山脈資源 (RRC) 2006 Q2 法說會逐字稿

Welcome to the Range Resources second quarter everyone's conference call. This call is being recorded. [OPERATOR INSTRUCTIONS] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question and answer period. At this time I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range. Resources. Please go ahead, sir.

Thank you operator. Good afternoon and welcome.

Range continues to report outstanding results each quarter. We're on track to reporting record results for 2006 as expected. The second quarter is highlighted by our highest production in the Company's 26 year history. With the closing of the Stroud acquisition at the end of the quarter we can continue to expect obvious built-in production growth for the next several quarters to come.

Obviously we continue to focus on our execution of our 2006 business plan. We're also looking to continue production and reserve growth at top core tile listing and find costs to drive our growth into 2007 and beyond. With our current hedge position we feel that we can be assured of the operating cash flow needed to execute our plans to 2007 and 2008. We're happy to discuss our results with you today.

On the call today 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'd like to cover a few administrative items. First we did file our 10-Q with the SEC this morning. It is now available on the home page of our website or you can access it through the SEC's EDGAR system.

In addition we've posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDEX, cash margins and the reconciliations of our non-GAAP earnings to reported earnings that are discussed on our call today. Tables are also posted on the website that will give you detailed information on our current hedge position by quarter.

Secondly, Range will be speaking at the Intercom conference in Denver on Tuesday, August the 15th with a Chicago road trip to follow later in the week. We will be at the Lehman Brothers' conference in New York and the Credit Suite's conference in Boston that are scheduled in the first two weeks of September. We have several road shows planned in various sections of the country over the next few months.

Please look on the website for upcoming conferences and road shows and let us know if you'd like us to stop by when we are in your area. Now let me turn it over to John. John

Thanks, Rodney. Before Roger reviews the second quarter financial results, I'll view several of the accomplishments for the quarter.

First of all, just on our overall basis, as Rodney mentioned we're quite pleased with the second quarter results. On a year-over-year basis production rose 13.4% beating the high-end of our guidance. This marks the 14th consecutive quarter of sequential production growth. Our drilling program, which is obviously the engine to the car here, has been on schedule throughout the year as we've drilled 479 wells in the first six months of 2006. We continue to be very pleased with the drilling results and we're generating what we believe to be very attractive rates of return.

On the call side of the business, the second quarter was quite positive as unit costs in several areas either decreased or were level for the first quarter of 2006. As a result our cash margins were up 21% from $3.74 per mcfe in the second quarter of 2005 to $4.52 mcfe in the second quarter of 2006.

Quarterly our unit cost structure continues to be one of the lowest in our peer group and Jeff and our operating teams are being proactive on this front. By posting record production lines and very favorable financial results in the first six months of 2006, we've executed on the first half of what we believe will be a terrific year for range and the stockholders. To put this in perspective our earnings in the first six months of 2006 are roughly equal to the earnings for all of 2005.

As Rodney mentioned late in the second quarter we completed the acquisition of Stroud Energy. The pleasure report that the integration is proceeding well with no negative surprises. Drilling and productions are both accelerating. That's good news.

Lastly, as you will note from Jeff's discussion our technical teams are continuing to do an excellent job expanding our drilling inventory and several emergent plays. Several of the merging plays are showing stong initial results that are quiet exciting. Stepping back and looking at the big picture, we have a diversified portfolio of projects and continue to expand. The upside potential of range is substantially greater today and this potential is not limited to one or two projects. There are a number of projects, that if successful, can materially increase our valuation.

With that, I'll turn the call over to Roger to review our financial results.

Thanks, John.

We're pleased to report another excellent quarter contributable to continued increases in production and favorable oil and gas prices.

Year-over-year quarterly production was up 13% as our drilling program continues to provide steady organic growth. As John mentioned, although the year is over half over, our first six months net income of 107 million equals 96% for our total net income for all of '05. So as you can see Range is on pace to post another record year in '06. A combination of higher realized prices and higher production drove a 33% increase in second quarter oil and gas revenue up to $157.6 million. Realized prices rose 17% or $0.96 per mcfe and cash margins were up 21% over last year to $4.52 per mcfe.

