Range Resources Corporation (RRC) Q2 2010 Earnings Report, Transcript and Summary

Welcome to Range Resources Second Quarter 2010 Earnings Conference Call. [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 morning, and welcome. Range reported results for the second quarter of 2010 with record production and reduction in our unit cost in most of the major cost categories. Second quarter marks our 30th consecutive quarter of sequential record production growth. As our operations continue to become more efficient, we're 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 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'd 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 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 this August. Check out our website for a complete listing for the next several months. We'll be at Tudor, Pickering Energy Conference on August 12 in Houston, energy conference in New York on August 18 and the EnerCom 15th Annual Oil and Gas Annual Conference in Denver on August 23. 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 adjusted the asset sales, first quarter production growth would have been about 13%, 14%. This marks the 30th consecutive quarter of sequential production growth as Rodney mentioned, and obviously a great milestone for our company. After closing the Ohio sale, right up into March and losing roughly 25 million a day of production, our analysis indicates we would not overcome the entire Ohio loss in the second quarter. Therefore, this would stamp our record consecutive record of production growth. However, our operating teams proved the analysis wrong, and made it happen, our growth record continues, which I'm ecstatic about. It's truly a team effort with all of our divisions that are contributing. The Marcellus division was the largest contributor as they continue to drive up production by drilling 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 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 cost 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're still building out our Marcellus team and we'll continue to see the impact for another couple quarters or so before we begin to see a decline in a unit of production basis with regards to G&A. With regard to the Marcellus Shale play, we continue to make significant headwinds during the quarter as we drill from the fantastic wells, drill on our acreage position, test other shale formations both above and below the Marcellus and continue to build out our infrastructure. As we previously note, we continue to add to our a 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 proceed 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 $135,000,000. We're pretty excited about the acquisition as it -- literally fits hands in gloves with fits with our other Virginia properties. The transaction NAV per share accretive and we see substantial upside in the properties. Jeff will go into more detail after 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 Rob to review the financial results.

Thanks, John. The second quarter of 2010 is setup to be a bit of a sequel to the first quarter this year. Production against all odds and asset, 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 in 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 from falling production over last year could not overcome the 18% decline in realized prices. Now 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 estimate of $0.83. Lower realized prices caused that $0.01 variance. Year-to-date cash flow totaled $277 million. EBITDAX for the second quarter is $156 million, 15% lower than the second quarter of last year. EBITDAX for the year-to-date period was $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 appears as tabs numbers six, seven and eight up 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 the second closing associated with the sale of our Ohio tight gas sand properties, netting a pretax gain on sale of $10 million. Non-cash marked-to-market derivative losses for the second quarter came in at $4.4 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 excluded the a 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 lower 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 analysts earnings. Although 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 the workovers were $0.68 per 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 '08, that's a 35% reduction and it's critical cost metric over just the past two years. So 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 costs has not only declining on a unit cost basis, but on an absolute basis as well. And in second quarter of '08, our direct operating cost was $36.5 million on average daily production of $381 million cubic feet equivalents. In the second quarter of 2010, direct operating cost is $29.1 million on average daily production of $472 million cubic feet equivalent. So even though direct operating expense is largely a production-dependent variable cost, costs are down 20% or production is up 24%. Compared with our improving capital efficiency, this cost compares and illustrates the benefit of continually high grading our assets and 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 cost to decline further into the low $0.60 range. Production taxes for the second quarter are flat with the second quarter last year and also flat with the first quarter of this year at $0.19 per 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, and this increase stems primarily from $2.6 million in legal expenses and those were incurred to successfully defend one lawsuit and successfully settle two other legal claims. As these type of G&A expenses 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 in the second quarter as we continue to step up the Marcellus Shale division. Interest expense for the second quarter of 2010 is $0.72 per Mcfe and is flat with the first quarter this year, $0.03 lower than the same quarter 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 reason for this increase over last year is higher delay rental payments. Quarterly exploration expense, excluding non-cash comp should fall in the $16 million to $18 million slot during the third quarter, as the late rentals decline, the 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 $2.34 per Mcfe. Just as declining direct operating costs signals improving operating efficiency, declining DD&A rates signal improving capital efficiency, as we see the benefit of high grading our assets and drilling inventory. Now 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 and even lowers DD&A rates. The DD&A rate is expected to drop another $0.07 to $0.10 in the third quarter and decline towards the $2 mark by year end. Abandonment and impairment of unproved properties for the second quarter was $13.5 million, that's a $27.5 million reduction from the second quarter of '09, and while this non-cash expense fluctuates, we're 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 carryforward to help shield future taxable income. Our effective tax rate for 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 dollars of Ohio asset sale proceeds that we have placed in an exchange account through the Virginia acquisition. In addition to the benefits Jeff will of speak shortly, this core area acquisition allows us to defer approximately half of the taxable gains in the Ohio asset sale, on an acquisition that's highly accretive in its own right. The remaining exchange account cash is earmarked for budgeted 2010 acreage transactions in specifically selected areas, but it is also completely unrestricted. So if the acreage is unavailable, we may move the funds out of the accounts anytime we choose. For the remainder of 2010, Range has approximately 75% of its gas production hedged, with collars that are floor priced of $5.56 per Mmbtu, a cap of $7.20 per MMbtu. We've 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 hedge, with collars that are floor priced of $5.37 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 a 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 the collar of $70 by $90. Lastly, we've added 2,000 barrels of 2012 oil volume hedged at $75 by $80 in a collar. The balance sheet remains in great shape. Our debt-to-capital ratio, net of the cash in the 1031 is right at 40%. And we expect it to drift up a bit slightly during the remainder of the year, as we increase our spending. But we remain committed to maintaining a 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 all both in 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 E&P 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 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. So John, that's it for me.

