山脈資源 (RRC) 2005 Q2 法說會逐字稿

Welcome to the Range Resources second-quarter 2005 earnings conference call. This call is being recorded. All lines have been placed on mute to present any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question and answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you operator. Good afternoon and welcome. We recorded results for the second quarter of 2005 with a 28% increase in production and a 37% increase in realized prices over the prior year. We're pleased to discuss our results with you today. On the call with me are John Pinkerton, President and Chief Executive Officer; Jeff Ventura, Executive Vice President and Chief Operating Officer and Roger Manny, Senior Vice President and Chief Financial Officer.

Before turning the call over to John, I would like to cover a few administrative items. First, we did file the 10-Q with the SEC this morning. It is now available on the homepage of our website or you can access it using the SEC's EDGAR system. In addition, we've posted on the website supplemental tables which will guide you in the calculation of non-GAAP measures of cash flow and EBITDA that are discussed on the call today. Tables are also posted on the website that give you detailed information as to our current hedge position by quarter.

Secondly, Range will be presenting at several conferences in the upcoming weeks. We will present at the Intercom Conference in Denver on August 10, at the Lehman Conference in September and the IPAA San Francisco Conference in October. Materials being presented at each of these conferences will be available on our website just prior to the conference. Please remember to review our upcoming events calendar which is posted on the website for future events. Now let me turn it over to John for the call.

Thank you, Rodney. Before I turn the call over to Roger to review our first quarter financial results, I will review a few of the key accomplishments for the quarter. First on a year-over-year basis, production rose 28% to 232.8 million a day, beating the high end of our guidance. This marks the tenth consecutive quarter of sequential production growth.

Our drilling program was on schedule throughout the quarter and we continue to be very pleased with the drilling results and we are drilling -- generating some very attractive returns on our drilling. Through the first half of '05, we drilled 344 wells, a 78% increase over the first half of 2004.

Importantly, we maintained a (technical difficulty) rate off 97%. Currently, we have 27 rigs running, the highest in our company's history.

On the acquisition front, the integration of the June purchase of the Permian Basin properties in New Mexico has been completed with no negative surprises. Production is on track and drilling will commence next month with a two-rig program. This is slightly ahead of our acquisition economics which did not assume a second rig until later in the year.

On the cost side of our business, we're experiencing upward pressure like the rest (technical difficulty). Offsetting this is the fact that on a relative basis, our cost structure continues to be one of the lowest in our peer group and Jeff and our operating teams are really doing a great job in terms of trying the mitigate the impact. Despite the higher costs, we generated the highest unit margin in our history as EBITDA and cash flow also reached record levels.

Turning to our financial position, our balance sheet continues to strengthen. Long-term debt at June 30 was below that at year end, our debt to cap ratio fell to 47% at quarter end and our total debt now is only 1.7 times EBITDAX on a full year run rate.

Lastly, we believe that the long-term consistent growth in (technical difficulty) is a large -- the key to that is a large multi-year inventory drilling project. Through the combinations of the project that we (technical difficulty) generate internally through our technical teams, plus those that we have acquired through the acquisitions, we have expanded our drilling inventory to over 6000 drilling locations. Based on the 820 wells currently budgeted for 2005, this equates to a 7.5 year inventory.

Our inventory combined with our emerging plays provide for what we believe to be transparent growth for many years to come. The way we view it for the rest of the decade, it's not a question if our production reserves will grow; the question is how quickly and efficiently we can harvest the inventory in the emerging plays. With that, I will turn the call over to Roger to review our financial results.

Thanks, John. The second quarter of 2005 brought record revenues and cash flow. Continued success with the drill bit, the impact of our successful acquisitions and higher oil and gas prices drove the financial results. Also evident is continued balance sheet improvement with a decrease in our debt to cap ratio below the 50% threshold to 47% at quarter end. To help place the 2005 financial performance in perspective, our six-month year to date net income to common shareholders of 43.7 million exceeded earnings for all of 2004.

Now appearing behind the numbers, production volumes during the quarter were 28% higher than the second quarter of last year and realized prices on an Mcfe basis were $1.51, or 37% higher. Quarterly revenues were a record 120 million, 74% higher than last year.

Turning to expenses, last quarter we reported an increase in our per-unit operating costs due to higher oil field service costs. Now this trend continued in the second quarter as total direct operating cost was $0.82 per Mcfe versus $0.72 in the first quarter this year. Now the reason for the $0.10 increase was not so much higher service costs, but higher than normal workover expense. Workover expense totaled 2.7 million in the second quarter this year, or $0.08 an Mcfe higher than that experienced in the first quarter. The workover expense is primarily attributable to three large offshore Gulf of Mexico workovers. Excluding workover expense, the field level (technical difficulty) per Mcfe for the quarter increased $0.02 from the first quarter this year to $0.69. (technical difficulty) the third quarter, we currently anticipate total direct operating unit costs, including workovers, to be in the $0.74 to $0.79 an Mcfe range. This assumes workover expenses declined back to the normal range of between $0.02 and $0.06 per Mcfe.

General and administrative expense for the quarter decreased $0.02 per Mcfe and the G&A expense figure for the second quarter of 6.2 million was $400,000 lower than that in the first quarter of '05. Going forward, I would expect G&A expense to remain slightly higher on an absolute basis, but will likely remain level with the second quarter on a unit cost basis.

Interest expense increased during the second quarter due to higher levels of debt outstanding, the proceeds of which we used to finance acquisitions, and higher interest rates as we refinanced short-term floating-rate bank debt with fixed-rate long-term notes. On a unit cost basis, interest expense was $0.45 an Mcfe for the second quarter, and that's compared to $0.27 in '04. The higher interest expense is partially offset, however, by the absence in '05 of preferred dividends as all preferred shares were retired at year-end '04.

Although interest expense rose during the quarter, our coverage ratio remained strong as EBITDAX a covered interest by 9.5 times. That continued timing by the Federal Reserve will likely place upward pressure on short-term rates going forward. However, this should have limited impact on Range as our current fixed-rate debt percentage is 62% and that's up for 51% at June 30 of last year.

Our DD&A rate for the second quarter was $1.44 an Mcfe, $0.08 higher than the second quarter of last year, but $0.1 lower than the first quarter of this year. Exploration expense for the second quarter was 4.9 million higher than last year and 5.8 million higher than the first quarter this year due to 5.7 million of seismic expenditures. As is the case with interest expense and G&A expense, we not capitalize seismic expenditures.

For the third quarter, looking forward we currently anticipate exploration expense to be in the $10 to $11 million range. This includes approximately $4 million for seismic costs. Our dry hole exposure for the third quarter totaled approximately $1 million from the drilling of six exploratory wells. Based on the probability of success assigned to each individual well, we project third quarter dry hole expense will run between 4 and 5 million. Obviously, we hope that all of the exploratory wells will be successful and we therefore will incur no dry hole expense (indiscernible) is highly unlikely.

