山脈資源 (RRC) 2005 Q3 法說會逐字稿

Welcome to the Range Resources third quarter 2005 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 afternoon and welcome. Range again reported record results for the third quarter of 2005 with a 16% discretion in production, and a 43% increase in realized prices over the prior year. More importantly, substantial progress was also made over the results from our second quarter 2005 in spite of two hurricanes. We are pleased to discuss our results with you today. On the call with me are; Charles Blackburn, Chairman of the Board, 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'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It is available on the Home Page of our Website or you can access it using the SEC's EDGAR system. In addition, we have posted on our Website supplemental tables, which will guide you in the calculation of the non-GAAP measures, cash flow, EBITDAX and cash margins that are discussed on the call today. Tables are also posted on the Website that will give you detailed information of our current hedge position by quarter.

Second, Range will be presenting at several conferences in the upcoming weeks. We will present at the J.P. Morgan Small Cap Conference in Boston next week, the Bank of America Energy Conference in Florida on November 15, and the Friedman Billings iNvestor Conference in New York City, on November 30. Materials being presented at each of those 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. Now, let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the third quarter financial results, I'll summarize the key accomplishments for the quarter. In summary, we were very pleased with the third quarter results. On a year-over-year basis, production rose 16% to 244.1 million a day, achieving our guidance, despite the impact of the hurricanes. This also marks the 11th consecutive quarter of sequential production growth. The fact that we achieved our original guidance despite the impact of the hurricanes is a real testimony to our operating teams. They should be applauded.

Our drilling program was on schedule throughout the quarter. Through the first nine months of '05, we drilled 613 wells, more than double the number of wells we drilled in the same period last year. We continue to be very pleased with our drilling results, as we're generating extraordinary high rates of return. Our 15 million a day Texas Panhandle well and our 20+ million a day east Texas wells are particularly encouraging. And we think this reflects the quality of our technical teams and the projects they generate. Currently, we have 32 rigs running, the highest in our Company's history. So we expect to have a solid finish to the year.

On the cost side of our business, we, like the rest of the industry, our expending upward pressure. That being said, we were able to moderate the impact in the third quarter as operating costs averaged $0.74 in mcf versus $0.77 in mcf in the first half of the year. During the quarter, we generated the highest cash margin our history, a whopping 55% higher than the prior year. Lastly, we believe that the key to long-term consistent growth and profitability is a large multi-year inventory drilling projects.

We've expanded our drilling inventory in the quarter to over 6,800 projects. Based on the 824 wells currently budgeted for 2005, this equates to an eight-plus year inventory. Our inventory combined with our merging plays provides transparent growth for many years to come. From our perspective, it's not a question of if our production reserves will grow. The question is how quickly and efficiently can we harvest the inventory in the emerging plays. With that, I'll turn the call over to Roger to review our financial results.

Thank you, John. The third quarter of 2005, again, brought record revenues and cash flow. But perhaps the biggest financial story for the quarter is actually an operating one. The resilience our Company exhibited in offsetting the shut-in production caused by hurricanes Katrina and Rita is a true testament to the resourcefulness of our people and the performance of our drilling program.

Like last quarter, continued success with the drill bit, the follow-on impact of our successful acquisitions, and higher on-gas prices drove our financial results. Quarterly revenues of 141.8 million were 65% higher than last year and 19% higher than the second quarter. Year to date, realized oil and gas prices were 43% higher than last year. So, while there has been upward pressure on operating expenses throughout the industry, as John mentioned, in the third quarter we were able to hold the line on operating expenses compared to the first half of this year. In the third quarter, workover expense, that's the item that most significantly impacted operating costs last quarter, declined from $0.13 per mcfe to $0.06 or from $2.7 million, to $1.4 million. Direct operating costs per mcfe in the third quarter averaged $0.74, which is lower than the $0.77 experienced in the first six months of this year.

Looking to the fourth quarter, we currently anticipate total direct operating unit costs, including workovers, to remain in the $0.74 to $0.79 range. Fortunately, higher oil and gas prices and higher realized prices from our lower priced hedges rolling off continue to drive margin improvement despite a higher cost environment. Cash margins were up 55% over last year, and 20% over last quarter. General and administrative expense for the quarter increased $0.05 per mcfe to $0.32 from $0.27 in the third quarter of last year. The increase was primarily attributable to salary, benefit and occupancy costs associated with acquisitions, and a larger work force. Going forward, I expect G&A expense will continue to increase slightly on an absolute basis as we continue to hire personnel to help execute our larger 2006 drilling program.

Adjacent to general and administrative expense on the income statement is a noncash stock compensation amount of 20.1 million. This consists of two components, a 17.5 million mark-to-market expense, associated with Range stock and marketable securities held in the deferred compensation plan and a 2.6 million mark-to-market expense from Range stock appreciation rights or, SAR's. I'll now take a moment to explain these items in greater detail as they are unusually significant this quarter. The 17.5 million noncash expense is largely due to the $11.73 increase in Range stock price from the end of the second quarter to the end of the third quarter. And our deferred compensation plan, there are approximately 1.4 million Range shares issued over the previous 10 years. Now, these shares appear on our balance sheet, much like Treasury Stock, at cost in the Stockholders' Equity section. But the benefit plan value of the shares must be carried at market. So, the noncash valuation entry used to reconcile the cost basis of the Range stock to market, is run through noncash stock compensation expense.

Now, perhaps the best way to explain how this expense works is to simply multiply the quarterly change in our stock price by the number of Range benefit plan shares appearing on the balance sheet. It should be noted that in the third quarter, Range stock price closed at $38.61. Now, to the extent that the Range stock price at the end of the fourth quarter is higher than 38.61, we will have additional expense. And to the extent that the stock price closes below 38.61 at the end of the fourth quarter, we'll have a negative expense. We view this accounting treatment as confusing and illogical, but again, GAAP doesn't always seem to may be sense.

Now, besides the 17.5 million, there is a 2.6 million in mark-to-market expense item from stock appreciation rights. These are stock appreciation rights issued to our 525 employees earlier this year. Equity settled SAR's continue to align our employees with the interests of our stockholders. But reduce by more than 50% the dilutive effect of using stock options. Under the new equity based compensation rules going into effect next year, equity settled SAR's, are accounted for the same as stock options. And, therefore, we believe SAR's are a better way to go versus stock options.