As was discussed last quarter, certain of our natural gas hedges are required to be marked to market at quarter end resulting in a non-cash pretax gain of 17.5 million in the second quarter of '06. Important to remember that no changes were made to the underlying hedges, that this gain is solely attributable to the accounting treatment. On the cost side of the income statement, the second quarter of '06 showed some encouraging signs. While costs are up on an absolute basis due to higher production volumes several cost items were flat or slightly below the first quarter of this year.

Direct operating expense for example was $0.84 per mcfe in the second quarter. That's up only $0.02 from last year's second quarter and flat with the first quarter of that year. Production taxes were down $0.06 per mcfe compared to the first quarter of this year due to lower prices and G&A expense, it was down $0.02 in the second quarter of this year compared to the first quarter. G&A will increase on an absolute basis during the rest of the year due to the Stroud acquisition and additional new hires. But it is anticipated to remain relatively steady on unit cost basis. We expect G&A expense to run in the neighborhood of 10.5 to 11 million per quarter for the rest of the year.

Due to rising interest rates and the refinancing of 150 million of our short-term floating rate bank debt to long-term fixed rate notes interest expense per mcfe this quarter increased $0.05 versus last year. Further down the income statement, looking at the non-cash stock compensation exception for the second quarter, it was 2.1 million and included expense associated with the newly effective phase 123 Alp announcement and previously present deferred combination plan mark to market expense. Exploration expense was lower in the second quarter decreasing from 9.1 million last year 7.1 million this year due mostly to lower siding expenditures. This quarters 7.1 million in expiration expense is also below the first quarter figure of this year it was 9.5 million. DB&A expense increased by $0.09 per mcfe to $1.53 in the second quarter of this year, up from $1.44 last year a up $0.04 from the first quarter of this year.

With the Stroud acquisition we anticipate DB&A expense to run approximately $1.60 per mcfe for the whole year. The increase in DB&A is mostly due to the Stroud acquisition being a corporate purchase and that required the booking of additional deferred taxes. While this increases our ongoing DB&A expense, in reality it has very little economic impact as our $207 million NOL carry-forward pushing the tax expense out many years into the future. Income taxes required a $622,000 current tax expense of the second quarter but no appreciable cash federal income taxes were paid.

Reported net income for the second quarter of '06 totaled 51.3 million or $0.38 per diluted share. That's more than double the 21.7 million posted in the second quarter of '05. Net income per share for the quarter calculated comparably to the analysts estimates was $0.29 per diluted share. This does compare favorably to the consensus estimate of $0.28 per share. EBIDAX for the second quarter of '06 totaled 120.2 million representing a 35% increase over the 89 million posted in the second quarter of '05.

Cash flow for the second quarter also increased 35% from 80.1 million last year to 108 million this year. Cash flow per quarter-- cash flow per share per quarter was $0.79. As Rodney mentioned earlier in the call, full reconciliations of these non-GAAP financial measures are readily available on the Range resources website.

Looking at the whole six months of '06 net income totals 106.9 million compared to 43.7 million in '05, that's 145% increase. EBITDAX year-to-date in '06 totals 258.3 million, a 52% increase over the 170 million for all of the first half of last year.

Year-to-date cash flow '06 is $236 million, 54% higher than '05 and cash flow per share year-to-date is $1.74, and that's up 46% for last year. The Range balance sheet saw several changes in the second quarter mostly attributable to the acquisition of Stroud Energy. The Stroud acquisition entailed the issuance of 6.5 million shares of Range common stock in assumption of Stroud stock options together valued 187.2 million plus cash and transaction costs of 171.3 million and the assumption of 106.7 million in debt. Now the debt was immediately retired with an advance under our bank credit facility. So the result of this transaction was a slight increase in our debt to cap ration from 42% at the end of last quarter to 45% at the end of the second quarter. Now this 45% leverage ratio is still below the 46% we had at the end of 2005.

Total debt was 895 million at June 30 with 398 million drawn under a 600 million bank credit facility. And the rest in long-term fixed-rate notes.