Thanks, Roger. Terrific update. I'll 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 five 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 per 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 spent $4 million to get 5 Bcfe and that the gas price is $4 dollars per Mcf flat forever is 60%, and $5 flat forever, the rate of return at 79% and that's $6 flat and 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 buildout 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, and 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're in great shape. We're currently renting 13 drilling rigs in the Marcellus play. Six of the rigs are the larger rigs, which drilled the horizontal portion of the wells with mud and the other seven rigs are smaller rigs, which drilled the vertical portion of the hole with air. The drilling team continues to get more efficient, and as a result, these rigs will draw 18 more wells in 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 pre-build 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, with $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 risks, we believe 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're 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 add $25 million to our 2010 capital spending. In total, we'll 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 to 210 million per day net. We'll also revise on our expected 2011 Marcellus exit rates 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're 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 on 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're 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 cost to drill and complete is $4 million, given we're now drilling laterals that are about 3,050 feet versus 2,500 feet last year. In addition, we're now the completing the wells with 10 stage frac 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 price 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've 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 on the fairway had a resource potential of 15 to 22 Tcfe net from the Marcellus. Today, we're estimating that our 900,000 acres has a resource potential 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 perspective 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 on our Marcellus team and Barnett team on fast forwarding this development. In addition, we're 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 past year. So at this time last year, we have not drilled in the northeast. Since then we have completed two horizontal wells in Lycoming County for rates of 13.6 and 13.3 million per day. Last year, we have 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 online by the end of this year and the ramp-up development there next year. I am extremely pleased with the accomplishments of our team and the industry partners we're working with. Las year, I believe that we had the potential to possibly reached 2 Bcfe per day as net production in the Marcellus. Today, I believe the potential upside could reach beyond that and could possibly approach 3 Bcfe per day net. Range is in a very enviable position. I've been in the business for 31 years and have worked all over the U.S. and the world. During the last 31 years, I've only seen very few, extremely few companies who have organically grown production in the U.S. from zero in a particular play to a net rate of 2 to 3 Bcfe per day. Again, I'm talking about growing productions through drilling only and 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 and have grown production from zero to about 1 Bcf flow 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 discovered Prudhoe Bay and Southwestern discovered the Fayetteville. Range like both of those companies has the potential to grow up to 2 Bcfe per day net and perhaps beyond. That's pretty exciting stuff. One other project I want to discuss today is our acquisition of additional properties in the Virginia. These properties are a great fit with our existing Nora/Haysi properties in Virginia. In fact, the 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 and the Huron Shale. This acquisition will give us a 100% working interest and 100% net revenue interest on all of the Haysi plays. As good as the Nora CBM has been economically, the tight gas sands were even better. We've 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 sands well is 40% and for $6 flat forever, it increases to 56%. That's for an average Nora well, which is drilled on 112 acres spacing and averages about 450 million cubic feet of gas per well. The Haysi wells that we're acquiring is even better than the Nora wells. The Haysi wells averaged about 550 million per day and are drilled on an average spacing at 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 developed the property and we're 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 the resource potential of approximately 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 acquire is prospective for all horizons including the Huron Shale, which is only had very limited vertical development here. In the other traditional horizons, the well was drilled on about double the spacing of the surrounding fields. We believe that there's a lot of low-risk, strong economic wells to drill. In addition to the acquisition capital, we'll 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're 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 10x 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 of 2010, I'll spend a few minutes in summarizing of what we 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're 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 cost and DD&A are particularly encouraging. The good news is that these are not onetime events. We expect the unit cost to continue and decline in the quarters ahead. Another significant accomplishment was completing the Ohio sale earlier in the year, when gas prices were higher and by completing the initial closing in the first quarter, where we're 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, and we're excited about the potential of the properties as Jeff has mentioned. Acquiring the properties at good prices and using the 1031 account proceeds were the home run. As I've said many times, I love the Nora area. It is our Energizer bunny and 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 buildout was right on track, the quality and depth of the 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 derisk and we really like what we see. Lastly, given that most of 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 and the Virginia acquisition as I noted before, we've increased our production guidance. With regard to reserves, we currently believe