Interest expense is greater than last year due to higher levels of debt outstanding. And higher interest rates as we refinance the 150 million of our short term floating bank debt with fixed rate long term notes in March of this year. We expect interest expense in the fourth quarter to increase slightly due to higher rates. Our DD&A rate for the third quarter was $1.47 in mcfe, a modest $0.10 higher than the third quarter of 2004. Total exploration expense for the third quarter was $7.2 million, or 2.6 million higher than last year, due to a 3.4 million increase in seismic expenditures.

Looking to the fourth quarter, Range has approximately $19 million of dry hole exposure in its drilling schedule. However, based on our estimated probability of success, our dry-hole expense for the fourth quarter is estimated to be approximately $6.5 million. Making our total projected exploration expense in the fourth quarter approximately 10.5 million. As Jeff will discuss in a moment, we experienced excellent exploratory success during the third quarter. And while we hope this continues, as we all know, exploratory outcomes are uncertain. Our $226 million net operating loss carry-forward continues to positively impact our income statement. As there was only a $331,000 state income tax expense for the third quarter. The Federal NOL carry-forward does not begin to expire for several years so we currently don't expect to pay cash Federal income taxes for the rest of '05 or all of '06.

Net income available to common shareholders for the third quarter of '05 totaled $24.7 million, or $0.28 per diluted share. Numbers comparable to analyst estimates for the third quarter would be net income of 37.6 million or $0.43 per diluted share. For the nine months ended September 30, 2005, net income available to common shareholders totaled 68.3 million, 168% higher than the first nine months of '04. EBITDAX for the third quarter of '05 totaled $110.2 million, and for the nine months - - first nine months of '05, EBITDAX totaled. Both are almost 80% higher than the corresponding '04 period and 24% higher than the second quarter of this year.

Cash flow increased 78%, from 56.5 million in the third quarter of '04 to 100.4 million this year. This is the first quarter in our history that cash flow exceeded the 100 million mark. In addition, this is the first time quarterly cash flow per share has exceeded $1. Year-to-date 2005 cash flow totaled $253 million. As has been the case in every quarter this year, both EBITDAX and flow represented record quarterly highs for the Company. And for shareholder references, Rodney mentioned, these non-GAAP financial measures are fully reconciled on the Range Resources Website.

Looking down the balance sheet. Debt increased by 14.2 million during the quarter, due to our capital spending exceeding our cash flow. Due to the nature of our drilling schedule, the third quarter has historically been the heaviest quarter for capital spending. In the fourth quarter we expect to return to cash flow exceeding capital spending by roughly $30 million. Continued improvement is evident in our credit statistics for the third quarter. Debt to annualized year-to-date EBITDAX is 1.7 times down from 2.7 times at year-end '04. And EBITDAX interest expense coverage is 11.1 times, up from 9.6 times at year-end '04.

Hedging activity during the third quarter consisted mostly of adding collars to 2007. The average gas collar spread in '07 is a floor price of 6.65 and a cap price of 9.24. But the big news on the hedging front, is that a mere 65 days from now, the remainder of our low price gas swaps roll off. These $4.19 swaps cover approximately 45 million of cubic feet per day of our fourth quarter gas production. So based on current NYMEX pricing, our realized in the first quarter of next year will increase about by approximately $2 an mcf over the last quarter of this year. Primarily, due to the roll off of these low priced hedges. For those of you seeking additional information about the hedge position, as Rodney mentioned, a detailed current summary of our hedging activity appears on our Website.

In summary, the third quarter financial results are similar to the first second quarters of '05, continued growth in revenues and cash flow driven by higher production volumes and higher realized prices. While staying focused on unit costs in order to deliver record setting margins. Quarterly cash flow in excess of 100 million represents a significant milestone for Range. And looking forward, there are more milestones ahead, such as the rolling off of those hedges, and further increases in our cash flow and earnings in '06. John, I'll turn the call back to you.

Thanks, Roger. I think Roger and I have both mentioned the extraordinary job that our operating teams did during the quarter. But I want to compliment Roger and his team. They're making many efficiency improvements and high grading many parts of our business and really doing a terrific job. I'll now turn the call over to Jeff to review our exploration development activities and the status of our capital program. Jeff?

Thanks, John. I'll begin by reviewing production. For the third quarter, production averaged 244 million cubic feet equivalent per day, a 16% increase over the third quarter of 2004, and a 5% increase over the second quarter of 2005. This represents the highest quarterly production rate in the Company's history, and the 11th consecutive quarter of sequential production growth. The 244 million per day is comprised of 120 million per day or 49% from the southwest division. 96 million per day or 39% from the Appalachian division and 28 million per day of 12% from the Gulf Coast division. This increase was due to the success of of our drilling and acquisition programs. Approximately 72% of the Company's production was natural gas. For all of 2005, we're forecasting production growth of more than 20% over 2004.

These results are excellent and were achieved despite the impact of hurricanes Katrina and Rita. We had a significant amount of production curtailed by both storms. At its peak, Katrina and Rita shut in 16 million per day and 33 million per day respectively. Rita was more impactful in that it shut in significant onshore production due to the impact that it had on the processing plants along the Gulf Coast. We still have 13 million per day shut in. I expect the remaining shut in production to come back on slowly with a portion not back on until late December.

We don't anticipate any lost reserves due to the storm, only delayed production due to shut ins of plants and pipelines. Fortunately we have had good onshore production success in our other divisions, which drove our excellent production growth in the third quarter. And despite this storms, we're still projecting good production growth for the fourth quarter and the year. I applaud our operating teams for an extraordinary job.

I'll now review some of the highlights of each of our divisions. And I'll start with the Appalachian division where the Pine Mountain properties are working out extremely well. The properties outperforming our original acquisition economics. Production is currently running about 20% higher than our original production. Current plans for 2005 drilling in Nora include 165 CBM wells and 25 tight gas stand wells, for a total of 190 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 Haysi field and own a 70% working interest and 12.5% royalty in 30,000 acres there. We have now drilled 15 CBM wells on this property. What's important is that these wells are over 5 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 at Nora and the production to date is also very similar to typical Nora wells.