The non-cash deferred compensation plan mark-to-market expense continues to be a significant component of (technical difficulty) due to continuing increases in range of stock price during the period. Please remember that this non-cash expense item is included as an expense per accounting requirement, even though it does not represent current period cash contribution to the plan or (technical difficulty) benefits. (technical difficulty) Range stock and issue over a 10-year period into the deferred comp plan planned and the stock on the plan was fully expensed at the time of issuance and GAAP requires that the appreciation and the value of the stock held in the plan be reflected as an expense each quarter, even though the Company has no further stock funding obligations.

If the Range stock price goes up, an increase in cash expense is recorded and earnings are reduced. If the Range stock price goes down, the reduction to expense is recorded in earnings increase.

Our year-end '04, 237 million net operating loss carryforward continues to positively impact our income statement as there was no deduction for cash federal income taxes in the first or second quarters of '05. And as the NOL does not begin to expire until 2012, this trend should continue for us in '06 as well. Net income available to common shareholders for the second quarter of '05 totaled 21.7 million, or $0.26 per diluted share. The numbers comparable to analyst estimates would be income of 25 million, or $0.30 per share.

For the six months ended June 30 of this year, net income available to common shareholders totaled 43.7 million, triple the corresponding net income in the same period of last year. EBITDAX for the second quarter of '05 totaled 89 million and for the first six months of this year, EBITDAX totaled 170 million. These are both approximately 80% higher than the corresponding period of 2004.

Cash flow was up 83% from 43.7 million in the second quarter of '04 to 80.1 million and year-to-date, '05 cash flow totaled 152.6 million. As John mentioned, and as was the case in the first quarter of this year, both EBITDAX and cash flow represent record quarterly highs for the Company. As Rodney mentioned, these non-GAAP financial measures are fully reconciled on the Range Resources Website.

Turning over to the balance sheet for a moment, there were several positive developments in the second quarter. First, we successfully acquired at an attractive price Permian Basin property highly complementary to our existing properties in the basin and the acquisition was financed with the issuance 4.6 million common shares in a public secondary offering. And due to the equity issuance in our cash flow continuing to cover our capital spending, the debt to cap ratio fell to 47% at the end of the quarter. Our goal is to steadily work the debt to (technical difficulty) to 40%.

The second quarter of '05 provided an opportunity (technical difficulty) to utilize a portion of the stock repurchase authorization previously approved by our Board. A total of 133,700 shares at an average price of $21 (technical difficulty) be purchased in open market transactions during the quarter. These shares will be held in Treasury and used to fund equity-based compensation in '05.

Our hedging activity during the second quarter consisted of layering-in our first calendar year 2007 protection. Currently we have 50 million cubic feet per day of 2007 production hedge with collars having an average floor price (technical difficulty) an average cap price of $8.59 per Mmbtu. In addition, approximately 44 million cubic feet per day were added to our '06 hedge position, reflecting our recent Permian Basin acquisition as well as continued production growth. Our low-price gas loss continued to (technical difficulty) reducing our second quarter '05 wellhead price by $1.05 an Mcfe. We obviously look forward to the end of '05 when the last of these swaps expire. Presently, 91% of our '06 and '07 hedges are collars. A detailed (technical difficulty) appears on the Range Resources Website.

In summary, the second quarter financial results continue to reflect growth in revenues and cash flow driven by higher production volumes and higher realized prices. Our core strategy of drill bit growth combined with disciplined complementary acquisitions is working extraordinarily well. Operating cost containment continues to prove challenging in this environment, however the bulk of our second-quarter expense increase stems from workover activity not (technical difficulty).

At the end of the third quarter of '05 and the stronger balance sheet and our debt to cap ratio the lowest it has been in over 10 years and from a financial perspective, Range is in the terrific position to build value for its shareholders for the foreseeable future. John?

I would like to compliment Roger and Dory Ginn (ph), our VP Controller and the rest of our financial and accounting group for an outstanding job this quarter. During the quarter, we switched over to an upgraded management information system and we were still able to report earnings slightly ahead of schedule, so Roger and Dory, a great job. I really appreciate the hard work. With this, I will turn the call over to Jeff Ventura, our Executive Vice President and Chief Operating Officer, to review the exploration and development activities. Jeff?

Thanks, John. I will begin by reviewing production. For the second quarter, production averaged 232.8 million cubic feet equivalent per day, a 28% increase (technical difficulty) 2004 and a 4 million per day increase over the first quarter of 2005. This represents the highest quarterly production rate in the Company's history, and the 10th consecutive quarter of sequential production growth.

The 232.8 million per day is (technical difficulty) 109.6 million per day, or 47% from the Southwest division; 92.6 million per day, or 40% from the Appalachia division and 30.6 or (technical difficulty) Gulf Coast division. This increase was due to the success of our drilling and acquisition programs. Approximately 73% of the Company's production was natural gas. For all of 2005, we're forecasting a 22% increase over 2004.

I will now review some of the highlights of each of our divisions. I will start with the Appalachia division where the Pine Mountain properties are working out extremely well. These properties are outperforming our original acquisition economics.

Production is currently running about 20% higher than the original projection. Current plans for drilling in Nora Field include 150 CBM wells and 20 type (ph) gas wells for a total of 170 wells versus the 110 wells that we assumed in our acquisition economics. The Haysi Field, which is contiguous to the Nora field, also looks encouraging. We operate the Haysi (technical difficulty) 70% working interest and a 12.5% royalty in 30,000 acres there. We gave the Haysi CBM potential little value in the acquisition evaluation because it was essentially untested. We've finished drilling and completing our first five CBM wells on the property. What is important is that these wells were approximately six miles away from the edge of Nora field, yet the gas content and thickness of the coals at Haysi is very similar to what we see in Nora field and the production to date is also very similar to typical Nora wells. We believe that the Haysi field, Nora field and Console Opus (ph) field will ultimately grow together and are in essence one giant gas field. Our acreage position in this area consists of 287,000 gross acres. Currently we're developing the acreage on 60-acre spacing (technical difficulty) the maximum upside case would be the 4780 wells would ultimately be drilled.

To date, about 100 CBM wells have been drilled, though there could be as many as 3980 additional wells to drill of which we've only booked 640, or 16% of those that has proved undeveloped.

Another possible upside to the Pine Mountain acquisition is the Widen acreage in West Virginia. This area contains a 77,008 block in which Range has a 100% working interest and a 100% revenue interest in 74,000 of the acres. The reason we own 100% revenue interest is that we own 100% of the minerals. We assign little value to the property, but it may have (technical difficulty). Since we acquire the property, we've been approached by two knowledgeable CBM companies who wanted to farm in the acreage. We declined their offer and initiated a study of the CBM potential of the property. The study has been completed and the analysis is encouraging.