we are on track to record an all-in find 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 through the remainder of 2010, we see continued strong operating results. For the third quarter, we're looking for production to average $495 million to $500 million a day, representing a 14% increase year-over-year. Our third quarter production, where we'll reflect the sale of both the New York properties we sold last December, and the New York properties we sold at March of this year. So the 14% third quarter target equates to 19% after adjusting for the asset sales. Now that we closed the Ohio property sale, I'll take a moment to look at the impact of our divestiture program. Over the past few years, we've reduced our well count by roughly 6,000 wells. As Jeff mentioned, this represents 50% of our well count, but they only represent 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 refocused on our capital in our higher return properties like the Marcellus, the Nora area and the Barnett Shale. As a result, despite the assets sales, the production reserves continues to increase rapidly. Over the same three-year period, we've seen our well count declined, our production is driven by over 50%. As a result, Range is a much more efficient company, we like to say we're doing more with less. By less we mean less wells, low refining development cost, lower operating cost and lower year end cost per Mcf. We believe this is critical in a low-cost environment. Turning to the topic of joint ventures. We were often asked about the various joint ventures that are either coming through or completed and what our current thoughts are. 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 or JVs where two companies in the industry pooled their acreage primarily for efficiency reasons and to jointly share the risk of developing the combined acreage position. Financial JVs, where one company contributes to land and the second company contribute to help defer 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 and from a NAV per share basis. Bottom line, if we received an offer that is NAV accretive, we'll seriously pursue it. As Jeff mentioned, we believe that our Marcellus acreage could result in production one day, and potentially 2 or 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 given 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 in considering the NAV per share impact of any large financial JV. That being said, at Range, we focused on NAV per share. I believe we've demonstrated this over the years in a very 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 three years. First, the drilling permit process in Pennsylvania has gotten much more predictable, and we're regularly receiving permits in 30 days or less. Second, the water access and flow back process is much more predictable, especially given that Range is recycling 100% of its flowback 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 the severance tax in Pennsylvania, the good news is the state has not yet enacted the tax. In the past the past several years, we and the rest of the industry have worked hard to educate and worked with the Pennsylvania legislature about issues surrounding the severance tax, encouraging them to take a holistic approach, whereby, any severance tax would come with a balance regulatory modernization. Recently, the Pennsylvania legislation announced that it would work for the severance tax proposal causing 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's 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 frac-ing fluid. As a result, we have spent several months working with our service partners that we could disclose the content of our frac-ing fluid. On July 14, we announced a voluntary disclosure initiative regarding the Marcellus Shale frac-ing fluid. We announced that we'll submit to the Pennsylvania DEP additional information about the content of the fluid on a well-by-well basis and also posted information on the website. We also announced that the current frac fluid moisture contains 99.86% water and sand, with the remaining 0.014% being chemical additives. Of the additives, 0.004% are considered hazardous in a concentrated form, according to the Federal Regulatory Classification, and like most common household chemical substances, in a diluted form, post no harm. Our objective with this initiative is to continue at Range this 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 legislators, land owners and other Marcellus operators and the general public as a whole. We are hopeful that other Marcellus operators will follow through, but we understand it will take them a while to work through the disclosure issues with their service companies. We are actually convinced that the Marcellus can be developed in a way that it's 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 on the 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 non-taxable 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 admirable position as we believe we can now grow the Marcellus production from 116 million a day, net, where we are today to 2 or 3 Bcf net over the next several years strictly through the drill bit, I may add. To add to what Jeff said, we believe we can do this at a fine 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, we were 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, by 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 douse you with some of the new financial maneuvering, I'll 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 capital. 51% of 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 liquid-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 or liquid ridge area in Southwest PA generates a 35% rate of return. So it makes sense for us to aggressively develop our Southwest PA acreage position in the current gas price environment as we'll 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 the 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 ore [ph] gas will have a location premium over other large gas plays in the U.S., Canada and throughout the world. Third, there's a significant and existing large pipeline infrastructure already in place to move Marcellus gas to market. While there'll 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 positions for 2010 and 2011 that will help underpin our 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. With 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'd 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 would do the best and 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 to bringing forward our NAV per share as quickly as prudently possible. The second quarter results are reflection of our 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.