Now our leverage target remains a 40% debt to cap ratio. But as we've said before, we're not going to place this financial bill ahead of value creating activities. And the acquisition of Stroud Energy, as you've heard from us before and you'll hear more about in a moment, it certainly an example of this type of value creating opportunity. So with the higher level of production and a strong hedge position in place, we do anticipate reaching the 40% debt to cap, probably the first half of next year.

Our cash flow and asset sale proceeds will more than cover our revised capital spending budget for 551 million. That leads us to another balance sheet edition stemming from the Stroud acquisition. There's a new line on the balance sheet this quarter and it's called assets held for sale. Now these assets are the Austin Chalk Stroud properties which we desire to sell. And the financial results for those assets held for sale, they're accounted for as discontinued operations and they appear on a separate line on the income statement.

All revenue and experience attributable to these assets held for sale are thus excluded from the body of the income statement and they appear only on the net discontinued operations line.

The production volume and price tables likewise exclude these assets held for sale. The liability section of the balance sheet also contains a new $150 million senior subordinated note issue. The notes are unsecured, [inaudible] five years, mature in 2016, they were issued at par bearing an interest rate of 7.5%. These new notes extend the maturity of Range's debt to better match the life of its assets and helps to lessen our exposure to floating interest rates. Importantly, Range's capital structure remains very simple, just senior bank debt, subordinated fixed rate notes and common equity.

One rather minor but new edition to the balance sheet this quarter is a 50% equity investment, which totals 12.3 million in an Appalachian drilling contractor. And this company has worked with us for over 10 years and we have the highest confidence in their management and employees. And the founder will continue to run the company. And he owns the remaining 50% of the equity.

This investment affords Range guaranteed access to top-quality drilling services without the burden of a hands-on running of a drilling business. Early in May, on the hedging side in anticipation of the Stroud acquisition and before gas prices fell, we entered into gas hedges covering much of our remaining '06 volume as well as for additional volumes for '07 and '08. And we added 2006 natural gas collars on 30 million [inaudible] with a floor price of 708 and cap of 883.

GAAP swaps filling 75 million per day were added in 2007 at a price of 959 and 105 million per day of '08 GAAP swaps were added at price of 942. These new attractively priced hedges lock in significant cash flow and give certainty to our '07 and '08 numbers which will help us-- really allow us to fully develop our drilling inventory and keep on expanding our emerging plays.

As Rodney mentioned the detailed summery of our hedge positions appear on the Range resources website. Now to wrap things up, our second quarter financial performance really bears a striking similarity to our previous quarters. That is our year over year increases in production volume coupled with higher [inaudible] own gas prices driving significantly higher earnings in cash flow. The Stroud acquisition represents a reasonably priced, conservitaly financed complimentary acquisition.

Though steady organic growth in production and completion in Stroud acquisition are both noteworthy value creating events that both occurred this quarter.

The balance sheet remains in good shape. We've added significant ability to our future cash flow for reinvestment with the new $9.00 hedges in '07 and '08. So John, I'll turn it all back to you.

Thanks, Roger. That was a thorough summary. Appreciate it. I'll now turn the call over to Jeff Ventura, Chief Operating Officer to review the exploration and development activities during the quarter.

Thanks, John. I'll begin by reviewing production.

For the second quarter, production averaged 264 million per day a 13.4% increase over the second quarter of '05 and a 2.7% increase of the first quarter of '06. This represents the highest quarterly production rate in the Company's history and the 14th consecutive quarter of sequential production growth. A 264 million per day is comprised of 141 million per day or 53% from the southwest division, 102 million per day or 39% from the Appalachian division, and 21 million per day or 8% from the Gulf Coast division. This increase was due mainly to the success of our drilling program, approximately 73% of the company's drilling was natural gas.

I'll now review some of the highlights of each of our divisions. I'll start with the Appalachian division and begin with our properties in Virginia with are Nora and Haysi. Specifically for wells drill in Nora to-date the average expected ultimate recovery is 400 million cubic feet per well from a depth of about 2500 feet. Haysi wells appear to be similar to Nora CBM wells. Drilling at Nora and Haysi continues to ramp up with 97 wells drilled in '04, 175 in '05 and 260 planned for '06.