As a result, we've proceeded to the next up of acquiring CBM cores and absorbing (ph) the cores in order to quantify the gas contents of the coals. The cores will be acquired within the next 30 days and the desorption (ph) process takes about 120 days. If this analysis comes back favorable we will (technical difficulty) PBM pilot project early next year. If successful and assuming 60-acre drainage, there's sufficient acreage to drill approximately 1300 (technical difficulty) acreage blocks. (technical difficulty) went down to Abington and visited with our staff there and really impressed by the office and the quality of the staff. Jerry Grantham (ph), Ian (ph) and the rest of the people there are really first-rate. I really like the area. I think that's going to be a really big growth area for the Company. The CBM potential is real and it has real significant upside.

In addition, some of the things that I've talked about, like Widen, could really grow as well as other things that we can do in the area. Particularly on the Widen, I've talked about CBM, but there is also a little bit deeper -- the CBM on Widen is about 1400 feet, a little bit deeper, it's 2400 feet of the plate holds a big lime. There could be 100 to 200 additional big lime wells to be drilled there, as well as there's a shale potential (technical difficulty) depth of about 4000 feet. An interesting block, given the size and when you look at the deep drilling, there's only four wells that go to about 4000 feet and there's only one well that goes to about 8000 feet. So that's a lot of outside in Widen, but again, I'm going to focus back. I think the big upside is in the Nora Haysi and in the coalbed methane.

Back to our CBM project in Pennsylvania, that is also moving forward. We have about 31,000 acres there and four different projects, and I will go through each of the four projects. On our Unity acreage, we talked about drilling five wells (technical difficulty) and we're encouraged enough to drill seven more wells there this year. We've finished drilling and completing all of those wells. And in regards to our Salem acreage, we're close to having all of our approvals in place. We're starting operations there. We've staged our first five-well pilot and our first well should spud later this year. We have two other CBM projects in Pennsylvania in our Chef Spring (ph) and Wilton (ph) projects and we've finished coring and desorbing the cores in both areas and the gas contents look excellent there, on par with what we had within Nora. Although the coals are thinner than Nora, both projects look very encouraging and we plan to initiate pilot drilling programs in each area early next year.

Our drilling program for the Deep Trenton (ph) Black River includes five wells back-to-back. We recently spud our first well and we drilled three deep in Bradford County in northern Pennsylvania and two wells in Washington County in Southwest Pennsylvania. Both areas contain grobbins (ph) that look very similar to the grobbins that are being successfully drilled by Talisman. By the time of the third quarter (technical difficulty) information on the first two wells.

In the shallow portion of the play in western New York, we drilled two exploratory wells in the first quarter which specifically targeted the Trenton Black River formation at about 3000 feet. (technical difficulty) tested 1.5 million per day at 1800 pounds flowing tubing pressure and during the last conference call (technical difficulty) well encountered promising shales and would be sidetracked. The sidetrack well was completed in the second quarter and tested at an open flow rate of 1.2 million per day from 2500 feet. (technical difficulty) vicinity of our previously announced Harper discovery. These well should be online by the end of the year.

We're also on target to drill 380 shallow wells in a tight gas play in Ohio and Pennsylvania. This compares to 270 wells that we drilled in 2004. Ramping up the drilling increases the net present value as well as speed to the conversion (technical difficulty) producing in the (technical difficulty) shale test in Pennsylvania and we pumped a large slick water frac on our first well in this play last October and finished a long-term test of the well. Our results were encouraging and we are drilling (technical difficulty) we've spudded the first of the three wells this month.

We also engaged Hodess (ph) and Associates who are the frac experts, shale and PBM experts in that part of the basin within Schlumberger to study the potential of horizontal drilling in this shale and (indiscernible) Beck (ph) to study the total organic carbon gas in place and thermal maturity of the shale. The results of these studies are complete and look encouraging. Our plans are to drill a horizontal well in the fourth quarter. (technical difficulty) position has increased from 38,000 acres to 65,000 acres and we'll continue to build his position to over 100,000 acres. Assuming continued positive results, we would then anticipate going to full scale development in 2006.

In the Southwest division, Range is continuing its infill drilling and refrac program in the West Fuhrman Mascho unit in Anthridge (ph) County, Texas. As a result of this work, the field is now producing at an all-time high of 25.6 million per day, a 25% increase year to date. The technical team and field personnel working this area have done a superb job.

At our Conger (ph) Field in West Texas, we started a 20-well drilling program in March. We plan to pick up the second drilling rig in this area in August. The technical teams are continuing to do a good job of increasing production in our Bel Verde (ph) area of West Texas and our lower Lavell (ph) field in East Texas through additional drilling (technical difficulty) completions.

Our initial Woodbine (ph) discovery in East Texas came online at year-end and is currently producing about 7.5 million grobes (ph) for 1.4 million per day net. In the area of the discovery, Range has nearly 15,000 acres of lease holdings with working interest bearing between 25 and 100%. Also in the area, Range has a 25% interest and approximately 30,000 acreage of leasehold options.

In addition to the zone that we tested, there's significant (indiscernible) potential in the (technical difficulty). The next well just recently spud (ph) and Range has a 25% interest in this well. Range will operate and have a 50% (technical difficulty) another well, which is scheduled to spud next month.

We will spud our first well on our newly acquired New Mexico properties within a week. We will pick up the seconds rigs here in August versus our original projection within October, so we've been able to accelerate that. We're projecting the producing rates (technical difficulty) by the end of next year. The integration of these properties has gone very smoothly and we're working on adjacent farmings (ph) to increase our drilling inventory.

In the Midcontinent area, we've been able to run four to six rigs this year as a result of the significant increase in acreage (technical difficulty). Our production in this area has increased by 5 million per day net or approximately 18% as a result of this increased activity. We also just finished acquiring a new proprietary 3-D in our Courson (ph) Ranch area in the Texas Panhandle. Preliminary analysis of this data looks encouraging and we'll begin drilling the new prospects there later this year.

Offshore, Range has a 15% working interest in the West Cam (ph) 295 Number 2 Well which just recently reached PBM with Lock (ph). The well encountered over 150 feet of pay in two intervals. First production is anticipated late this year.

Range just finished drilling its fourth successful well in the Lalu (ph) area onshore South Louisiana. This well logged 26 feet of gas pay and currently is producing $6.4 million per day gross, or 2.2 net. Range operates the well with a 45% working interest. A fifth well is currently drilling.

We had a 25% working interest in a high potential Norfolk (ph) well onshore Mississippi which is spud in the fourth quarter.

In summary, we're in great shape to achieve 22% production to for 2005. 2005 is projected to be an excellent year for Range and I'm excited and focused on the future. Range now has a proved reserve base of 1.3 Pcf of solid long-life properties. Our reserve life is now 15 years.