We believe that Haysi field, Nora field and Oakwood field are in essence one very large gas field. Since acquiring the properties, we've integrated the geologic control from the CBM wells, conventional wells and core holes to map the coal thickness across the property. Combining this geologic data with the gas content in the coals and the rock properties and applying reasonable recovery factors, we believe that we have about 2,800 locations to drill assuming 60-acre spacing.

Of the 2,800 locations, only 640 are booked as proven undeveloped locations, which leaves over 2,100 locations yet to be booked. Given our knowledge of the area, we feel that the probability of drilling these wells is very high. Given the quality of the production, and because we own the minerals in the field, our finding costs are excellent, below $1 per mcf and our rates of return are outstanding as well. Our acreage position in this area consists of 287,000 growth acres.

Another possible upside to Pine Mountain acquisition is the [Wydan] acreage in West Virginia. This area contains a 77,000 acre block in which Range has a 100% working interest and a 100% revenue interest in 74,000 of the acres. We assign little value to the property but it may have significant upside. As I mentioned during the last conference call, the CBM studies of the properties has been completed and the analysis is encouraging. As a result, we have proceeded to the next step, which was to acquire CBM cores and to disorb them in order to quantify the gas content of the coals. The desorption process is ongoing and should be complete by year-end. If this analysis comes back favorable, we'll initiate a five-well CBM pilot project early next year.

Our CBM project in Pennsylvania is also moving forward. After drilling a five-well program on our Unity acreage last fall, we were sufficiently encouraged to commence an additional seven-well program this year. We finished drilling and completing those wells and the early production is encouraging. Two additional CBM projects in Pennsylvania are Chest Springs and Wilpen projects. We finished coring and disabsorbing the cores in both area and the gas contents look excellent, on par or better than what we have at Nora. While the coals are thinner than Nora, both projects look encouraging and we plan to initiate pilot drilling programs in each area early next year.

We'll also begin drilling our [Salem] acreage next year. Our drilling program for the deep Trenton Black River includes five wells. Three well in Bradford County, in northern Pennsylvania, and two wells in Washington County in southwest Pennsylvania. Both areas contain [grobbens] that look very similar to the grobbens that are being successfully drilled by Talisman. We're in the process of drilling the five wells and plan to release the results once we've completed all five wells. Most likely sometime in the second quarter of next year. In the shallow portion of the Trenton Black River play in western New York, we drilled three successful exploratory wells, which specifically targeted the Trenton Black River formation at about 3,000 feet. These wells should be online by the end of the year.

We have 91,000 gross acres in this portion of the play so we have some running room. We're on target to drill 380 shallow wells in tight gas sand plays 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 speeds the conversion of nonproducing reserves to producing and unproven reserves to reason proven.

Finally, our our highest risk opportunity in the Basin is our shell test in Pennsylvania. 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've drilled three more wells in the area. One of the wells encountered a strong sustained open flow of 1.6 million per day from a shallow zone at approximately 1,000 feet. Given the potential of this zone, we stopped drilling and completed the well at this step. We anticipate that this well should produce about 200 mcf per day into the pipeline.

The other two wells were drilled to a total depth of about 1,000 feet below the shell interval that we plan to test. They were drilled deeper due to the fact that we though we had two zones below the shell that would have exploratory potential. Both of the wells were successful in that the deeper horizons - - in the deeper horizons, so we completed both wells in them. The wells tested at open flow rates at 2.1 million per day and 1.2 million per day.

Given the success of our original well and the three well follow up, we have began laying a pipeline into the area to connect these four wells. They should be online in late November. Before year-end, we also plan to start drilling four more vertical wells and one more horizontal well in this area to further test the shell. We've continued to build our acreage position this play and we now have 100,000 acres. We're continuing to aggressively increase our land holdings.

Just stepping back and looking at that whole area, it's been very encouraging. And what we've discovered to date, we have not just a shell play but we have plays in multiple horizons out there. We have lot of acreage, a lot of running room. And again we're in a great area to be drilling wells, we're looking at a strong premium to NYMEX, great royalties, really strong economics. So, I'm excited about the area and excited about continuing drilling as well as trying a horizontal well there. And again looking at some of the shale plays around the country like the Fayetteville, like the Barnett. It's the horizontal wells in those type of plays that made them take off and accelerate even more. So, we're excited about that opportunity.

In our southwest division, we're continuing our infill drilling and refracing program in the West Fuhrman-Mascho unit in Andrews County Texas with continued success. We still have about 80 locations to drill as well as several wells to refrac. We have significant upside with regard to water playing. One website to the west of Fuhrman, our new Eunice properties in southeast New Mexico are also performing extremely well. We picked up our second rig there and anticipate doubling production on these properties by the end of next year. We're also actively drilling and having good success on our Conger, Val Verde and Laura LaVelle.

Our initial Woodbine discovery in east Texas that came online at year end late last year is also still producing about 6.8 million gross or 1.2 million 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 in approximately 30,000 acres of leasehold options. In addition to the zone that was tested, there's significant behind pipe potential in the chalk. We're currently drilling two more wells in the area. We operate and have a 50% working interest in one and the other is outside operated and we have a 25% interest in that well.

Also in east Texas, we recently tested a new discovery at a very impressive rate of well over 20 million per day gross or 5.6 net at very high flowing tubing pressure. We're currently producing the well at 13.3 million per day gross or 3.7 net, which is constrained by facilities. Our working interest in this well is 38% and we have potential multiple offsets to it. We're not being specific as to the location for competitive reasons.

We also drilled two very impressive wells in our midcontinent division. These wells, which are Range operated, are currently producing 20 million per day gross or 12.8 net from the Hunton formation. Again, due to competitive reasons we aren't being specific as to the location. Both of these discoveries are very exciting and I congratulate all the technical staff who were involved with these wells. In the midcontinent area, we've been able to run four to six rigs this year. And as a result of the significant increase of the acreage that we had last year. Now, this higher activity, coupled with good technical success and good economic success, has resulted in the division growing to about 39 million per day, which is a 37% increase over December 2004.

The Gulf Coast division had three successful exploration wells during the quarter. Range has a 15% working interest in the West Cam 295 Number 2 well, which is over 13 million per day gross or 2 million per day net and is anticipated to come online before year-end at a rate in excess of 20 million per day. Another offshore well in which we have a 16% working interest, logged 44 feet of pay and should be online in the first quarter of next year. This well remains confidential due to competitive reasons.

