, we mean less wells, lower finding and development costs, lower operating costs and lower year end costs per MCF. We believe this is critical in a low price environment.

Turning to the topic of joint ventures, we are often asked about the various joint ventures that other companies have completed and what our current thoughts are. While we prefer not to complicate our operations in the way we do business, we continue to have discussions internally and with third parties regarding joint ventures. I think it's important to differentiate between the industry joint ventures versus what we call the large financial joint ventures. Industry joint ventures are JVs where two companies in the industry pool their acreage primarily for efficiency reasons and to jointly share the risk of developing the combined acreage position. Financial JVs are where one Company contributes the land and the second Company contributes money to help defray the cost of development. So far nearly all the joint ventures associated with the shale plays have been the large financial joint ventures.

Due to our drilling results and other industry wells, a substantial portion of our acreage has been derisked in the Marcellus. Because of the reduced risk of our acreage, we can reasonably model our acreage from an NAV per share basis. Bottom line, if we receive an offer that is NAV acretive, we will seriously pursue it. As Jeff mentioned, we believe that our Marcellus acreage could result in production one day of potentially 2 to 3 BCF per day. Assuming we entered into a large financial joint venture, where we gave up a third of our acreage, we would be giving up a third of the production or roughly 700 million to nearly 1 BCF per day. While I want to make clear this is a very simplified analysis, one can readily see that we should be extremely careful when considering the NAV per share impact of any large financial JV. That being said, at Range we focus on NAV per share. I believe we've demonstrated this over the years in a disciplined way.

I'll now take a moment to discuss the regulatory environment in the Marcellus play. While challenging, the regulatory environment has improved in many ways over the past two years. First, the drilling permit process in Pennsylvania has gotten much more predictable and we are regularly receiving permits in 30 days or less. Second, the water access and flow back process is much more redistrictable, especially given that Range is recycling 100% of its flow back water in the southwest portion of the play. The Pennsylvania DEP is very supportive of our recycling program. It's not only a better environmental solution, but it also saves us money.

With regard to a severance tax in Pennsylvania, the good news is, is that the state has not yet enacted a tax. During the past several years, we and the rest of the industry have worked hard to educate and work with the Pennsylvania legislature about the issues surrounding the severance tax, encouraging them to take a holistic approach, whereby any severance tax would come with a balanced regulatory monetization Recently the Pennsylvania legislature announced that it would work towards a severance tax proposal calling for enactment on or before October 1, 2010, and effective January 1, 2011. We are continuing to closely monitor the situation and believe a holistic balanced approach will likely result.

There has also been much discussion pro and con about hydraulic fracturing. As we discussed this issue with many people in Pennsylvania, the clear message we received was that there was a great desire to know more about the makeup of our fracking fluid. As a result, we have spent several months working with our service partners that we could disclose the content of our fracking fluid. On July 14, we announced a voluntarily disclosure initiative regarding the Marcellus shale fracking fluid. We announced that we will submit to the Pennsylvania DEP additional information about the content of the fluid on a well by well basis and also post the information on our website. We also announced that the current frac fluid mixture contains 99.86% water and sand with the remaining 0.014% being chemical additives. Of the additives, 0.04% are considered hazardous in a concentrated form according to the federal regulatory classification and like most common household chemical substances, in a diluted form, pose no harm.

Our objective with this initiative is to continue Range's philosophy of transparency and to provide all the citizens of Pennsylvania an accurate record of our frac fluid content and put their concerns at ease. Our recent survey data indicates that a great majority of the citizens of Pennsylvania support Marcellus drilling. We felt that our voluntary disclosure initiative was simply the right thing to do. We have received very positive feedback from nearly everyone regarding our initiative including regulatory, environmental, legislature, landowners and other Marcellus operators and the general public as a whole. We are hopeful that other Marcellus operators will follow suit but we understand it will take them a while to work through the disclosure issues with their service companies.

We are absolutely convinced that the Marcellus can be developed in a way that is safe and environmentally sensitive for the benefit of everybody. We don't believe it's an either/or situation. By developing low cost clean burning natural gas in a safe and environmentally sensitive way, everybody wins. In the weeks and months ahead we will be coming out with initiatives towards better educating Pennsylvanians about how we go about developing natural gas in Marcellus in a safe and environmentally sensitive way. We have been working on this broader initiative for some time and look forward to rolling it out. With it, we would be taking a proactive position with the goal of beginning to dispel many of the nonfactual statements that others have made. Our number one goal is to simply educate. We believe that the Marcellus shale play and natural gas is a great opportunity and once more and more people understand and better understand the issues, they will embrace the safe and environmentally sensitive development.