In addition to that, we have discussed our drilling inventory, which contains over 6000 locations that equate to 1.45 Bcf of net unrisked reserves of which about 70% or 1 Bcf is unbooked. This is a large, multiyear inventory of projects that consists mostly of low-risk, highly repeatable development projects complemented with several higher-risk, higher potential exploration contracts.

In addition to that, Range has well over 1 Pcf of net unrisked reserve potential in its emerging plays. These are primarily technically-driven resource plays involving coalbed methane, refrac and recompletion opportunities win our existing (technical difficulty). So in total, we have 1.3 Pcf (technical difficulty) 1 Pcf of met unrisked unbooked reserves in our drilling inventory and more than 1 Pcf of net high unrisked reserves in emerging plays. (technical difficulty) depending on one or two projects for our future growth. Having a large high-quality drilling inventory is the real key in my mind. One of the key strengths of Range is its portfolio, the other is its people. This is lead by a technical team that now consists of a total of 86 geologists, geophysicists, engineers and landmen (ph). This is a talented group who is responsible for all of the project that I've mentioned and they're continuing to generate exciting new opportunities.

The Company today is significantly different than it is one year ago. With our 72% reserve growth last year, we now have over 1.3 Pcf of proved reserves. Importantly, the reserves that we've added are long life, low decline rate, very predictable reserves. e now have a larger, more stable proved reserve base. We also have (technical difficulty) net unrisked reserves potential.

To help put our portfolio in perspective, I'll list a few of the key projects. Roughly 3000 drilling locations in the shallow type gas pan (ph) plays in the Appalachian basin, of which 1000 -- approximately 1000 are not yet booked. We have about 4000 potential coalbed methane locations in Nora and Haysi fields, of which over 3300 are not yet booked. There are numerous identified Trent and Black River grobbins on our acreage that are undrilled. There are 80 additional locations to drill in the West Fuhrman Mascho units as well as significant additional refrac and waterflood potential which will continue to add production in reserves there.

There are over 50 additional locations to drill at Conger field. There is over 100 Bcf of net unrisked reserve potential in our Texas Panhandle and Oklahoma acreage and frac pays (ph) at the Morrow, Springer and Hunton (ph) formations as well as some shallower pays. We have approximately 65,000 acres on our Shale play in Appalachia. Importantly, we will continue to add the acreage in this play, which will increase the upside potential of the project.

In addition to the shale play, we have 100% working interest and approximately 20,000 acres on the shale play in Texas that has met unrisked reserve potential of about 240 Bcf. This is the play -- last time we talked, we had 16,000 acres; we've been able to grow that to about 20,000 acres and currently, there's a lot of activity in the area. In Canna (ph) and Burlington in particular, drilling is relatively close by our acreage and EOG is drilling further away. So by the end of the year, we should have good indications in terms of the prospectivity of that play, which is an exciting shale play out in West Texas.

The unproven coalbed methane reserve potential to our Pennsylvania acreage could be greater than 100 Bcf. The Norfolk play with the initial well to be drilled this year has the potential to be over 100 Bcf net while Woodbine and Austin Chalk have similar upside.

There are numerous other projects as well, however, hopefully, this gives you a feel for Range's portfolio and why I'm excited about the future. At this point, I usually move onto the conclusion, but I talk a lot about there's numerous other projects. But to try to put a little color on some of those, and the reason don't talk about them is that there's an appropriate time given the progression down the technical path that we go forward as well as acquiring acreage in everything else. But just to mention a few, the new Courson Ranch 3-D we actually have in-house and we have parts of it back from processing and there's really a lot of exciting opportunities on it, similar to the opportunities where we have success. But in addition to that, there's some exciting new exploratory and development plays that we will be drilling off that later this year. So that is looking really encouraging.

In Northern Oklahoma, we have a shallow oil play that we haven't talked much about because we're continuing to build our position, but we've drilled on it. We've had some very encouraging results. We've got a good acreage position which we're continuing to grow and we'll be shooting at 3-D there in the third order.

We talked about the shale opportunities in the Appalachian basin, but specifically the one shale play (technical difficulty) shale plays that we have in the basin that we have identified that earlier in the stages of evaluation that look pretty encouraging and remembering again that we have an acreage position there of approximately 2 million acres. We have a huge acreage position and I believe there's lot of good shale opportunities on the acreage we have, and this is addition to the play that I talked about earlier.

And then in Oklahoma, we have a deep Springer play that will probably drill next year. We have acreage on it, we're accumulating more acreage, but it's a very exciting play with big upside for Range.

(technical difficulty) to talk about. I think the moral of the story is we have a strong technical team. It's not just the portfolio that we talk about it in our portfolio in emerging plays but we're continuing to add and build to that. At the end of the day, it is a fairly simple business. The key is just to grow production and reserves with good planning and lift (ph) costs. The hard part is to do that consistently over time. But with our technical staff and large drilling inventory and 2.6 million acre leasehold possession, we're well positioned to do just that. Back to you, John.

Thanks, Jeff. I think I was a terrific update in terms of where we're -- what's going on in terms of the E&P side. Why don't we just turn to the second half of '05. Obviously we're looking and think that we're in good shape to continue to deliver stock operating and financial results. We're looking for third-quarter production to come in at rough (technical difficulty) 44 to 245 million a day. This is a think jump of approximately 12 million a day or 5% higher than the just-completed second quarter. So a nice job there from second to third. So we have our work cut out for us.

Concerning the third quarter '05 revenues, obviously they're expected to continue to rise due to the higher production and stronger realized prices. Assuming the current futures prices and the hedges that we have in place, we anticipate third quarter price realizations to be in the $5.80 per Mcfe range. This is $0.20 higher than the $5.60 per M that we realized in the second quarter and $1.36 or 31% higher than the third quarter of 2004.

Once again, production revenues, cash flow and earnings (technical difficulty) should set record highs exceeding the second quarter results by a fairly healthy margin. In our review, the second quarter -- I mean the third quarter of '05 year-over-year comparisons like those of the first and second quarters are an important in that they continue to demonstrate the solid quarter-to-quarter execution of our business plan. And it all starts with production, which is (technical difficulty) mentioned we anticipate to come (technical difficulty) 244 to 245 a day. Second realized prices (technical difficulty) swaps are estimated to increase by 31%. As a result, oil and gas revenues are projected to exceed the (technical difficulty) by about $15 million or more.

Looking to the year-over-year third quarter, '05 revenues are estimated to increase by approximately 50 to 60% versus third quarter of '-4. On the expense side, (technical difficulty) we expect the expenses to increase at roughly half the rate of revenues. So our margins are going to continue to expand, which is obviously the key.

Looking beyond the third quarter, we anticipate production to continue to increase in the fourth-quarter results of 820 well drilling program. As Jeff mentioned, we have increased our '05 production growth guidance from 20 to 22% based on current futures prices. We anticipate per-share cash flow and earnings per share will increase sequentially in each quarter of '05.