[Operator Instructions] Gentlemen, our first question is from Dave Kistler with Simmons & Company. David Kistler - Simmons & Company: Real quickly, just following up on your last statements there, John, with the increase in CapEx for 2010 and a lot of that tail end with the year CapEx flowing through the production in 2011, can you talk a little bit about maybe what we should be thinking about for CapEx in 2011, flat versus up substantially from 2010? And then as you mentioned, kind of a pass to free cash flow neutral, had that pushed this out in any way, shape or form at this point?

We're just in the throws of putting together our 2011 analysis, and we're going to share that to the board in September, and then what we normally do is, based on our comments, finalize that in December. So that's what we'll do again this year. I think it's too early to tell in terms of where we're going to be. Obviously, we'll be sensitive to where natural gas prices are. Historically, it's been a pretty easy playbook and that we've taken cash flow and asset sales to fund the bulk of our capital. And then we try to use debt and equity securities at the high end, at the end of it, and then obviously, the equity side is the very end of it. And we'll continue to do that. So it's just a little bit too early to look at 2011 in my mind. But again, the good news is that we're really driving down the cost per unit, so we'd be able to do more with less. The other thing, I think, is really, really important is if you kind of step back and look at this from a kind of NAV per share perspective, and we're running models all the time to try to figure out what's the best way to drive up our NAV per share. And that's really what we're all focused about. And we've run a ton of models on the $210 million that we're going to spend this year, and we're actually convinced it's the right thing to do, and we'll do the same thing for next year's capital budget. That being said, we're going to tee up some more asset sales for this year. John and his team are already worked at that, so we'll try to look at that. And obviously, asset sales for 2011 will be a big part of the plan as well. So that's kind of where we stand. David Kistler - Simmons & Company: John, following up on that, you mentioned as part of the sales in your prepared speech the possibility of selling production. Did you mean that outright in terms of doing maybe a volumetric production payment to be able to accelerate cash from that to then reinvest in accelerating the NAV out of the Marcellus, or am I reading too much into that comment?

Well, I think the asset sales are being more along the lines of what we've historically done. One of the rules at Range is because they try to keep it simple, and 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, like the lawyers running around and review all the time, so that those aren't things we think are productive in the long-term trying to run a business. So we're going to stay away from production payments for the most part. We've got, I don't know what the total number is, but roughly 130 million, 150 million a day of production that's not from our big three. And we'll continue to take a look at that and high-grade that and look at the more marginal higher costs up. Just like what we have in the past, we'll continue to sell that stuff off and help generate proceeds. So I don't think there's going to be anything fancy that we're going to come out with. Like I said, we're not going to try to douse you with some kind of new, financial trick of the trade here. We're going to stick to our knitting, we're going to stick to what we've historically done. And again, I think there's a lot of different ways to spending the cash. If you look how Southwestern did what they did, have done, we obviously studied that quite hard and some other things. So we'll continue to look at things, and at the end of the day, again, the one thing that you can, I'll put the stake in the ground, so to speak, is whatever we do, we'll look at all the alternatives, and we'll pick the one that generates the highest NAV per share. So whatever it comes down to, that'll be the stake in the ground. David Kistler - Simmons & Company: Looking at the uptick 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 just being driven purely by the 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 guys are in the process of putting a propane line in place, so obviously, NGLs across that whole area would increase production like yours is going higher, where are we on that propane line and is it on schedule, et cetera, et cetera?