Currently there are about 1,000 producing CBM wells on our acreage. Between Nora and Haysi we believe we that we have about 2500 locations to drill assuming 68 acre spacing. Of the 2500 locations, only approximately 600 are booked as proved undeveloped locations which leaves about 1900 locations yet to be booked. Given our knowledge of the area, we feel the probability of drilling these wells is very high. Given the quality of production and because we own the minerals in this field, our finding costs are excellent and our rates of return are outstanding as well.

Our acreage position in this area consists of 287,000 gross acres. Importantly we plan to test 30 acre in-field drilling later this year. CBM has successfully tested down spacing for 80 acres per well to 40 acres per well in their portion of the CBM field which is adjacent to ours. On our Widen property in West Virginia we finished drilling our five wells CBM pilot project and are in the process of completing the wells.

This area contains a 77,000-acre block in which Range owns 100% working interest and a 100% revenue interest in 74,000 of the acres. Because of the data we have to date the typical CBM well here could potentially recover about 200 million cubic feet per well from a depth of about 1,800 feet. Cost of drilling complete are currently expected to be about $270,000 per well. This equates to about $1.35 per mcf development cost. Potentially there could be as many as 1,000 wells to drill which gives an upside of about 200 bcf net.

I'll caution that it's still early and we need to complete our long-term tests to confirm this analysis. Our CBM projects in Pennsylvania are also moving forward. We have 12 producing wells on our unity acreage and have drilled 10 additional wells. We're also planning on drilling 15 additional coal bed methane wells on our projects in Pennsylvania which are our Chest Spring, Wilpen and Salem projects. Combined we have about 35,000 acres of CBM potential in Pennsylvania. Our success rate for all of our CBM wells is 100%.

Moving on to our shallow type gas sand drilling in Ohio and Pennsylvania, plans are to drill 479 wells in '06. So far this year we've drilled 221 wells and are on schedule. We have an inventory of more than 33,000 type gas sand wells to drill here. Our success rate for these wells is close to 100%.

Next I'll give an update of our shale gas project in Pennsylvania. Our three vertical wells are all still producing well. And the oldest well had been producing for over seven months. Based on reservoir simulation by Holdage/Schlumberger, although it's still early, reserves for these wells appear to be in the 600 million to 1 BCF per well range. We've just finished fracting our fourth vertical shale well and are flowing it back now. Plans are to have all ten vertical wells fracted and on line by early in the fourth quarter.

Our first two horizontal wells did not perform as expected. Based on our knowledge to date it appears to be viable vertical play, although it's still very early to make a final determination as to vertical vs. horizontal wells. Given our current knowledge of the play and believe we currently have 281,000 acres under lease that are perspective for this play, we're continuing to increase our land holdings. Based upon 80-acre spacing, that's potentially 3,512 wells. Assuming the mid-range of what would seem so far 600 to 1 BCF. If you use 800 million cubic feet per well that equates to net unrisked reserve potential of 2.4 tcf. Current costs for a vertical well is 1.1 to $1.2 million in this test phase.

In a development mode I believe we can drill and complete these wells for $900,000 to $1 million per well. Assuming our total cost for well are in the mid point of that are 950,000 per well and we use mid-point in reserves of 800 million our net F&D costs will be about $1.38 per mcf.

However, as we drill and complete more wells my hope and expectation is that we'll continue to drive down costs as well as to improve the completion and there for the recoverable reserves per well. Now when you look at the project, too, and compare it against other shale projects around the country, there are certain key things that have going for it one is a great gas price. One you're looking at about a $0.35 premium in the Appalachian basin versus the various deducts most other places.

And along with gas price, another one is the BTU content of the gas. It's about 1200. At a $6 per mcf price 1200 BTU gas gives you $1.20 increase. With the premium on top of that. So we get a -- one, we have a great gas price; two, we have very good royalties; three, we have relatively low land costs; and four, we have no need for 3D. So all of those really enhance the economics of the project.

The other thing is I think we have a really strong team. I want to take a minute just to talk about the team we have within the company that are working on this project as well as other shale projects around the Company. We've talked in the past about Mark Whitley and Mark's experience pioneer really Mitchells efforts in the Barnett shale that unlocked a lot of the potential for the industry.