For the year, cash flow is anticipated on an aggregate basis (technical difficulty) by over 60% and earnings per share are projected to nearly double. So as you can see '05 is shaping up to be a really terrific year for the Company. For the remainder of the year, we're obviously focused on the quarter-to-quarter execution of our business plan. While we're hopeful that additional exploration discoveries and attractive acquisitions will occur (technical difficulty) achieve our '05 goals. Executing our plan of success (technical difficulty) value for the year. We view additional exploration success for acquisitions completed in the second half of the year to be the icing on the cake.

Turning to the operations, while we're focused on getting our wells drilled and hitting our quarterly production targets, we also continue to expand our drilling inventory to make some solid progress with our emerging plays. I think Jeff did a good job of giving you a fairly good thumbnail sketch of those and then some of the other kind of newer projects that we are focused on. Just to echo Jeff, the technical teams have really done a good job in terms of bubbling up these new projects from the grassroots up. So my hat is off to them.

Again as Jeff said, we've got projects in the pipeline (technical difficulty) have potential well over 2 TCF of net unrisked reserve potential for roughly twice the size of our existing crude reserves, so plenty of upside.

Like Jeff did on the operating side, I'll spend just a moment here commenting at least on how I see Range is different today. First, our financial results for the full year 2005 should be top tier. Net income for the year should be in the $100 million range with cash flow approaching 350 million. Second (technical difficulty) swaps rolling off and increasing production 2006 where financial results should blow away those of 2005 as earnings are projected to increase by roughly 70% while cash flow will likely reach $500 million.

So from a financial perspective, there's little question (technical difficulty) results for '05 and '06 should be fairly impressive. That really gives the management team, gives us confidence to really focus on opportunities that we believe will grow NAB per share (technical difficulty) focus in on short-term fixes. As I mentioned earlier, the question is not whether we're going to grow production and reserves, but how quickly and efficiently we can really harvest this very large multiyear inventory of drilling projects and these emerging plays that we're working on.

As Jeff said, the key element I really see is our technical and operating teams. As Jeff mentioned, we now have 86 technical people on staff and we are aggressively looking to add more high-quality professionals. We believe our technical teams give us real competitive advantages in the areas we operate. We don't plan to expand out of those. We have plenty of room in the sandbox (indiscernible). It's really these technical teams and these individuals who are coming up with ways to enhance our existing properties and use these techniques to generate new drilling prospects and acquisition opportunities.

So it's the combination of our organization and a very large multiyear inventory that really places Range in our view in a very strong position. The important parts on drilling inventory are one, as Jeff said, it's anchored by a large number of lower risk repeatable projects. It is diversified into a number of different plays and we also have a number of high return plays that if successful will fast-forward our growth.

On top of that, we have several meaningful emerging plays that could really be life-changing like the CBM and the shale plays.

So when you conclude it, in our view, we really have completed the riskiest portion of our strategy. We have successfully built a sizable long-life asset base coupled with a very large multiyear (technical difficulty). We certainly thank all of the shareholders for their patient's during this phase. We're now focused on really harvesting this drilling inventory while aggressively pursuing these high impact projects such as the CBM and the shale plays and then some of the different deeper drilling plays, like North (indiscernible), Woodbine, the Trenton Black River and (technical difficulty) plays that we've been working for several years. So we have a plethora of different opportunities here. We really believe that we're in an outstanding position (technical difficulty) deliver attractive growth in an NAV per share over the next several years.

In conclusion, while we are well positioned and it seems like we clearly have the wind in our sails, we fully understand the key is to continue the execution quarter by quarter of our strategy and we continue to maintain severe vigilance and discipline. As shown in the building of our drilling inventory, we will not sacrifice the long-term for the non-repeatable short-term gain. The second quarter results in our view really is (technical difficulty) benchmark and we look forward to reporting (technical difficulty) second half of the year. With that, operator, why don't we go ahead and open up the call for questions.

(Operator Instructions). Phillips Johnston, JP Morgan.

John, can you give us some commentary I guess on the M&A picture that you're seeing right now in Appalachia?

Clearly the (technical difficulty) domestic U.S. is red-hot. It has always been competitive, but it's particularly competitive in this environment. And in Appalachia in particular for a number of years there, we kind of had the whole sandbox to ourselves. Now obviously there (technical difficulty) players in the basin are getting more active. And in a way, we think that's good. We think it's going to give more -- a little bit more spotlight on the basin and what not.

On the other side, it obviously makes the acquisitions were difficult. That being said, it is a huge basin. As we said, it is the largest onshore basin in the U.S. so there's plenty -- we think there's plenty of room so we're not overly concerned about it. So it's not something we stay up at night and worry about, but it has gotten more competitive, no doubt about it.

But I think we really understand and have a pretty good idea of the kind of properties we're after. As I have set over and over again, we're just not out looking to buy properties that have a long reserve life and a decline at a shallow. What we're really looking at is trying to find properties that three years from now, we're going to be able to dramatically increase the production compared to when we buy them. And that takes a big technical team. It takes a lot of experience. It takes (technical difficulty) being in the basin for a long time, being aggressive when you need to be aggressive, being able to hit the ground running, having the operating teams, the pipelines and all of the other things in place. So we think we're in good shape, we have great competitive advantage in the basin. So we still think we're in good shape. We continue to look at things from time to time up there. We're looking at a number of things currently. But whether we will be able to buy them at an attractive price, who knows. But it's tougher, but every basin in this price environment quite frankly is pretty tough.

On the Trenton Black River play, have you guys had any recent conversations with Talisman about (technical difficulty)?

I don't think we can comment specifically, but I think in a general sense in the areas where we have acreage, Talisman and a number of other companies also have acreage as well. So I think from land department (technical difficulty) conversations going on in terms of combining acreage and doing joint ventures on particular prospects or wells just to make it more convenient and to make it a lower risk, sharing the risk, so to speak. So those conversations go on all of the time.

In terms of the larger deal, I think the best thing to do is just not comment until when and if something ever happens. But again, a good company, they've got some great technical people, they're doing a great job in the basin and we just hope to match them one day.

Last question is for Jeff. On the Texas shale (technical difficulty), is the strategy here pretty much continue to lease more acreage and just sit back and wait for some of these larger companies that you spoke about to drill wells, or are you guys planning to run seismic or perform coring or any sort of active to type of levels prior to some of these results?

We are to the extent we can pick up attractive acreage for the right price, we would continue to build that. The acreage position there is much competitive, much more competitive and much tighter. Jumping back to the Appalachian basin, we've gone from 38,000 acres to 65 and we'll build it to 100,000 and beyond. But in that particular play, the acreage is pretty tight. We have a good acreage position, we have lots of term on our leases. So our short-term strategy really is going to be to sit back a little bit, acquire acreage if we can at the right price, but watch and see what the results of some of these other guys are.