So let me talk about the production a little bit. We're not going to -- the bulk of that is going to be coming from the Southwest. That's the de-risk area. We're really building out a lot of infrastructure. What we got, the liquid ridge part of it, so all of that is going to be where the bulk of our drilling and bulk of production is. However, by the end of this year, we expect we will get production on from the Northeast, so that will start to contribute. But if you look at our acreage, 900,000 acres that allows us to grow significantly from where we are on the order of 8x over just from the Marcellus, the bulk of that acre, 600,000 of that is in the Southwest, and there's been a lot of industry drilling, a lot of our drilling, I'd say 90-plus percent of that acreage has been de-risked. So that's where you're going to see the bulk of our activity. In terms of the propane line, I mean, it's moving along as we thought, and we're pleased with -- there's some regulatory stuff they got to get through, but it's making great progress. And so we're right on scale in that, right on schedule. David Kistler - Simmons & Company: Just a clarification, like, most of the production coming from the Southwest liquids ridge propane line, feels like it'll be done in time to ensure that there aren't any liquid-related issues there. Just trying to kind of check that box, more than anything else.

Yes, I mean, let me back up a little bit. The propane line, we're already doing propane down the pipeline even though the big line we're talking about is a longer-term issue that really deals with the ethane. And as we ramp up in the Southwest, we'll ramp up the ethanes. Currently, we're just selling the ethane in the back stream. We put just a little [ph] amount that selling of ethane because we get paid more. So that's what we're trying to do. We're trying to capture the whole gas stream there. The good news is that we dominate the liquid-richer, so a lot of this progress is going through us, and we're seeing a lot of different things. And the good news is that there's a lot of neat, creative things going out there, and so we're encouraged by that, and if you think over time, it'll continue to help the margins and whatnot.

And Marshall Carver with Capital One Southcoast.

The new bolt-on acreage at Nora/Haysi, I know you helped the mineral interest on the old acreage. What's the royalty on that new acreage?

1/8.

And 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'd suggest there is after the call, I mean, Rodney is trying to put out a lot more information on that split in mix, and so people can get pricing right. It's probably better, I would say, to just call Rodney. He can give you some of that detail.

And then finally, a question on the Huron and Devonian wells. It looks like you're encouraged with the initial results. Trying to think long term, it 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. So how would it be able to get capital or would you potentially sell that or JV it? What would your plan be on success here on Devonian Shales?

Let me clarify that, and so that it's really clear. The Huron potential is down in Virginia. That's on our existing Nora acreage, Haysi acreage and the new acquisition acreage. The Huron is a Devonian age shale. When we go up to Southwest Pennsylvania, and we're saying Upper Devonian, it's not Huron. It's Genesee briquette lines, Great Middlesex, it's an aggregate of those shales. And it's literally in Southwest Pennsylvania right on top of the Marcellus. And I wish I could actually, with a lobbing heart, to be able to talk about it in more detail because we have a lot of data and a lot of exciting data, but I can tell you, I'll say this, after drilling our first well, we're clearly ahead of where we were in the Marcellus at the same point in time. As we drill every Marcellus well, you're drilling right through that Upper Devonian package. We've now drilled and completed our first well. We have long-term testing on it. It'll be online later this year. We've actually drilled our second well and we will be completing probably by the end of September, and we'll have a third well. It's right on top of the Marcellus, so it's really going to help us with efficiencies. All those its lines and compression and gathering and everything, so literally like the same area. The acreage is -- there's no acreage cost; it's right on top of where we are. That has a huge potential, I mean the potential, when you look at Bcf per mile off of Bcf logs, what's in the Upper Devonian aggregate is on par with what we have in the Marcellus. So it's extremely high upside. So it's not -- it has fantastic potential. That was a very general answer, and hopefully, whether it's the next quarter or the following quarter, we can get more specific. But so far, I just say we're encouraged. And well, for total clarification, we have Huron down in Virginia, and the whole of that acreage is perspective for the Huron. You have Upper Devonian basically in Southwest Pennsylvania, and then there's a third upside in the Utica Shale, which is below the Marcellus. And again, we've drilled and completed our first unit of well, have long-term testing. We will be spreading another well probably early in the first quarter of next year. And there's tremendous upside in the Utica as well, so you have three horizons.