Now, Range just finished drilling in fifth successful we will in the [Laloo] area onshore South Louisiana. This well logged 25 feet of gas play and began producing at a rate of 6.2 gross or 2 million per day net. Range will also have a quarter interest, in a high potential [Norfoot] well, onshore Mississippi, which should spud in the first quarter of 2006.

In summary, we're in great shape to achieve more than 20% production growth for 2005. 2005 will 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 Tcf of solid long-life properties. Our reserve life is now 15 years. In addition to that, we've discussed our drilling inventory, which contains over 6,800 locations that equate to 1.76 Tcf of net unrisked reserves. Of which about 74% or 1.3T's are unbooked. This is a large multiyear inventory of projects that mostly consists of low risk highly repeatable development projects. Complimented with several higher risk, high potential exploration projects.

In addition to that, Range also has 1.4Tcf of net unrisked reserved potential in its emerging plays. These are primarily technically driven resource plays involving CBM and shale gas opportunities within our existing core areas. So in total we have 1.3 Tcf of proved reserved, 1.3 Tcf unrisked unbooked reserves in our drilling inventory, and 1.4 Tcf of net unrisked in emerging plays.

Importantly, we're not depending on any one or two projects for our future growth. Having a large, high quality drilling inventory is a real key in my mind. One of the key strengths of Range is its portfolio. The other is its people. This is led by a technical team that now consists of a total of 90 geologists, geophysicists, engineers and land men. This is a talented group who is responsible for all of the projects that I just mentioned. And they are continuing to generate exciting new opportunities.

The Company today is significantly different than it was a year ago. With our 72% reserve growth last year, we now have over 1.3 Tcf of proved reserves. Importantly, the reserves that we've added are long life, low decline rate, very predictable reserves. We have a larger, more stable proved base. We also have more upside with 2.7 Tcf of net unrisked reserve potential.

To help put the portfolio in perspective, I'll list a few if the key projects. We have roughly 3,000 drilling locations in the shallow type gas sand plays in the Appalachian Basin, of which 1,000 are not yet booked. We have over 2,700 potential CBM locations in Nora and Haysi, of which over 2,100 are not yet booked. There are numerous identified Trenton Black River grobbens on our acreage that are undrilled. There are still 80 additional units to drill in the West Fuhrman-Mascho unit. As well as significant additional refrac and water flood potential, which will continue to add to production and reserves there. There are over still 50 locations to drill at Conger Field.

There's over 100 bcf of net unrisked reserve in our Texas Panhandle and Oklahoma acreage in stacked pays and the Morrow Springer and Hunton formations, as well as some of the shallower plays. Our shale play in the Appalachian Basin now consists of 100,000 acres. Importantly, we continue to add acreage in this play, which will increase the upside potential of the project. In addition to to the shale play, we have 100% working interest in approximately 20,000 acres in the shale play in Permian Basin in west Texas. And that play is a Barnett/Woodford play. The Barnett and Woodford and are in essence on top of one another there. And it's a very thick section. And we're excited about the play, there's currently a lot of activity in the area. There's EnCana, Burlington, PetroHunt and along with DOG, are drilling in and around us. And there's a couple of small independents as well. So, we'll see the results of what they have in the next few months, and based on success, plan on drilling well sometime plus or minus in May of next year.

And we've recently begun leasing on a new shale play in Texas with over 8,000 acres leased to date. This play has strong technical merit and I'm excited about its upside to the Company. The unproven CBM potential of our Pennsylvania acreage could be greater than 100 bcf net. In the Norfolk play, with its initial well to be drilled early next year, has a potential to be over 100 bcf net. The Woodbine Austin chalk had similar upside. There are numerous other projects as well. Hopefully this gives you a feel for Range's portfolio and why I'm excited about the future.

Despite listing all those, there are other things that are in the works that are very exciting. We finished our 3-D at Courson Ranch. We're just beginning to drill on that. There's a lot of really exciting tons there. And we have a new oil play in northern Oklahoma that we've begun drilling on that looks very encouraging. And we're shooting a 3-D over that right now and our rates are climbing there. We have a deep Springer at Hunton well that we're drilling a deep well in southern Oklahoma that really has a lot of upside and repeatability. And I could go on with other things. For the sake of time, we have a great portfolio with a lot of upside.

So, to conclude, as I've said before, it's a fairly simple business, the key is to grow production and reserves with good finding and lip costs. The difficult part is to do it consistently over time. However, with our technical staff and the large drilling inventory and 2.6 million acre leasehold position, we're well positioned to do just that. Back to you, John.

Thanks, Jeff. I'll take a look forward here a little bit. Looking to the fourth quarter, we continued to see strong operating and financial results [Inaudible - Technical difficulty.] We're looking for continued production growth in the fourth quarter with production projected to come in at 246 to 250 million a day. The big variable, as Jeff mentioned here, is the lingering effect of the hurricanes. As Jeff mentioned, we still have 13 million a day of production shut in due to third-party pipelines and processing plants still being down. Given we know today, we're looking at mid to late December before the shut in production is restored. So, we're being a little careful in terms of trying to project fourth quarter volumes.

Fourth quarter '05 revenues are expected to continue to rise due to the higher production volumes and the stronger realized prices. Assuming the current futures prices and hedges, we anticipate fourth quarter price realization to be at or above $7 per mcfe. or $0.67 higher than the $6.33 per mcfe we realized in the third quarter. And a staggering $2.08 higher, or 33% more than the fourth quarter of 2004. Once again, we anticipate fourth quarter production revenues, cash flow, and earnings to set all-time highs exceeding the third quarter results. The fourth quarter 2005 year-over-year comparisons will continue to demonstrate solid quarter-to-quarter execution of our business plan. And starts with production, which, as I mentioned, despite the hurricanes, is anticipated to reach another record high.

Second quarter - - I mean, second realized prices, which continue to reflect a roll-off of the lower-price swaps, are estimated to increase 33%, as I mentioned. As a result, fourth quarter oil and gas revenues are projected to exceed third quarter by $25 million or more. Looking year-over-year, fourth quarter '05 revenues are estimated to increase by 50% to 60%, versus fourth quarter 2004. Expenses, on the other hand, are anticipated to rise at less than half the rate of revenues. So that's good for margins.