There's a lot going on in a relatively short period of time, there's been a lot of leasing going on and then there's a number of companies I think Jeff mentioned -- there's a number of wells being drilled as we speak. So very shortly here, probably within the next three to six months, there's going to be a number (technical difficulty) really (indiscernible) or quite frankly could condemn it. So we're going to know pretty soon here.

Yes I just mentioned three of the bigger operators within (technical difficulty) there's at least three other wells that will be going on with smaller operators right in the vicinity of where we are.

Alright, thanks.

John Wolff, Wachovia.

I'm just trying to understand the coalbed methane upside. I think you have 100 Bcf booked, and then you had put 150 into probables, and I think another 200 into your higher risk category. Can you just kind of help us think about that? It sounds like you have 3300 locations which is more like a Tcf, if it's 300 Mcf a well.

Yes. On the -- let me talk about the locations that you mentioned. Like we mentioned and it's on our website, there's a little (technical difficulty) out there and in the pitch book, it's summarized of that (ph), guide and I've walked through some of that today.

We have 640 of them particularly and it's all in the Nora area booked as puds. And on top of that, we have another 3340 locations that are unproven. So you take the 3340 and use something on the order of 300 million per well, that gets you to a little over a Tcf. Of that, net to us would be about 550 Bcf. So there's about 550 Bcf of upside just in the Nora and Haysi area. And that's what really excites me, because again, you can pull the maps up off of our website, but you have 800 wells on our acreage, (indiscernible) has a lot of wells on their acreage, there's a lot of core holes that were drilled to originally evaluate the area for core volume. So you have a really good feel for the coals and where the coals are and the distribution of the coals. Anywhere you drill on that hole's 287,000 acreage position, you are going to find coal, and we also know the gas contents in the coals and they are excellent out there. So you're going to find gas and you're going to find coal and it's very low risk. We have conservatively booked it according to SEC, we're literally just one well off to an existing well and it's called a pud. But all of those other locations are extremely low-risk. So the book there is unproven is very low risk opportunities.

The other important thing to remember about that is, if you take an average well, cost to drill and complete is on the order of $250,000. And our cost to find and develop out there, given our working and revenue interest is about less than $0.80 per annum. So it's very low finding and development cost, lots of low-risk opportunities. And then to take it to the final step, when you look at the rate of return on those opportunities at a $4.00 flat gas price forever, that's a 35% rate of return and $6.00 flat gas price at 64 and at current strip pricing, your rates of return are going to be on the order of 100%. So lots and lots of opportunities, low-risk and with great finding costs and rates of return.

And then with the upside beyond that (technical difficulty) Pennsylvania coalbed methane coverage be (technical difficulty) as well as we are always looking for other and new opportunities there to build the inventory. We like that play a lot and we like those opportunities.

So is the 550 just Nora (technical difficulty) or does it include Widen?

No, that's just the Nora Haysi area. that doesn't include anything for Widen or for Pennsylvania CBM.

So if you had to think of that (technical difficulty) your probables and possibles today, would you -- it's more like 50 that the (multiple speakers) you had estimated?

Say in the probables and possibles (technical difficulty) order of 550, plus to that add another 100 Bcf net or (technical difficulty) Pennsylvania plus Widen. It's to early for me to put a number on in it, but I did it using acreage. Given the amount of acreage, we would have over 1300 or about 1300 locations. And the reserves per well are going to be a function of these desorption tests that we're running. So before I can give you a reserve number, I need to get a feel for what's the gas content of the coal, which we will announce when we get those, which will be somewhere around the end of the year, early next year.

Thank you.

Ron Mills, Johnson Rice.

Good afternoon. You've answered a lot of questions. In terms of the Permian acquisition properties from June, the second rig obviously getting there a couple of months early as a positive, can you just update us on what your drilling plans are in terms of number of wells you hope to get drilled in that area?

Basically, we plan on keeping those two rigs really through the end of this year and really on into the first half of next year. And then of course, we will evaluate it as we go. But we have a number of identified low-risk drilling opportunities out there, plus we have probables and possible opportunities we will be looking at as well as expanding through opportunities that are off our acreage that we're in contacts with. Again, back to what is out on our website as far as the number of wells that we see, there is a firm 41 wells that we've listed, along with 17 recompletions. But in time, I believe that number will (technical difficulty).

Okay. And as it was relates up to the Appalachian basin with Console (ph) creating their natural gas unit, does that have any implications for you in terms of activity levels, are you all partners with them in any properties that may be accelerated as a result of that, or I'm just trying to get a sense as to what (technical difficulty)?

We don't have (technical difficulty) right now and it really has nothing, no impact (technical difficulty) in terms of the "competitive landscape." Just to give you a feel, we are drilling 150, 175 coalbed methane wells this year, but these are relatively shallow wells. You drill two wells a week. So there's no real issue in terms of getting rigs. The takeaway capacity in the systems are fine. (technical difficulty) the upside case works, we will be happy to (technical difficulty) we have those issues.

So from our perspective, we have had a lot of people ask us about the Console planning and from our perspective (technical difficulty) it's positive because I think it would get more data out in people's hands and it will give people a better idea of some of the upside and range. But it really has no impact operationally in terms of what we're doing.

Okay. And then from (indiscernible) looks more and more like it's going to spud by the end of this year. Can you walk us through some of the items that in terms of drilling the well, if successful, how soon could it come online, how many locations (technical difficulty) do you think you have in that area and what kind of terms you have from a partnership standpoint?

(technical difficulty) some of that again for people that are not quite as familiar, the analog to that is Mobile Bay offshore (technical difficulty) those wells average about 50 Bcf a well. They're deep, they're below 20,000 feet. And what is unique about them, they have a very specific seismic character. So on the 3-D survey (technical difficulty) identified growth, about 1.6 Bcf of potential. And then of course, that's growth on risk. Our working interest in that will be 25%. So off of that 3-D that we have identified, net to us, you're looking at about 320 Bcf kind of net unrisked potential. And we think the wells if they work could average on the order of 50 Bcf a well. And those are natural completions.

There's a lot of capacity to produce that. Mobile Bay was at its peak years ago, so there is a lot of additional (technical difficulty) to produce that (indiscernible) pipeline takeaway capacity in the area. The other key thing is if it works, it's not going to be just on this 3-D; there would be (technical difficulty) and that trend would continue. So that is where we are. Our first well (technical difficulty) later this year probably plus or minus November. They're deeper wells, so you are going to be looking at 100 days plus to drill, so you're going to be looking at result towards the end of the first quarter. And again, going back to our drilling pyramid, we show that our inventory in terms of a pyramid. This is higher potential, but it's also higher risk, as opposed to something like Nora that's really big potential but is relatively low risk.