Finally, I'll take a few minutes to discuss capital expenditures and funding. As Jeff discussed, Range is in an enviable position. As we believe we can now grow the Marcellus production from 160 million a day net, where we are today, to 3 BCF net over the next several years. Strictly through the drill bit, I might add. To add to what Jeff said, we believe we can do this at a find development cost of $1 per MCF or less. This is extremely good news for Range and its shareholders. Because Range is not a major oil company, or an extremely large independent, if we are able to accomplish this high growth at extremely low cost, the impact on our NAV per share will be extraordinary. The challenge is how do we capture as much of the NAV impact for Range's shareholders. We firmly believe that if we stick to our disciplined approach of focusing on NAV per share, we will put ourselves in the best position to drive up our NAV in the medium to long term. Instead of trying to dazzle you with some new financial maneuvering, I will first review what our past track record had been. Over the past two and a half years, I think since the end of 2007, we have expended $4.6 billion of capitol. 51% of the funding has come through operating cash flow, 19% from asset sales, 18% from the issuance of debt and 13% from the issuance of equity. Since 2007, we have increased the shares outstanding by 7% in total or about 2.8% per year on average.

Looking forward, we plan to take the same approach. That being said, developing a giant gas field in a low price environment will be challenging. However, we have several advantages going for us. First, the Marcellus shale, and especially the liquids rich portion of the Marcellus is extremely economic even at low gas prices. Our analysis indicates that $2.50 flat NYMEX gas and $60 flat oil in a liquids rich area in southwest PA generates a 35% rate of return. So it makes sense to us to aggressively develop our southwest PA acreage position in the current gas price environment as we will be generating attractive returns, increasing NAV per share and fast forwarding the net present value. The increase of the 2010 capital budget is a reflection of this. Funding increase will come from a combination of additional asset sales and draws under our credit facility.

The second advantage is that the Marcellus shale is uniquely located in the best gas market in the world. Therefore, Marcellus gas will have a location premium over other large gas plays in the US, Canada and throughout the world.

Third, there is a significant existing large pipeline infrastructure already in place to move Marcellus gas to market. While there will be investment necessary to interconnect the large existing pipeline systems to the Marcellus gathering systems, the investment will be far less than the other major new gas plays.

Fourth, Range has a significant amount of other production that it can sell from time to time to help fund the Marcellus. Fifth, Range has a strong balance sheet and nearly $1 billion of liquidity to help fund our growth. Sixth, Range has an attractive hedge position for 2010 and 2011 that will help underpin out cash flow. Most importantly, because the Marcellus is so economically attractive, over time it will become self funding. The self funding point will depend on a number of factors including natural gas prices, the pace of development and the cost to develop.

We understand the concerns of shareholders who worry about dilution through the issuance of equity. We are right with you there as all of us at Range have a great majority of our net worth in Range stock. However, I would be misleading you if I didn't expect that all of us would suffer some dilution in the future. However, I will commit to you that we will do the best to minimize the NAV dilution from where we are to reach the point of self-funding. These are extremely exciting times at Range. We have a great team of people at Range, highly motivated at bringing forward our NAV per share as quickly as prudently possible. The second quarter results are a reflection of the passion and our ability to succeed. We truly appreciate our shareholders continued support. The future is extremely bright at Range. With that, Operator, let's turn the call open for questions.

Thank you, Mr. Pinkerton. (Operator Instructions) First question, Dave Kistler with Simmons & Company. Proceed with your question.

Good morning, guys.

Good morning.

Just following up on your last statement, with the increased in CapEx for 2010 and a lot of that tail end of the year CapEx flowing through to production in 2011, can you talk a little bit about what we should be thinking about for CapEx in 2011, flat versus up substantially from 2010, and then as you mentioned, the path to free cash flow neutral, has that pushed this out in any way, shape or form at this point?