Looking beyond the fourth quarter, we anticipate production to continue to increase in the first quarter of '06, as a result of our 824-well drilling program, and the anticipated risk restoration of the shut in production in the Gulf Coast division. Based on the strong 2005 drilling results and the preliminary plans that we've been working on for '06, we anticipate another year of double-digit production growth in 2006. And based on futures prices, we anticipate per share earnings and cash flow for '06 will far exceed that of 2005.

For the remainder of this year, we'll continue to focus on the execution of our business plan. We're hopeful that additional exploration, discoveries and attractive acquisitions will occur. But the good news is we don't need either of those elements to achieve our goals. Executing our plan and successfully completing the 824 well drilling program has and will continue to add significant shareholder value in 2005. While focused on getting the wells drilled, getting the pipeline laid and hitting our production targets, we're also continuing to expanding our drilling inventory and have made solid progress with our emerging plays, as Jeff has mentioned. We have projects in the pipeline that have over 3 Tcf of unrisked reserve potential or more than twice our existing proved reserves.

Like Jeff did on the operation side, I'll spend a moment commenting on how Range is different and better today. First, our financial results for the full year 2005 should be top tier for our peer group. And income should exceed $100 million with cash flow topping 400 million. Second, with our low-priced swaps rolling off, increasing production, 2006 results should far exceed those of 2005. So from a financial perspective, there's little question that year-over-year results for both 2005 and 2006 will be extremely impressive. That gives the management team the confidence to focus on opportunities that build NAV per share, versus focus on short term fixes.

As I mentioned earlier, the question is not whether production reserves will grow, but how quickly and efficiently can we harvest our drilling inventory and emerging plays. The key element of this is our technical and operating teams. And as Jeff mentioned, we now have 90 technical personnel on staff, and are aggressively looking to add more high quality professionals. This is really important as we anticipate drilling over 1,000 wells next year. We believe our technical teams give us a competitive advantages in areas where we operate. They're the ones who are really coming up with all the ways to enhance our existing properties like Fuhrman and the ones in west Texas. But they're also generating the new prospects. And they're also obviously involved in any acquisitions we look at.

The combination of our people and our very large drilling inventory, places our Company in very strong position. The important points to our drilling inventory, is one) it is anchored by a very large number of lower risk repeatable projects. I think that's probably the most important. Second) it's diversified in the number of different plays. So, we're not just in one sandbox. And three, we have a number of higher risk, higher return prospects that if successful, will really fast forward our growth.

On top of that, we have several very meaningful emerging plays, that could be really life changing, such as the CBM and the shale plays. This equates to being out the same position to methodically deliver attractive growth and NAV per share over the next several years. While we're positioned to fully understand that the key is to continue to execute our strategy and we continue to maintain vigilance and discipline. As shown in the building of our drilling inventory, we will not sacrifice the long term for nonrepeatable short term gain. The third quarter results are another solid benchmark and we look forward to reporting our progress in the last quarter of the year. That's all my prepared remarks. I will now turn the call over to Charlie Blackburn, our Chairman for his comments. Charlie.

Thanks John. Well, there's not a whole lot I can add to that comprehensive report that the management has given you. But I would like to say congratulations to the management team, the operating teams and everyone else at Range for an outstanding quarter. I'm very pleased, extremely pleased with the record results the Company posted in the third quarter. In particular, I'm impressed with operating results that allowed us to meet the original production guidance in spite of the impact of two hurricanes. In my mind, this is the mark of a resilient and imaginative organization.

I periodically visit the various offices, and meet with the operating teams, and I continue to be impressed with the projects they're generating. And refuse to be satisfied with the status quo. They're continually striving to find a new approach or new idea that will unlock additional potential and they are succeeding. The key to success in this business is the quality of technical teams, and their ability to generate rewarding prospects. We've made it a priority to build and high grade the operating teams over the past two years. And are continuing to add high quality personnel. This effort is paying off with a portfolio of projects and emerging plays that has the Company well positioned to grow for many years. Thank you, John.

Thanks, Charlie. Operator, why don't we go ahead and turn the call open for questions at this time.

[OPERATOR INSTRUCTIONS] The first question is from Ron Mills of Johnson Rice. Mr. Mills, your line is open, please go ahead with your question.

I'm sorry. Good morning, guys. Afternoon, I guess. A couple questions. On the Pennsylvania shale, the three wells that were drilled, were those all vertical wells, Jeff? And have you all started to drill any horizontals in the Pennsylvania shale yet?

No, those wells were vertical wells, and the wells were [inaudible]

I'm sorry, you're cutting out,.

[inaudible]

Hello?

Yes, I don't know if this is any better, but all these of those wells were vertical wells, and [inaudible]. Second question, we plan to start our first horizontal well in the fourth quarter. [Inaudible]

Hello? I'm having trouble, I don't know if it's our phone or yours but it's cutting out.

I think it's our phone.

The pricing differentials, Rodney, you may be able to help a little bit, I know with the run-up it's in Henry Hub that a lot of the regional trading hubs have seen increased pricing differentials. Can you give us any kind of guidance as to what to look for or a way to look at how we could look at the regional trading hubs and try to come up with a blended number for Range?

Well, if you look at the actuals for the third quarter, the gas differential [inaudible] was about $0.37, though, to NYMEX [inaudible].

Ladies and gentlemen, this is the Operator. I apologize, but there will be a slight delay in today's conference. [OPERATOR INSTRUCTIONS] Mr. Mills, your line is own, please go ahead.

Great, I apologize, I didn't, if you all don't mind rehashing the first couple questions, because I wasn't able to hear any responses. In terms of the Pennsylvania shareholders, it sounds like you didn't - - your first horizontal will be upcoming in the fourth quarter. Was that as planned versus the last conference call, or has that horizontal drilling just been pushed back to the fourth quarter?

Ron, this is John. Hopefully, this is better.

Yes, it is.