One last one for Roger, since we have not heard you in a while. In terms of your CapEx, the 262 million (technical difficulty) moved up to you after the Permian acquisition. Is that still remaining intact? Is there any potential for increasing that if for no other reason, the cost increases you all alluded to earlier?

That's a good question, Ron. Jeff and (technical difficulty) looking at (technical difficulty) the Board and it will be reviewed at our December Board meeting as well. You have schedule changes as you can tell from Jeff's remarks. Some of the wells have been pushed back, does it make sense to move some things around and accelerate some other projects. So it's a little bit of an Etch-a-Sketch. Will the number will go up? I think there's probably a good chance it will, but we will keep you apprised if and when we have that locked in for you.

I think some of these things -- I think the number will go up. We have not had anything authorized (technical difficulty) Board meeting this quarter that will discuss that with them. But there really is about three areas I see where we're going to increase capital. One is in the acreage acquisition side (technical difficulty) we have a lot going on. Jeff talked about the shale play in Texas. We've increased our acreage. Quite frankly, we have another one that we're working on that's in the infancy stage that we hopefully will get authorized some money on. And then we are trying -- we have a town of landmen working on our Appalachian shale play. As Jeff said, we want to take that from the mid 60's to 100,000 by the end of the year. So that is going to take some dollars. And then we have some other things we're working on too. So I think the acreage dollars will be increased, at least we're going to recommend it.

And then as I mentioned or Jeff mention, we fast-forwarded a rig onto the Permian New Mexico properties much faster than we thought, so that is good news. So we will add for some additional capital there as well. And then in some of our more boring things like Sterling and Fuhrman where we've had just really good success this year, it's just amazing how good our teams have done like at Fuhrman where we're -- I think we're up another 30% on production (technical difficulty) ask for more dollars there and we're actually going to go to a Phase II on another pilot water flat (ph) on that property. So that will add some capital.

So most of the things that we're going to ask for I would say 75% of it is going to be increased activity. The other 25% will probably be cost related. But the good news is that I think 75% of the increase will be for new activity, which is obviously the thing that drives value.

The follow-on to that question is, as you start to get close to that 40%, the GAAP target based on expected cash flows by year end, is that excluding future acquisitions, is that the level YOU'RE comfortable with? At which point would you think you would seek to extend the buyback that you did during the second quarter?

That is an interesting question. We have discussed that at the Board a fair amount. In terms of -- right now, we are at 47% debt to cap. Based on our rough numbers, we're going to be at the 40% just based on cash flow runoff, probably mid-next year and (indiscernible) before that. So we have some time to think about it. I think the key is just to be very disciplined. And once at least from my perspective and I'm one of nine Board members, but from my perspective given our reserve life, given our inventory, I don't see a lot of upside by paying off (technical difficulty) 4% bank debt. So I would be one that would (technical difficulty) of reducing the outstanding shares.

But again (technical difficulty) so we will see how it happens. Again, it's a great issue to have. We talk about it at the Board a lot. And again, I think you saw a little bit of it when we bought back a few of those shares when we thought that the stock was way low. So we will continue to the advantage of that from time to time. I think once the third and fourth-quarter numbers come out and we have a better view of it, we will talk to our Boards more and I think we can give you a more definitive answer Ron (indiscernible) on the third-quarter call and the fourth-quarter call.

Rehan Rashid, FBR.

On the Appalachian shallow (indiscernible) Black (ph) River, could you talk about what is the next step there? You have three discoveries now, just remind us again the acreage position and again the next step?

The next up really is to get those wells online. Those first three wells, that is a play in the first three wells. The first three wells, we had 50% working interest and those are outside operators for us. It has taken a long time for those wells to come online. The next step is to get them flowing down the pipeline, which should occur by the end of the year. But granted, it has taken awhile to do that. We have a good acreage position there. It's north of where the Trenton Black River production is. Again, it's a lot shallower. The other stuff is more in the 12 to 10,000 foot range. This stuff is about 3000 foot. So it's quite a ways north. We have 91,000 gross or 81,000 net acres there. Our average working interest is actually higher. It's 90% where the first few wells are were in the 50-50 partnership for (indiscernible) is the operator. So once we get these wells online, we will be acquiring additional seismic and then you will see additional drilling next year.

In terms of in spacing, is there any particular spacing requirements or how would you develop the area and any (indiscernible) as to how spread out it will be throughout the acreage position. Are the first few wells relatively close by each other and kind of you have to continue to step out?

They're in the same vicinity, but they're not right together. This is really a new play. There's no producing analog for these kind of wells and the flow tests on them were relatively short term on the order of three weeks, three days to a week max. So you're looking at wells that we think, we're hoping that maybe they will be in the 300 to 500 million cubic foot per well. But again, at depths of 3000 feet, that can be attractive economics. So there are no pre-set defined spacing requirements. They are drilling grobbins like we're looking for in the deeper part of the play, so you're looking -- it's not a blanket play like a shale play or like coalbed methane; you are specifically targeting those grobbins.

Okay, thank you.

Andrew O'Connor, Wells Capital.

John or maybe Jeff, from a qualitative point of view, how would you expect the risk profile of Range's ongoing exploration program to change or evolve over the next year or two relative to where it is today? Does that make sense? Or maybe can you take a stab at it in percent terms.

In our pitch book, we actually have a little pie chart in there that talks about (indiscernible) exploration and it's really been fairly consistent, even looking back a few years. And I predict going forward, it will probably be similar (technical difficulty).

So on a dollar-weighted basis, the exploration program maintains the same balance of overall risk going ahead? Is that right?

I would use the same percentages as the pie chart that is out on our website.

Okay, that is helpful. Thank you.

Robert Lent (ph), Simmons & Company.

Question for Jeff. I guess outside of CBM, how confident are you that going forward you will be able to access drilling rigs and other essential services to develop the potential inventory in Appalachia?

I feel good about that because our guys, we have a long track record up there. We've been in the basin for a long time. We have really good relationships. Steve Gross (ph) and his team dealing with the same people for a long time. They're not (technical difficulty) they are all smaller I won't say mom-and-pop, but they're not the big drilling contractors that you would be familiar with. So they're people we've known for a long time that have continued to supply us rigs. We're also advantaged in that we have very large acreage positions so we can keep rigs active in an area for a long, long time. It makes it easier on the drilling contractors and easier on their crews (technical difficulty) add anything to that John?

I think that's fair. From a global perspective, the further you get away from the Barnett shale plays, the easier it is to get rich.

That's all I had guys. Thank you.

Out of our 27 rigs, 15 of them currently are in the Appalachian Basin, so there's a bunch of them up there.

Jack Aydin, KeyBanc Capital Markets.

I have two or three questions. One starts with Roger. Roger, you mentioned about the operating costs (indiscernible). Correct me if I'm wrong. Are you looking for $0.69 or so LOE (technical difficulty) a couple of tenths (ph) for workover? Could you reaffirm that or repeat it? In the third quarter.