This is a great question. We are just in the throws of putting together our 2011 analysis and we will share that through the board in September and then what we normally do is, based on their comments, finalize that in December. That's what we will do again this year. I think it's too early to tell in terms of where we will be. Obviously, we will be sensitive to where natural gas prices are. Historically, it's been a pretty easy play book. We've taken cash flow and asset sales to fund the bulk of our capital and then we tried to use debt and equity securities at the high end, and then the equity side at the very end of it. We will continue to do that. It's a little early to look at 2011 in my mind.

But, again, the good news is that we are really driving down the cost per unit so we will be able to do more with less. The other thing I think that is really important is to kind of step back and look at this from a kind of NAV per share perspective. We run models all the time to try to figure out what is the best way to drive up our NAV per share. That is really what we are all focused about. And we have run a ton of models on the $210 million that we will spend this year and we are convinced it's the right thing to do. We will do the thing for next years capital budget. That being said, we're going to key up some more asset sales for this year. Chad and his team are already at work at that and obviously asset sales for 2011 will be a big part of the plan as well. So, that's where we stand.

Great. Following up on that, you mentioned as part of the sales in your prepared speech, the possibility of selling production. Did you mean that out right in terms of doing a volume metric production payment to be able to accelerate cash from that to then reinvent in accelerating the NAV out of the Marcellus or am I reading too much into that comment?

I think the asset sales will be along the lines of what we have historically done. One of the rules at Range, try to keep it simple. Production payments, at least in our view, are highly complicated. They really trash up your balance sheet and it creates a lot of legal documents that you have to let the lawyers run around to review all the time. Those aren't things we think are productive in the long term trying to run a business. So, we will stay away from production payments for the most part. We have, I don't know what the total number is, but roughly 130, 150 million a day of production that is not from our big three. And yes, we will continue to take a look at that and high grade that and look at the more marginal higher cost stuff just like we have in the past, we will continue to sell that stuff off and help generate proceeds. I don't think there will be anything fancy that we will come out with.

We won't try to dazzle you with a new financial trick of the trade here, we will stick to our knitting, stick to what we have historically done. But again, there is a lot of different ways of skinning the cat. If you look how Southwestern did what they have done, we have studied that quite hard and some other things. We will continue to look at things. At the end of the day, again, I'll put the stake in the ground so to speak is whatever we do, we will look at the alternatives and pick the one that generates the highest NAV per share. Whatever it comes down to, that will be the stake in the ground.

Great. One last question. Looking at the up tick in 2011, Marcellus gas production, can you guys give us a little bit more of a breakdown in terms of southwestern production, northeastern production? Is that larger number being driven purely by efficiencies or should we expect maybe the northeastern gas to be coming on sooner and then as a follow-up to that, just I know you are in the process of putting a propane line in place. Obviously NGLs across that whole area with increased production like yours is going higher, where are we on that propane line and is it on schedule, et cetera, et cetera?

I'll talk about production a little bit. The bulk of that will be coming from the southwest. That's the derisk area. We are building out a lot of infrastructure. We have the Liquid Rich part of it. So all that will be where the bulk of the drilling and the bulk of production is. However, by the end of this year, we expect we will get production on from the northeast. That will start to contribute. If you look at the acreage, 900,000 acres that allows us to grow significantly from where we are on the order of eight times over from the Marcellus, the bulk of that acreage, 600,000 is in the southwest. Theres been a lot of industry drilling, a lot of our drilling. I would say 90% plus of that acreage has been derisked. So that is where you will see the bulk of our activity.

In terms of the propane line, Dave, it's moving along at we thought and we are pleased. There are some regulatory stuff that they have to get through but it's making progress. So, we are right on scale there. Right on schedule.

Just clarification with most of the production coming from the southwest, Liquid Rich, propane line feels like it will be done in time to ensure there aren't any liquids related issues there? Just trying to check that box more than anything else.

Yes, let me back up. The propane line, we are already selling propane down the pipeline. The big line we are talking about is a longer term issue that deals with the ethanes. As we ramp up in the southwest, we will ramp up the ethanes. Currently we are selling the ethanes in the gas strain. We prefer to strip them out and actually sell them as ethanes because we get paid more. We are trying to capture the whole gas stream there. The good news, we dominate the Liquids Rich area. So, a lot of these projects are going through us and we are seeing a lot of different things. The good news is that there is a lot of neat creative things going out there. So, we are encouraged by that and we think over time it will continue to help the margins and what not.

Great. Thank you, guys, very much.

Thank you.