The - - basically, what we've done is we continue to study a lot what's going on out there. The - - we drilled the first well, it was a vertical shale well, pleased with that results, as Jeff mentioned. We drilled three more wells. A little surprised by the multiplicity of pays that we got, so that's encouraging. The one thing that we're getting more and more convinced of is that as soon as we possibly can we need to drill a horizontal well. Because that seems to be the thing that's allowing the other plays, and particularly the Fayetteville, to fast forward. So what we're going to do is the rig that we've currently got drilling our TBR wells, probably what we will - - or most likely case, we'll take that rig and move it and maybe drill one or two last TBR wells and move it down into the shale play and drill one or two shale wells. It's going to be a question in terms of locations and how fast we can get all that moving. But we really want to see what's going down in the shale play in terms of the horizontal benefits, especially given the fact that we've got a lot of manpower, buying a lot of acreage. And we're expanding that play pretty dramatically. So the sooner we know what the metrics on the horizontal well, the better off we think we are. So that's current plan.

So in essence, you potentially, instead of drilling five deep TBR wells, you drill maybe three and take the rig down to do the horizontal, is that a fair representation?

That's exactly right.

And we can come back and drill whatever we want to drill later. To drill the horizontal well, you need a top drive rig and both the deep and the shale well would be horizontal. So, you'd need the same rigs for both.

Okay.

And there are not that many rigs in the Basin that can currently do that. So that's what we're thinking about right now.

Okay. And then Rodney, on the differentials, it was just about the regional trading hubs, I'm assuming you've seen significant increases in differentials?

We've seen a lot of basis differential coming into the market during bid week. You can see what the actual differentials corporately were about $0.37 on the gas, and $3.29 negative differentials to NYMEX corresponding prices. We'd expect that those would expand slightly in the fourth quarter. But as we go through November and December, if we still see the wide divergence in the local differentials, that obviously will change. The positive thing in Appalachia is that that's generally a premium. And to some extent, that premium will actually expand in the fourth quarter as we rebid out some of our production up there on a 12 month basis. So it is encouraging from that standpoint but there is a lot of noise in the marketplace today.

Okay. And then one last one, I know there's a lot of people on. The midcontinent, Jeff, can you walk through the 75,000 plus or minus acres that you all farmed out in Oklahoma? Is the recent Hunton activity, is it in that area? What are some of your plans in targeted formations in that play? It's one that hasn't been talked about as much as some of the Appalachian plays and west Texas. And I just look for some more color on that.

In terms of the Hunton well, we've been pretty specific. At some point we'll tell you exactly where it is and tell you the amounts. But right now we're keeping that confidential. We've had excellent results and of course we're looking for follow-ups and repeatability. We're going to keep that confidential. In terms of the farm-outs that we got from the major results there have been excellent. Our success rate has been in essence 100%. It's a sack pay area. They have a lot of expertise in it. We've drilled some really good wells there. Great rates of returns. So I think it's a win win. It's been a great deal for us as well we're generating a lot of value on their acreage that they haven't been active on. And that's why we were able to do the deal. Very excited about that. And I think we'll be drilling on that acreage for the next three to five years. There's lots of opportunity out there.

And does that farm out more development exploitation oriented all out of the Appalachian stuff? Or is it also one that as you dig through the data and evaluate it, that could even become more exploratory in nature?

Yes, there's various horizons that's going to be - - it's like the Appalachian Basin in that you've got at certain depths you may have development type horizons, as you drill deeper, exploratory or step-out, and you may be able to expand and grow the field. And it's like the Appalachian Basin, it's a high chance of success, it's a very low risk area. But there are opportunities. It's unlike Appalachia though, in that you have the opportunity - - one of the wells we drilled on that acreage came on to 5 million per day. So, you can get high rate wells. It's not like - - we love shallow type gas sand wells and we love coalbed methane wells but you're adding very excellent finding costs and excellent rates of return. But those are relatively low rate wells. Here on the Oklahoma, it may be different in that it's deeper. But you can be looking at higher rate stuff.

All right, I'm going to let someone else jump on. Thanks.

Your next question is from Jack Aydin of Key Bank Capital Markets.

Hi guys. A couple of questions. When, Jeff, this Pennsylvania shale, it looks like stack pay, it looks like three formations. Could you elaborate a little bit? Because A you got the shallow, B, you've got the shale, C, you've got the deeper horizon. Am I reading it correctly? Or could you talk about it a little bit more?

Yes, you are reading it correctly. The good news is we found that that it's a stack pay area, there's multiple opportunities. And in each one of those horizons, potentially there's a lot of running room. So, we're really excited about that. Again, to put real detailed color on what are the names of the horizons and depths and qualities, for right now, we still want to keep that confidential. Because with the success we've had and success we anticipate, we want to continue to build our position and solidify that before we get too detailed. But we're certainly encouraged and we're going to go drill five more wells there shortly. And one of those will be a horizontal well into the shale.

Jeff, if you would talk about potential reserve in each formation, could you throw some numbers, or you are unwilling to do it?

I think at this point, we're still a little unwilling to do that. I will say obviously we feel comfortable enough that we're continuing to drill and we're continuing to lease acreage. But insofar as the details, I don't think we can say a whole lot more about that. John Pinkerton was shaking his head no, so that gives me clear - - the clear answer that I can't say anything more. Otherwise, Jack, I would love to tell you.

Now, the other question I have is basically in the west Texas shale plays, the two plays you have over there. Why do you have to wait until somebody else to drill? Why don't you take the initiative and you start drilling?

Okay, there's a couple of reasons for that. One is we have a lot of time and term left on our leases, so there's no rush to have to drill. So, we're in a good position there. Secondly, we also think that could be a stack pay area. So, we see some deeper potential in MussleMan and shallower potential in Wolf Camp. But we think the proper way to approach that is to shoot 3-D over that, gather that data, and then see what some of the operators are doing. And we think once we gather all that information, we can make a more intelligent decision in terms of how to develop and how to go forward.

And this is the final question. You got a couple wells in the Panhandle, are one well, producing 15 million, the other is 20 million, what kind of running room? How many prospects do you have in each those areas?

I hate to say it again, but when you get results like that those are excellent onshore wells. Obviously, they're really high rate wells and we're really excited about them. And there aren't very many wells like that onshore U.S. So we want to lock up every bit of acreage that we can before we talk about them in detail, like we have on all of our other plays. If you roll back in time with our Warren County discoveries, we weren't specific to where they were. And then we talked more about the them. And things like that. So what - - we will definitely at some point in time, disclose all that. But right now we think we have a competitive advantage and we want to fully take advantage of that for our shareholders.