With the Stroud acquisition we really pick up three more of those pioneers. We pick up Chris Veeter who on the geological side was one of the original players and who's going to work in the shale. We picked up David Dunn who has tremendous expertise drilling those kind of wells and Greg Fraiser on the reservoir side so we've got a really strong shale team that we have. In addition with Stroud, we pick up Chris Hammock who has a lot of completion experience, very strong player. Also I'd say we had a great team on the ground in Appalachia and leading the way there are Jim Watson and Lynn Pau [ph], really strange team.

In addition to that, we have recently hired a guy by the name of Ray Walker. Ray is really an industry expert in term of completions on really type gas sand well, shale well in general. Ray has actually worked on, I believe, every shale play that exists in the country. Ray has tremendous experience in type gas sands, shale gas and coal bed methane. We're really glad to have Ray on board. And Ray's full time job is going to be working with these various shale plays around the country.

Moving on, in the Trenton Black River we spotted our first well in southwest Pennsylvania there. Talisman operates the well and we're 50/50 partners. I'm excited about partnering with Talisman who's the industry leading in the play. We plan on following that up with Bradford County Drilling in completion this year.

In the southwest division I'm excited about our shale projects there, in particular the integration on the Stroud acquisition is going well. Combined we now have over 40,000 acres on the Fort Worth basin, almost all of which is in the original core or expanding core. The reserve potential in this acreage is about 1 tcf net to range. We currently have three rigs drilling here with plans to be at 6 rigs by year end.

Notably we've completed a well in Tarrant County for initial rate of 7.8 million per day or 5.3 on net, which puts it among the best wells in the Barnett play. We also have 20,000 acres in Reeves and Culberson counties in west Texas. We believe these acreage is perspective for the Barnett Shale, Woodford Shale, Fussleman and Wolfcamp formations. We're currently acquiring 3D here and plan on drilling early next year. We've also initiated an additional shale plan in this division. We current have about 5,000 acres committed that we believe are highly perspective for the Woodford shale in Oklahoma. We plan on spudding a well here late this year.

Range is continue it's in-field drilling and refract program in a West-Fuhrman-Mascho unit in Andrews County, Texas with continued success. As a result of this redevelopment work, Range has increased production over seven-fold since acquiring this property. We still have more than 100 locations to drill on 10-acre spacing as well as several wells to refract.

Even after all this redevelopment, we estimate we'll be recovering only 10% of the oil in place, which is estimated about 213 million-barrels. We've drilled and are testing our first down spaced five acre well.

Initial results are encouraging as the initial test was over 100-barrels per day. We plan to drill three more. If successful we have the potential to double the recovery from is this field through a combination of in-field drilling and water flooding. We have two rigs in this area.

One county to the west of Fuhrman, our unit properties in southeast New Mexico continue to perform well. We originally projected that we could double production on these properties by the end of '06. We've done that and have increased production from about 7 million per day to over 17 million per net currently.

We're also actively drilling and having good success on our Conger and Val Verde properties, specifically in Conger we've had good success extending the limits of the field as well as re-completing some of the wells to the shallower Wolfcamp formation. We recently did a look back of the acquisition that was completed in this area in December of '03. As a result of the field extension and recompletion work the reserves on this acquisition are 42% greater than what we assumed back then. And we'll drill 25 wells there this year.

In east Texas we completed our third chalk well in Tyler County. Combined our three wells are making 12.4 gross or 4.2 net and we have seven more wells to drill there. In northern Oklahoma we have a shallow drilling project that appears to have significant running room. So far we've drilled 41 wells and are pleased with the results. Typical wells range in depth from 27,000 feet deep to 5,000 feet and will produce 250 million to 500 million cubic feet gross per well. The shallow wells cost about 325,000 and the deeper wells cost about 575,000. We've identified more than 400 potential drilling locations on our acreage. With significant upside potential beyond that. We operate and have a 65% working interest in almost all of the wells there.