Our next question is from Ron Mills with Johnson Rice. Ronald Mills - Johnson Rice & Company, L.L.C.: Jeff, on the 2 to 3 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 or three years or even longer?

Well, let me start with where we've been historically, and then I'll, in big 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 per day, net, onto the Marcellus. At the end of 2009, we tripled it or we actually quadrupled it to 100 million per day, net. The end of this year, basically, we'll double it, 200 million to 210 million. And we're giving guidance for end of 2011 to double that again till we get to 400 to 420 million per day, net. That's the kind of trajectory that you'll see. If you look in our current book or current presentation out on our website, on Slide 13, I believe -- it's Rodney giving me the right information, you can see the Range hockey stick. You can take that, and you can get a French curve, which is what you'll need because it is exponential up. And you can project forward with where you think we'll be at the end of 2011. Once we go through that budgeting process that John talked and present to the board and walk down on where we'll be, I would imagine, sometime around the end of this year, we'll probably come out and ping out that euphoria. And I believe it's pretty exciting. I mean, again, you can look at the hockey stick, see where it has been, where it was going, and as we ping out that extra year, then I think you get a pretty clear feeling. And you can probably do it yourself with the data that's out there on when you think we'll break that. So that's exciting. I mean, a lot of people, I think, just to a little more color, and I tried to do it in my notes, and I know you guys go through a lot of presentations and a lot of conferences and everybody's talking about Bcf, but how many of those really materialize? How many companies have done organically and have been able to literally grow from 2 Bcf per day or two or beyond, and that's I can think of two, and since I've been in the business for 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, really strong economics. And that's really what's going to drive NAV, and like John said, that's what we're focused on. Ronald Mills - Johnson Rice & Company, L.L.C.: On the ethane production, it sounds like you're still keeping that in the gas stream for now. What will be the trigger point that gets you to start to strip that out, begin to sell it, especially given the current price situation for ethane?

Well, I think you got to remember, we always have a couple of options. I mean, one option is to continue to do what we're doing and to blend. And right now, we're getting paid for the Btus, and even after we strip out the liquids, which are really nice positive boost to our rate of return, we still get paid for the Btus. So after processing, we still have 1,140 Btu gas roughly. So we have the ability to keep blending, but like John said, since we have a dominant position there, a lot of those projects were critical piece, turning those projects going forward. And we look at them all to see what's optimum. Is it better to continue to blend long term, or is it better to break it out? And again, like John said, all this is going to be based on what maximizes NAV per range. Ronald Mills - Johnson Rice & Company, L.L.C.: And Roger, just a couple questions. On the G&A, you talked about 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 the increased staffing year you're undergoing up in Pennsylvania?

I think it'll be in that $0.57 ,$0.58 slot for the remainder of the year on. We're continuing to add staff and gear up the capital increase. You need more people, but again, like Jeff said, a lot of these expenditures are really -- their project expenditures were just moving from '11 to '10, so got to get extra people to handle that. So it's a little bit of a fast-forward and broad, too. So it's the eight-ish. Ronald Mills - Johnson Rice & Company, L.L.C.: And then finally on liquidity, can you walk through which is current liquidity is in terms of cash and under your revolver?

Yes, sure. Our borrowing base is currently $1.5 billion on our bank credit facility. That was just reaffirmed in March of this year, and our next bank meeting is in September. All indications are what kind of reserve performance we're seeing there is that our maximum conforming capacity will be above that $1.5 billion number by a considerable margin, but we don't have a need to access that. Our legal and binding commitment, Ron, is $1,250,000,000. And the way our facility works is we can send a notice with the agent and then we can increase from that $1,250,000,000 to $1,500,000,000 with 20 days notice among existing groups. So just see enough the $1,250,000,000, we've got $475 million outstanding, but that's a little misleading because we've got $160 million parked in that escrow. So you're looking at a net bank debt in the low $300 million against $1,250,000,000 in committed availability. So we're just under $1 billion in liquidity on a legally binding basis, and about $1,250,000,000 on a maximum volume base.