Do you have, are you willing to give us the acreage position in each area?

Jack, this is John. What we are willing to say is, is that we're in both of these areas, and we do have additional acreage. We do see offset drilling. And we are acquiring acreage and we do expect to, just like, quite frankly everything else we work on onshore, we expect these plays to be repeatable. So, that's why we got them to begin with. To answer your question, the answer is yes. But again, we're unwilling to give the details because there's a lot of smart competitors out there, that based on just those acreage numbers will be able to figure out a lot more quicker. We just really need to, for the benefit of all the shareholders, we really need to be careful.

Well, I appreciate that. Thank you.

Your next question is from Rehan Rashid from Friedman, Billings, Ramsey.

Good afternoon, guys. Jeff, quick question. Could you remind us of the prior [bell] reserves in the Nora Haysi area between 100 unbooked locations, reserves per well?

In the past we've talked about and in our materials, I think we have 325 million per well. That's probably a reasonable number to use across those. It's interesting, if you look at the wells drilled to date, of which there's over 800 of them, the average DUR to date on those wells looks like to be over 400 million per well. So, I feel comfortable with the 325 million per well. And the cost of those, even in today's environment, is,depending on where you are, $280, $300,000 per well, plus or minus. And remembering that we own the minerals, so our revenue interest is actually higher than our working interest. So our finding costs are well under $1 per mcf, in a lot of cases less than $0.80 per mcf, just with excellent rates of return. Clearly a trip pricing well over 100%. But those wells are real robust, even down to a $2 flat gas price. And again, adjusting costs back to a $3 environment, there's still 20% or better rate of return to those numbers. Excellent upside for us, it's very low risk. It's very repeatable. And we're really excited about the project.

And in terms of tying it back to John's comments earlier, just sufficiency and acceleration, this year's program and next year's program in order of magnitude growth, any thoughts in terms in terms of infrastructure you have already or just have to wait and find out?

Again, it's interesting if you look back historically and 2003 and prior, we were about 60 wells per year, '04 was about 100, '05 you're in that 190 range, plus or minus. So there's been a big ramp-up in drilling and so moving that forward. And I anticipate, although we're working on it, that you're going to see a big number, again, a big significant increase in terms of what the wells will drill out there at Nora and then on top of that Haysi. So, it's early, but I'm sure we'll combine Nora and Haysi, at least in the - - probably in that 300 well range. But it's listed early and we're working on it.

As you develop this field, it's not that you have gas and gas competition, you can put compression to make sure it's at net increase on the - -.

Yes, correct.

Wyden field - - please, once again. So what's the next step in the fourth quarter? You do a core analysis, or you have that back now?

Well, we booked our first quarter, series of quarters and we're disabsorbing them. And we'll get that data back around the end of the fourth quarter. Plus we'll probably take some additional quarters late in the fourth quarter and early in the first quarter. It's a big acreage and so you need multiple pieces of data. And then what we'll do is just look at the gas contents in the coals to see if radical. We know we have good thickness, the question and it is a risk, are we going to have adequate gas content. If we do, there's a lot of running room, a lot of upside. Also within Wyden, it's not to forget, there's conventional production. And there's some other things we're looking at and trying there. So, I think in time, Wyden will be a sleeper, looking forward into '07 and '08, I think Wyden will be a real good property for us.

So so fourth quarter conference call or even first quarter conference call, what kind of gas content do you think we should be keeping our ears open for, in terms of what, if you get beyond that, that means you're in good shape?

We're actually looking attachment it becomes a function, obviously we have the minerals so that helps with our economics a lot. With what our expectations of future gas prices. We're really going through right now. And I have numbers in my mind of what I'll look looking for. But before I release them, I want to make sure we finish all the economics and look to see what kind of projects will generate a reasonable rate of return for our shareholders going further. But we should be able to on our next conference call at least talk about that, I would think. There is no competitive thing there, we own the acreage, it's locked i[. We own the minerals, not just the acreage.

The Trenton Black River shallow, any thoughts on what the program could look like next year? And I remember you had some gas grobben problems there initially. That's why the first one couldn't come online for a long period of time. Is that being addressed?

Yes, there it's - - again, those first three wells and the hooking up of the wells, we do not operate that. It's a [inaudible] south side operating, we're not controlling the pace of that. But it's taken a while to hook them up. It's still taking awhile. That company is currently telling us the end of the year. I hope they're right. And we're just - - we're going to wait until that's in before we do additional drilling. Other than - - again, it's early, I would imagine next year we'll probably drill at least another five wells up there, or something like that. But there's a lot of acreage and a lot of running room.

Okay, thank you.

Your next question is from David Snow of Energy Equities.

Hi, I know you keep encountering these annoying conventional sands, but what's the thickness of the Pennsylvania shale?

The thickness of the shale in Pennsylvania is good. It's on par with the thickness of the Barnett and the Forth Worth Basin. Again, I don't want to draw a comparison back. In terms of thickness and TLC, and bitronite reflectants and all those kind of things, it's fairly similar to the Barnett and the Fort Worth Basin. But I believe the - - ultimately it comes down to reservoir pressure. Barnett's probably a 0.5 grade and slightly over pressure here, that's going to be more normally pressured. And then you got the other thing with shales, what's the permeability and distribution. And I expect that the Appalachian shales are going to be much tighter than a typical Barnett well. So, we're not anticipating rates like that. But at the flip side, our gas price, we're looking at right now it's unbelievable, as far as a positive differential with NYMEX. That historically it's like $0.35, where the Barnett may be $0.50 to $1 negative. So you've got a great advantage on the gas price. You've got a advantage on royalties. We have an eight in the Barnett, typically it's a quarter, maybe 30%. Our cost breaker up there is still low, it may be in the $25 in the $50 per acre. Where in the Fort Worth you're in the $500 to $11,000 an acre. So, it doesn't have to be rate-wise a reserve life like the Barnett, but the thickness, a long answer to your question is actually fairly similar.

You think the slick water frac will be the best way to do it or maybe something like the Fayetteville shale approach?