From Marshall Carver with Capital One Southcoast. Please proceed with your question.

Yes, Good morning. A couple of questions. The new bolt on acreage at Nora Haysi, I know you have the mineral interest on the old acreage. What is the royalty on the new acreage?

An eighth.

An eighth, okay. On the production mix for next quarter, could you give us a feel for what, either in absolute numbers or percentages, what the split would be between oil, NGLs and gas?

What I would suggest there is after to call Rodney has tried to put out a lot more information on that split and mix so people can get pricing right. Probably better, I would say to call Rodney and he can give you that detail.

Okay, I'll do that. Finally, a question on the Huron and Devonian wells. It looks like you are encouraged with initial results. Trying to think long term, seems like it would have trouble competing with the Marcellus in terms of economics unless it's really good because the Marcellus is so good. How would it be able to get capital or would you potentially sell that or JV it? What would your plan be on success with the Huron and Devonian shales?

Let me clarify that so that it's really clear. The Huron is in Virginia. That is on the exiting Nora Haysi acreage, in the new acquisition acreage. The Huron is a Devonian A Shale. . When we go up to southwest Pennsylvania and we are saying Upper Devonian, it's not Huron. It's [Genesee, Burkett, Rines Creek, Middlesex] it's an aggregate of those shales. And it's literally in southwest Pennsylvania, right on top of the Marcellus. I was lobbying hard to talk able to talk about it in more detail because we have a lot of data and a lot of exciting data. I'll say this, after drilling the first well, we are clearly ahead of where we are in the Marcellus at the same point in time. As we drill every Marcellus well, you are drilling through that upper Devonian package. We have long term testing on it. It will be online later this year.

We have actually drilled our second well and will be completing it by the end of September and will have a third well. It's right on top of the Marcellus so it will help us with deficiencies. All those lines and compression and gathering is literally right in the same area. There is no acreage cost. It's on top of where we are. But it has huge potential. The potential, when you look at BCF per mile off of ECS logs, what is in the upper Devonian in aggregate is on par with what we have in the Marcellus. It's extremely high up side. It has fantastic potential. That was a very general answer and hopefully whether it's next quarter or the following quarter we can get more specific but so far I would say we are

Okay.

And for total clarification, you have Huron in Virginia and all that acreage is perspective. You have upper Devonian, basically in southwest Pennsylvania, and there's a third up side in the Utica shale which is below the Marcellus. And, again, we've drilled and completed our first Utica well, have long term testing. We will be spotting another well probably early in the first quarter of next year, and there's tremendous upside in Utica as well. So, you have three horizons.

Okay, thank you,

the next question is from Ron Mills with Johnson Rice. Please proceed with your question.

Good morning, guys. Jeff, on the two to three BCF per day that you think you can now get to, at what point down the road do you think you can achieve that level? Is that five years from now, three years or even longer?

Well, let me start with where we have been historically then in vague ways talk about going forward and hopefully give you some guidance. If you go to the end of 2008, I believe we were about 26 million net out of the Marcellus. At the end of 2009 we actually quadrupled it to 100 million per day net. The end of this year basically we will double it, 200 million to 210 million. We have given guidance for end of 2011 to double that again to where you get to 400 million to 420 million a day net. That is the kind of trajectory that you will see. If you look at our current presentation on our website, on slide 13, I believe, if Rodney has given me the right information, you can see the Range hockey stick. You can take that and get a French curve, which is what you will need because it's exponential up and you can project forward where you think we will be at the end of 2011. Once we go through that budgeting process that John talked about and present to the board and lock down of where we will be, I would imagine that sometime around the end of this year, we will probably come out and paint out that year for you. I believe it's pretty exciting.

You think look at the hockey stick and see where we have been. See where we've been, see where we're going, and as we paint out that extra year, then I think you will get a pretty clear feeling and you can probably do it yourself with the data that is out there on when you think we will break that. That is exciting. Just to add a little more color, and I tried do it in my notes, and I know you go to a lot of presentations and a lot of conferences and everybody is talking about TCF, but how many of those really materialize? How many companies have gone organically and been able to literally to a BCF per day or two and beyond. I can think of two since I've been in the business 31 years. Range clearly is on that trajectory and we have the potential to get into that slot and do it organically, and to do it with an extremely low cost structure and strong economics. That will drive NAV and that is what we are focused on.