Our next question is from Gil Yang with Bank of America.

Granted you accelerate your activity, as you increase more NAV per share, I just want to get inside your head a little bit and think about what limits the ability to accelerate even more if you think that you can create NAV through this acceleration?

Well, I think when you look at it, a big driver was when we entered the year or at the end of last year when we set our budget, we went through the same process last September, October, November, December. We commenced with the number of wells we think, the rigs we have under contract of drill, and the reality is our technical organization with those same number of rigs can now drill more wells. That was a key part. So as we've gone up the learning curves, we really had two choices there. One is we could format 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 a fixed price than where we are this year, significantly better. It was great last year; it's even better this year. So our decision was rather than to format a rig, that's what prompts those points to the extent our team gets faster and faster with the same number of rigs. That's been accelerate production. And again, that acceleration, some people are looking at what did it do to this year, what does it do to next year, and we raised guidance both years. But I think actually, the question, and I think Ron asked it, where does it take you, where are you going to be out there in terms of breaking the Bcf per day. That acceleration helps you in 2012 and beyond because as you build those into an area, when you build a pan off of it, well, then you can combine and can build additional pans off the same road. You can drill additional wells off the same acreage. There is additional wells off the same path. So those efficiencies are what is going to drive of this. We're 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're about rate of return and NAV, and we let our technical team sort of dictate that. And we learn as we go. The good news is as the more we drill, the more the acreage gets de-risked. The more the industry drills, the more the acreage gets de-risked. So that 20-plus Bcf that we see at there right now is looking extremely strong. The production growth is looking great. The rates of return are better, and you're seeing it quarter-to-quarter, and our unit cost, they are coming down, as Roger's mentioned. So that's what drives our decisions.

So the increase in spending for the roads and the pads, et cetera for next that you're accelerating into 2010, again, a result of the more efficient drilling rigs that you've seen?

Yes, well, it's a combination of that, but also, as we're starting to develop in the Northeast, we're getting more efficient organization. In the Southwest, you're out in front of the mountains. When you go into the Northeast, you're up in the mountain, so you have winter in Pennsylvania. It's important in both areas, but pre-building some of that stuff in the fall and before wintertime, again, makes this more efficient. It's more cost-effective, it's a better thing to do. And as we ramp up in that area, we're pulling some of that fast forward because I talked about those two rates for our first two horizontals in Lycoming County being 13.5 million per day roughly each. Those are seven-day averages. So those are pretty impressive rates, and those are pretty strong wells when we finish. That's a heck of a shale well, so we're excited about that. We're up there drilling right now, and 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. And those are the things that drive us.

When you already have had capital in your budget for the Northeast expansion in terms of the accelerating, in getting out in front of a wintertime?

Well, we had capital. We have some capital in there, but it comes back to -- you remember, a lot of that capital, most of the capital predominantly is for the Southwest. That's for most of our infrastructure and most of our drilling is. But as you have the capital in there, we did our deal with PVR. PVR looks like they're on track. It looks it won't be delayed. It looks like it'll be, if anything, maybe a little earlier, so we want to pull some of that a little bit forward to make sure -- if we can get it on this year, we think that just continue with the great story that we have.

For the Talisman joint venture, of the $25 million, just like you said, how much is the total commitment to hold that acreage for that joint venture?

Well, it's really about developing acreage that we think is prospective. In that plan to develop the acreage or to maximize value of the acreage will not only drive our production but will hold the acreage. That capital does, in essence, both. It's not one or the other, it's both.