No, those are things - - that's why in those shell-type plays, there's going to be experimentation and technical learning as you go forward. I think horizontal drilling could be very important. As far as optimum stimulation, it will take a number of wells to figure that out, just like it has in all these other plays.

And what's the royalty, did you say?

It's typically an eight. Which is great, because as in the Fort Worth Basin, you may be a quarter or 30% or I've heard of even high numbers way beyond that.

And you're still expanding it?

Yes.

Okay. And in Texas, is the - - is it kind of comparable to what you were just discussing?

Our west Texas Barnett play?

Yes.

There the Barnett is actually on par or thicker than what it is in the Fort Worth Basin. You're looking at a thicker section. Plus on top of that - - or actually below it, you have the Whitford which is also very thick. So - -in parts of that acreage that we have the section is up to 800 feet thick. It's really thick. So you're looking at a thick section. And there you do have a higher pressure. But it's deeper, and again, it's relatively untested. So time will tell whether that play is going to work or not. But we think our acreage has a lot of upside in the Barnett, in the Woodford, potentially in the [Fulton] and potentially in the Wolf Camp.

How deep is it?

It depends on where you are in the Basin. Where we are, you're in the 11 to 13,000-foot range.

And the Woodford is a shale also?

Yes, New Field recently has talked about the success they had in the Woodford. So, nationally, the Barnett, obviously is making over 1 bcf a day. Is a very successful shale play. Now, the is gaining traction and New Field recently has been talking about success they've had in the Woodford in eastern Oklahoma. So that would be the same interval.

And is that - - is that comparably thick to the 800 feet you just mentioned for the?

I'm saying combined, the Barnett and Woodford can be as thick as 800 feet there. They're pretty thick.

Okay, thank you.

We are nearing the end of today's conference. We would go to Howard Swenker of Swenker and Company for our last question.

Can you give economics of a well in the Woodford shale, or in the Texan shale, if it's not Woodford? How much it costs, how much you're shooting for, what the lifting costs might be?

You're just talking out in the [Reese] and Culverson County in the Permian?

Yes. Where are you located?

Where we're located?

Yes.

I sort of hesitate to do that. And like I said what we're going to do is shoot a 3-D and look at results of others. So you've got the potential of even thinking about how you design that. You can design straight holds to test the [fusselman] if it doesn't come up. And a vertical well tests the Woodford or tests the Barnett. Or you could be looking at just staying a well horizontally, directly into the Barnett. And we're working through all those. Depending on what scenario you come up with and the size of the treatment, costs are going to vary. So, I think it's a little early for us to talk about that.

Do you have any idea what it would cost to drill one of those wells?

Sure. Give me a design. Horizontal well in the Barnett, depending on where you are in the Basin, you may be $2.5 to $3.5 million. And of course the other thing when you drill, depends on whether you're drilling a two or three wells or you get into a 50 well 100 well program mode. In a program mode over time you can drive those costs down and there's efficiencies you can gain with large scale developments.

How far might you be from Rice County?

We're right from in Reese and Culverson out in the Permian Basin there.

I'm sorry, I didn't hear clearly.

We're right in Reese and Culverson County in the Permian Basin . We're now saying, that used to be our secret shale place. We're now telling you where that is. And for the people on the road show, when people come by my office, likely show you a map where the acreage is. And then of course, we have another Texas shale play that we've developed that looks like a really strong project technically and it could have a real lot of upside and we aren't telling people about that one. But we will at some point.

And what sort of royalties do you have to pay to the landowner to obtain mineral rights?

We were lucky out there that we started leasing early, so early on, you could lease for 15% royalty, maybe 20. Anything today is going to be a quarter or more. So our acreage we picked up early on. So our price per acre is fairly low and our royalties are real reasonable.

How long ago did you get this 15%? Because I know it's higher now.

Yes, it's - - we started leasing, it was more than a year ago.

Yes, more than a year ago.

Oh, I see. And now it's easily past 25, you said?

Yes.

Okay. Thanks.

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.

We want to thank everybody for being on today. We apologize for the mechanical or technical difficulties. I can assure you, none of our technical team were responsible for that. We've got them all fine on oil and gas. In terms of, we're obviously very excited with the results today, where we are. We are disappointed, quite frankly, that the hurricane has masked some of that. But we believe that we've come through the storm better than most. And it really has been a testimony in terms of the technical team under Jeff's leadership on how well they've done. So I applaud them, but also Jeff. He's done a magnificent job.

I think you can tell by the questions asked, we've got a lot of opportunities, there's a lot of neat new projects that we're developing. And these are, in this environment, are hypercompetitive so we're being very careful. We hope you all understand that we're doing that for all of our own good shareholders at Range Resources. That quite frankly is the only thing we care about. So it's being done with, obviously a lot of thought and caring for the projects that we are working on.

That being said, we're really excited about the fourth quarter of this year despite the hurricanes. We're going to hit record numbers in everything. But I think really most importantly, I think, that to me, that the big, big catalyst, at least financially, is going to be the first quarter of '06. I think you said it really fast, but I think that one of the things that Roger said that was pretty powerful is that our price realizations in the first quarter of '06 are going to be at $2 - - more than $2 higher than they're going to be in the fourth quarter of 2005. And as I mentioned, our realizations between third quarter and fourth quarter are going to be up $0.60, $0.70.

So, when you're looking at first quarter '06, our price realizations are going to be, let's say, $2.70 in mcf higher than they are in the fourth quarter - - I mean third quarter this year. That is a huge change in price realizations. And then you take on the added production revenues - - production volumes, you can imagine at least what our internal forecast, are really exciting. And so those, we really look forward to the first quarter of '06 to be able to really show that. I really think that is going to be going to be a very important event catalyst for the shareholders. And how the market views the value the value of our stock. As well as what really matters in this business, which is finding oil and gas on a consistent basis and production reserves going up, which I think we've done an extraordinarily well job own that. So everything's bright. We are excited about opportunities.

But that being said, we've got our nose to the grindstone, we're working hard, we're not going to let up. We've got a long way to go here. There's an enormous amount of upside that we're focused on, and we want to get that through the income statement, into the stockholders' equity as fast as we can. Because we certainly believe that's in everybody's best interest. So with that, we'll conclude the call. Thank you all very much, and we'll see you next quarter.

Thank you for your participation in today's conference. You may disconnect at this time.