I don't know who this is for, on the ethane production, sounds like you are keeping that in the gas stream for now. What will be the trigger point that gets you to start to strip that out and begin to sell it, especially given the current price situation for ethane?

You have to remember, we have a couple of options. One option is to continue to do what we are doing in the blend. Right now we are getting paid for the Btus. And even after we strip out the liquids, which are a really nice positive boost to the rate of return, we still get paid Btus. So after processing, we still have 1140 Btu gas roughly. So we have the ability to keep blending, but like John said, since we have a dominant position, a lot of those projects are a critical piece to any of those projects going forward. We will look at them all to see whats optimum. Is it better to continue to blend long term or break it out? Our decision will be based on what maximizes NAV for Range.

Roger, just a couple of questions. On the G&A, you expect it to be flat with the second quarter. Is that flat after backing out the $2.5 million legal fee or is it going to continue to grow at kind of that level just because of the increased staffing you are undergoing in Pennsylvania?

I think it will be in the $0.57, $0.58 slot for the remainder of the year, Ron. We are continuing to add staff and gear up the capital increase. You need more people. But, again, like Jeff said, a lot of these expenditures and just moving from 2011 to 2010. We have to get extra people to handle that, so it's a little bit of a fast forward.

And then finally, on liquidity, can you walk through what your current liquidity is under the terms of cash and under your he revolver?

Sure, our borrowing base is currently $1.5 billion on the bank credit facility. That was reaffirmed in March of this year. Our next bank meeting is in September. All indications are with the kind of reserve performance we are seeing, is that our maximum conforming capacity will be above that $1.5 million number by a considerable margin but we don't feel the need to access. Our legally binding commitment is a $1.250 billion. And the way our facility works is that we can tender notice with the agent and then we can increase from that $1.250 billion to $1.5 billion with 20 days notice among the existing groups. But just keying off the $1.250 billion, we've got $475 million outstanding but that is a little misleading because we have $160 million parked in escrow. You are looking at a net bank debt in the low $300 million against $1.250 billion in committed availability so we're just under $1 billion in liquidity on a legally binding basis and about $1.250 billion on a max bind basis.

Great. Thank you very much, guys.

Thank you. Our next question is from Gil Yang with Banc of America. Please proceed with your question.

Good morning. Granted you accelerated your activity to create more NAV per share, I wanted to get inside your head and think about what limits the ability to accelerate it even more if you think that you can create NAV through this acceleration?

Well, I think when you look at it, what a big driver was, when we entered the year at the end of last year when we set the budget, we went through the same process last September, October, November, December and we came up with the number of wells we think the rigs we have under contract will drill and the reality is our technical organization with those same number of rigs can now drill more wells. That was the key part. So as we have gone up the learning curve, we had two choices. One, we could farm out a rig but given the strong economics and strong rates of return, and again, look at where we were last year. Rate of return under fixed price and where we are this year, is significantly better. Great last year, even better this year. Our decision was rather than farm out a rig, that is what prompts those points. To the extent our team gets faster and faster with the same number of rigs, that's going to accelerate production.

That acceleration, some people are looking what did it do to this year, what does it do to next year and we raised guidance both years. Actually the question, I think Ron asked it, where does it take you, where are you going to be out there in terms of breaking BCF per day? That acceleration helps you in 2012 and beyond, because as you build roads into an area and you build a pad off it, then you can come back and build additional pads off the same road. You can drill additional wells off the same pad. So those efficiencies are what will drive. We are not about running the most number of rigs or like John said many times being the biggest and baddest and running the most number of rigs in the play. We about rate of return and NAV and we let our technical team dictate that. We learn as we go. The good news is the more we drill, the more the acreage gets derisked. The more the industry drills the more the acreage gets derisked. So that 20 plus TCF that we see out there right now is looking extremely strong. The production growth is looking great. The rates of return are better, and you are seeing it quarter-to-quarter in our unit costs coming down. That what drives our conditions.

So, is the increase in spending for the roads and pads et cetera for next year that you're accelerating to 2010 again a result of the more efficient drilling riggs that you are seeing?

Yes, it's a combination of that but also, as we are starting to develop in the northeast, we getting to be a more efficient organization. In the southwest, you are in front of the mountains. When you go into the northeast, you are in the mountains. You have winter in Pennsylvania. It's important in both areas but prebuilding some of that stuff in the fall and before wintertime makes us more efficient. It's more cost effective, it's a better thing to do. As we ramp up in that area, we are pulling some of that fast forward.