Yes, Jack. Of course you know workovers are terribly difficult to try to predict, particularly when you have a lot of the offshore non-op (ph) stuff. So generally though you can say they would run between two and six (technical difficulty) for the workovers. And the range I gave was $0.74 to $0.79, including the workovers, which if you saw it backwards, gives you a number in that 69 to 73 range for the base.

Okay. And Jeff, could you just and a little bit more color on the Appalachian shale play? I know you (technical difficulty) and everything. Could you add a little bit -- explain it a little bit more? And also, if you could give us a little bit more color on the (indiscernible) a little more to share with us?

In the Appalachian play, I won't get real specific, but I'll try to give you a little more color. You're looking at pretty reasonable depth on the order of 6000 feet. Again, it's a great place to do business. You're looking at rather than a deduct to NYMEX, you're looking at a 35% increase to NYMEX. We have aced (ph) leases, we're able to acquire acreage for very (technical difficulty) in the 20 to $50 an acre kind of ranges. So from an economic point of view, it's a very favorable place to do business. You have -- and also like John said, it's a very large basin. And the shale we're looking at has a lot of running room and a lot of variable extent, so it can be very repeatable.

So all those things are very favorable. I think based on what we saw in our first (indiscernible), and I don't want to get too specific, but you're looking at it's going to be more Appalachian Basin style reserves. You're going to be looking at lower rate wells (technical difficulty) flat declines and very, very flat basically very flat decline long life wells.

So we are (technical difficulty) we see on the first well and we've also done some modeling in terms of what a horizontal (technical difficulty) and other shale plays obviously in the Barnett and in the Fayetteville horizontal wells became very important. So we're looking at applying that technology as well. We're drilling our three wells in a row (technical difficulty) first well that we drilled are in the vicinity and then we will follow up later this year towards the end of the year with the horizontal well. So I would -- hopefully, that puts a little more color on that play for the --.

How much it cost you to drill a well and what is the economic? What do you need (indiscernible) on average to be -- for you to proceed full-scale development?

I think if we're able to get something on the order of literally close to a half a Bcf a well, and that is on a fairly reasonable price deck (ph), the economics will look good. So hopefully (technical difficulty).

How much will it cost you to drill a well like that?

You get into -- in the first few wells (technical difficulty) experimentation and then you're going to get into fine-tuning. If you could get a well in a development mode, I think could be on the order of $700,000. And based on what we saw in the first well, we think that we can (technical difficulty) just a three-month test, which is -- that's a reasonable time, but it's not putting it into a pipeline for a couple of years. We think that you might be able to get well in excess of a half Bcf. So we're encouraged by the first well we see. But it's early, it's just one well, it's just one data point. (technical difficulty) horizontal wells may dramatically alter that. But We think we're pretty encouraged by what we see so far.

Okay. How about the West Texas area? Could you add a little bit more color?

The color there is that -- going back to the Appalachian Basin and the Devonian shale, which is the play we're making, within the Basin which is huge and we have it on our website (indiscernible) study by Colorado (indiscernible) Mine just a couple two or three years ago where they talked about the potential in the shales in the Appalachian Basin of recoverable gas potentially being in the 14 to 28 Pcf range. So it was a huge number. And then in the Appalachian Basin and in the Devonian shales, there's actually a Big Sandy Field down in the Eastern part of Kentucky that laps over into West Virginia that has made over a couple of Bcf, so you have a great producing analogy for the Devonian shales. Granted it's fractured and it's a little shallower, but there is (technical difficulty) production from it.

And then if you go out into West Texas into the (indiscernible) and Culverson and some of the surrounding counties and look at the shale play there, which is a Barnett play and a Woodford play, there are no tests of the Barnett and Woodford anywhere out there. The analog for that is the Ft. Worth Basin and the Ft. Worth Basin now is of course producing over a Bcf a day out of the Barnett Shale. But when you -- Is the same shale and it's the same interval, but when you go out into West Texas in that particular Basin, it's deeper. It depends on where you are in the Basin but, it is quite a bit deeper. It is also quite a bit (technical difficulty). So it's deeper, it's high-pressure, it's thicker. That can be more positive, but there are no tests for it anywhere out there. These first (technical difficulty) EOG (ph) and Canna (ph) and Burlington as well as a couple of smaller independents are the new test in the basin. If it works, it really could open up a big area, but obviously (indiscernible) has not tested it, it's higher risk.

Thanks.

Howie Plinker (ph), Plinker (ph) Company.

It's close. Hello everybody. What is your scheduled CapEx for this year?

Right now, it's $261 million.

For the year?

Yes.

(technical difficulty) 27 million on one acquisition in the second quarter alone.

Without acquisitions.

Without acquisitions. (technical difficulty) what would it be?

Right at 400.

Around 400, okay. And two administrative items. One, in your schedule of swaps for '07, on page 8, there is a typo. It says calendar year '07 then the quarterlies say '06, so you might want to correct that.

Okay.

And second, unless I missed it, did you print complete cash-flow statements for the quarter (technical difficulty) or just a partial with the complete cash-flow statements that some with the 10-Q?

The Q has the complete one. What we show you there is a reconciliation to what we use as (technical difficulty) which is just basically it doesn't have the investing -- the other two parts below that.

I just wanted to make sure I didn't miss it.

That's what we typically we have done.

Okay, that's it, thanks.

Vedula Murti, Tribeca. (OPERATOR INSTRUCTIONS) Brad Beago, Calyon Securities.

Hey, guys. Most of my questions have been answered. Just real quick -- you're clicking on all cylinders on the drilling front clearly. If you just look at the core development projects, not assuming anything from some of the exploration (technical difficulty) what kind of a percentage would you put on production growth next year?

We're looking for production -- if you just take '05 production and then you compare it to '06, what we think we're going to have, we're going to have (technical difficulty) somewhere between 10 and 12%.

Very good. Thanks a lot guys, good quarter.

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

Thank you all for (technical difficulty). We are obviously very pleased with the second quarter results, the continued production growth. As Roger mentioned, we will pop a bottle of champagne when our low-priced hedges roll off at the end of '05 and I am sure a number of shareholders will do the same thing. We are very -- I think Brad Beago mentioned at least it's nice enough to think that we're hitting on all cylinders, but I think we're not naive enough to know that we have to work every day and prove it every day and every quarter. As I mentioned, I think the key (technical difficulty) is just this very large multiyear (technical difficulty) a cushion and to know that we can grow our production year in and year out through this decade. And then coupled on top of that, I think our technical teams and then with Jeff Ventura's leadership from our technical side, they have just done on a wonderful of bubbling up new projects and my hat is off to them. We feel very confident but we are also -- everyday wake up and have to do it again. So we are very cognizant of that. Again thank you all for your attendance and we look forward to having even better earnings and results third quarter. Thank you.

Thank you for participating in today's conference. You may now disconnect.