There's no quote. We haven't committed $100 million or $200 million or $300 million. It's just the normal operating agreement and when Talisman or Nashville [ph] sit down and decide how to drill wells and then either party can either commit or not commit to those wells, and you could -- see you have a little lever there where you want to commit capital or not. So it's not like -- it's much different in the JV, these financial JVs. This is a regular industry joint venture where you've got two industry partners, just developing an acreage position. And again, I think one of the things that's encouraging to me is that, that acreage up 14,000, 15,000 acres would not have been developed in the short term for us. So what we're doing is we're pulling that forward, that acreage forward in our NAV curve, and we're using the benefit, our Talisman technical team in their rigs and people to help us develop that. And I think it's pretty smart on our part to do that. What we have to give up is the day-to-day operations, which a lot of companies don't like to do, but obviously, Talisman's a first-class organization. As Jeff said, they drill from terrific wells up there. So we feel really comfortable with them. Not they will do a lot of these, but we're talking to different people about some of the stuff and other prices where we have bits and pieces of acreage that we're not going to get to in the short-term. It's a great solution to deal with that NAV issue in terms of pulling that forward into the NAV curve. So again, it's part of it. As Jeff mentioned, now when we have Talisman's team now working on that is that we brought Mark Whitley and his team from the Barnett Shale, and they're going to be working a lot on this Northeast acreage. So this time last year, we had one team working on it, now we'll have three teams working on it. We just think that makes sense in terms of bringing -- you're getting of them with three teams, and you only have one team. So again, it's pretty -- it's just the maturation of the process. You kind of learn as you go.

We will go to David Heikkinen of Tudor, Pickering, Holt for our final question. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: As I think about the acceleration of CapEx from 2010 into 2011, I'm thinking about that as a recurring talk that all these years, you pre-invest in roads and pads and the like. Is that a reasonable expectation or would CapEx actually drop in 2011 versus 2010?

So I think a better way to think about it is the total project CapEx is the same. We're just pulling it forward. It's as simple as that. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And you'll pull forward 2012 into 2011. I mean, it's kind of acceleration. That train target keeps going for roads and pads and the like.

Right, but you're pulling forward and increasing the rate of production, and the NPV of the project is greater. But the capital, the overall capital is the same. You're just moving it all forward, but you're moving the production and the reserves and everything else forward as well. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then just specifically on split of rigs running on the liquid ridge versus dry gas in the Southwest, do you have that?

Yes, right now, we just have one rig in the Northeast. All the other rigs are in the Southwest, and they're all in the wet gas. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then speaking about the Nora transaction, I know it's relatively small dollars and kind of a core area for range, but trying to think about how investing capital and blocking that up adds more NAV than investing more and just developing your huge Marcellus solution?

Well, I think it's -- again, I think we believe what our mission is to build NAV per share. And we've got some core areas in the Barnett and then Nora and the Marcellus, and we're going to continue to build on those. We think it makes sense when you look at the overall risk of the industry, and we've 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. And so when we see opportunities in these other areas, we think it's prudent from a risk prospective 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 then that was we had a little piece of Nora. I think going back to that, I think it was back in 2006, 2005. So we've been really disciplined on the acquisition side and not do anything because we've had this Marcellus opportunity. But we've had these opportunities in Nora, and we think they're exceptional. So we're going to go ahead and do it. And again, I think you got to look at the risk, the overall risk in the industry, in our company and just think through it. Do you want to put all your eggs in one basket? And we're obviously putting all our eggs in the Marcellus basket, but we think it's prudent to -- in an area like Nora, what we know so much about, we got a great team. I think Jeff mentioned we think the upside on those reserves is the 100-plus Bcf approved. We think that total reserve that size is close to 800 Bcf. So great, great long NAV-accretive acquisition. Do I think we're going to do a lot of those? No, and I think history shown over the last several years, we haven't done one. It's relatively small, and it's a perfect fit. So we think it made real good sense. And look, I think if you're going to be buying something today, I know a lot of people are rushing out to buy oil projects, but I got to tell you this, if I was an acquirer today, I'd be buying gas prop because I think there's substantial, more upside in gas prices than there are in oil prices. So again, that's a little bit of this jumping [ph] editorial in terms of the acquisition market, but we're not going to be a big player in the acquisition market. I don't think any shareholder should worry that we're going to run around doing some giant acquisition anytime soon. I think that you make a good point. We're going to stick to our knitting. We've got our sandboxes. We've got our terrific and we're going to continue to expand those. But again, from time to time, where we see little bolt-on or add-ons in these key areas, we're going to continue to try to take advantage of that. That's what we think that long term, that's what our shareholders want from us.

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