I talked about those two rates for our first two horizontals in Lacoma County being 13.5 million per day roughly each, those are seven day averages, so those are pretty impressive rates and those were pretty strong wells when we finished. That's a heck of a shale well. We are excited about that. We are up there drilling now. We want to bring that stuff online, so it's all part of how do we maximize the value of our share price, how do we maximize NAV. Those are the things that drive us.

Wouldn't you have already had capital in your budget for the northeast expansion in terms of the accelerating, getting out in front of wintertime?

Well, we had some capital in there but it comes back to, remember most of the capital is predominantly for the southwest. That's where most of our infrastructure and most of our drilling is. As you have the capital in there, we did our deal with PVR, PVR looks like it's on track, it looks like it won't be delayed, it looks like if anything it maybe a little earlier. We want to pull some of that forward to make sure, if we can, to get it on this year. We think that would continue with the great story that we have.

Okay. Great. Last question, for the Talisman joint venture, the $25 million you expect to spend, how much is the total commitment to hold that acreage for the joint venture?

It's really about developing acreage that we think is perspective. In the plan to maximize the value to acreage, will not only drive up production but will hold the acreage. That capital does in essence both. It's not one or the other, its both.

We haven't committed $100 million, $200 million, $300 million. It's just a normal operating agreement. Talisman and us will sit down to decide how to drill wells. Either party can commit or not commit to those wells. You have a lever there whether you want to commit capital or not. It's much different from a financial JV, this is a regular industry joint venture where you have two industry partners developing an acreage position. One of the things that is encouraging to me is that that acreage, that 14,000, 15,000 acres would not have been developed in the short term for us. So, what we are doing, we are pulling that acreage forward in our NAV curve and we are using the benefit of Talisman's technical team and their rigs and people to help us develop that. I think it's smart on our part to do that.

What we had to give up is the day to day operations, which a lot of companies don't like to do, but obviously Talisman is a first class organization. They have drilled some terrific wells up there. We feel really comfortable with them. Not that we will do a lot of these but we are talking to different people about some of this stuff and other places where we have bits and pieces of acreage that we're not going to get to in the short term, that's a great solution to deal with that NAV issue in terms of pulling that forward into the NAV curve. So, again, it's just part of it. As Jeff mentioned, not only do we have Talisman's team working on that, we have Mark Whitely and his team from the Barnett shale and they will be working a lot on the northeast acreage. This time last year, we had one team working on it, now we have three times working on it. We think that makes sense in terms of you will get more done with three teams than one time. It's a maturation of the process. You learn as you go.

All right. Thank you.

We are nearing the end of today's conference. We will go to David Heikkinen of Tudor, Pickering, Holt for our final question. Please proceed with your question.

As I think about the acceleration of CapEx from 2010 to 2011, I'm thinking about that as a recurring cost that goes each year as you pre-invest in roads, pads and the like. Is that a reasonable expectation or would CapEx actually drop in 2011 versus 2010?

A better way to think about it, the total project CapEx is the same. You are just pulling it forward. It's as simple as that.

You will pull forward 2012 into 2011. The train car keeps going for roads and pads and the like?

Right but you are pulling forward and increasing the rate of production and the NPV of the project gets greater. The overall capital is the same, you're just moving it all forward, but you are moving the production and the reserves and everything else forward as well.

Specifically on split of rigs running on the liquid rich versus dry gas in the southwest, do you have that?

Yes. Right now we just have one rig in northeast. All the other rigs are in the southwest. They are in the wet gas.

Okay. And then thinking about the Nora transaction, I know it's relatively small dollars in kind of a core area for Range, but thinking about how investing capital and blocking that up adds more NAV than investing more in developing your huge Marcellus position?

Well, I think it's -- again, we believe what our mission is to build NAV per share. We got core areas in Barnett and Nora and Marcellus. We will continue to build on those. We think it makes sense, when you look at the overall risks of the industry and we have done a lot of studying. At the end of the day, do we want to be a one basin company and I think the answer to that is, no, we don't. So, when we see opportunities in these other areas, we think it's prudent from a risk perspective to go ahead and seize that opportunity. Like I said before, we haven't done an acquisition for, I think, way back into 2007 and that was we added a little piece of Nora. Going back to that, back in 2005. So, we have been disciplined on the acquisition side and not done anything because we had this Marcellus opportunity. But we had this opportunities with Nora and we think they are exceptional so we will do it.

Again, I think, you have to look at the risk of the overall risk in the industry and our company and think through it. Do you want to put all your eggs in one basket and we are obviously putting a lot of eggs in the Marcellus basket. We think it's prudent in an area like Nora, we know so much about, we have a great team. I think Jeff mentioned, we think the up side on the reserves, 100 BCF approved, the total reserve up side is close to 800 BCF. Great, long NAV accretive acquisition.

Do I think we will do a lot of those, no. I think history has shown over the last several years we haven't done one. It's relatively small and a perfect fit so we think it made real good sense. Look, I think if you are going to be buying something today, I know a lot of people are rushing out to buy oil projects, but if I was in a choir today, I would be buying gas property because I think there's substantial more upside in gas process than there is in oil process. That's a little bit of an editorial in terms of the acquisition market but we won't be a big player in the acquisition market. I don't think any shareholder should worry that we will do some giant acquisitions any time soon. You make a good point. We will stick to our knitting. Our sandboxes that we have are terrific and we will continue to expand those. From time to time when we see little add ons in these key areas, we will try to take advantage of that. Long term we think that's what the shareholders want from us.

Seems like a good place to end. Thanks, guys.

Thank you.

Thank you. This concludes todays question-and-answer session. I would like to turn the call back over to Mr. Pinkerton for his closing remarks.

Thank you, all. Second quarter was truly a terrific quarter for us. Being able to continue our consecutive string of quarterly production increases obviously given the guidance we gave you, we expect to hit 31 and then at the end of the year hit 32. That will be eight consecutive years of sequential production growth. More importantly, obviously nobody in our peer group has been able to do it, so it's something that we are proud of. More importantly, just to focus on what is really happening within Range and that is we decreased our operating costs by more than a third. As Roger mentioned, we are running on an absolute basis less than where when production was almost a quarter lower.

The other thing I think that's really important is that we are driving down our DD&A rate, which at the end of the day that's what has to happen in a low price environment. We expect to be at $2, maybe with a little luck under $2 by the end of the year and continue to drive that down. That's going to do a lot of stuff. And at year end if we book reserves, with less than a dollar all in fighting costs, that will continue to drive down the DD&A rate. That will increase our net earnings, increase the shareholders equity and it will allow us to continue to prudently put on leverage on the company. As Roger said, we will keep a firm balance sheet. But as we drive down our costs, our debt per approved MCFE will drop pretty significantly this year with the additions that we will put on. That will allow us to continue to accelerate production in capital into these projects. And like I said to you, I won't fool you and say we will never issue any equity ever again and suffer any dilution but at the end of the day, but the worst dilution in my mind would be to do a giant joint venture and give up a quarter or a third of your acreage position. That is the ultimate in dilution.

So again, when we run the model, we will be sensitive of that. We are focused on the long term and the good news, we found a giant gas field. It's working. It's working like spades and it can work terrific at 350 to 450 gas and we are convinced of that and we will charge ahead and develop the NAV per share and try to fast forward that as prudently possible as we can. Again, we appreciate everybody's support. I know the current gas environment is unsettling for many investors. The cure for low gas prices is low gas prices. The good news is that we are able to keep it at $4.50 to $5 Range. Most of the electric generation in the US in the future will be with natural gas. It's cleaner for the environment so we will doing some good for the environment as well. I think it's all good. We will get through this period of low natural gas prices and demand will pick up one of these days and gas prices will increase. It will happen. Gas prices won't stay low forever. There is too much energy all over the world for that to happen. It's cleaner and we can do it with current technology. We don't have to play like there is some cleaner version of it. So, the future is bright. We will get through this period of low gas prices.

Toward the end of the year, as you will see with more vigor, what the costs will be, where the production is going. The hockey stick in terms of Marcellus is exciting. We will give you data in terms of the other formations. That is terrific work. We need to add in some of our acreage positions before we do that so that is occurring. So, it's all good and we are excited and, again, for those of you all who didn't get to ask questions, feel free to call us. We will be here all day. We are not leaving and we will take any and all questions from everybody and try to be as transparent as we can. Thank you very much. We will see you next quarter.

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