In southern Oklahoma our deep exploratory discovery is currently being completed in Morrow/Springer section. We have a 16% working interest in the first well. We have 14,400 gross acres in this play we're currently drilling two wells on the prospect. We operate both of them and have a 72% working interest in one and a 44% working interest on the other. Both wells are targeting the Marrow and Springer sands and are planned to drill 20,500 feet. Both wells should reach total depth around the end of the year.

The Gulf Coast division spud it's high potential Norfolk [ph] well and should reach total depths also around the end of the year. We'll have a 25% working interest in this well. We've also established a shale planning division. We currently have about 20,000 acres leased in the Floyde Shale play and are targeting an additional 20,000 acres. We'll most likely drill a well here early next year. We're not disclosing where the acreage is since we're actively leasing.

In summary we're in great shape to achieve 15% production growth for both 2006 and 2007. 2006 will be an excellent year for Range and I'm excited and focused on the future. Range now has a proved reserve base of 1.6 tcf of solid long-life properties. Our reserve life is 15 years. In addition to that, our drilling inventory consists of over 8,000 locations that equates to 1.9 of TCF of net un-risk, unbooked reserves. This is a large multi-year inventory of projects that consist mostly of low-risk, highly repeatable development projects complemented with several higher-risk, high-potential exploration projects.

In addition to that, Range also has 3.9 TCF of net un-risk reserved potential in its emerging place. These are primarily technically driven resource plays involving shale gas and coal bed methane opportunities within our existing core areas. Today we're currently producing about 24 million per day of shale and 20 million per day of coal bed methane or 44 million combined. This is up from zero, 2.5 years ago. I'd expect that this number will continue to grow significantly.

I'd like to conclude my talk by summarizing some of the our recent progress. Today we are producing over 20 million per day from the Barnett Shale in the Forth Worth Basin. Our position in the basin is 40,000 acres. Essentially all in the core or expanding core over tier one. This represents potentially one TCF net to range with the majority of the reserves unbooked.

Today we're producing roughly 20 million per day of coal bed methane. essentially all from Nora and Haysi. There's more than 500 BCF of low-risk upside net to range on these properties with great finding and development costs and great rates of return.

Our first three vertical shale wells in Pennsylvania are performing well. Our position in this play consists of 281,000 acres with un-risk reserve potential of 2.4 TCF net to range. We have about 350,000 acres in five shale place. The Barnett in the Fort Worth Basin, the Devonian in Pennsylvania, the Woodford in Oklahoma, the Floyde in the Black Warrior Basin and the Barnett/Woodford in the Permian Basin.

Our first five acre in-fill well in the Westfirm and Moscow unit had an initial potential of more than 100-barrels per day. We'll drill three more five acre in-fills. If this works it could lead to drilling a few hundred more wells. Importantly between five acre in-fill drilling and water flooding we potentially could double the recovery factor from 10% to 20% in it's field it contains 213 million barrels of oil. For the last year I've discussed the possible upside in CBM on our Widen property. We've now moved from the study phase to the coring phase into the pilot phase having drilled the first five wells of the CBM pilot project. Reserve potential is 200 BCF net to range.

In regard to high impact wells, we're drilling and operating two deep Marrow/Springer test in Oklahoma. These wells are in between our [inaudible] discovery in a new Marthel [ph] that flowed into a pipeline added an initial rate of 20 million per day. This project has the potential to be over 100 BCF net to range with wells that can produce a the gross rates of 10 to 20 million per day per well.

We've talked about our high-potential Norfolk project for a while now. The first well is drilling head and should reach TD by year-end. If successful, in a full development mode, this project could add approximately 150 million per day net to range on top of the 264 million per day that we averaged during the second quarter.

We've also discussed our joint venture with Talisman in the Trenton Black River play. Our first well just recently spud. And the Tonkawa project in northern Oklahoma that we've barely discussed now has 41 wells drilled on it. It looks very promising and we believe there could be more than 400 wells to drill.

All in all, pretty exciting stuff, and bottom line, what I'm trying to emphasize is there are many different ways to win at range. Back to you, John.

Thanks, Jeff. Now let's look to the remainder of 2006. Based on what-- that you can see from some of Jeff's comments, we expect to continued to see strong and operating financial results. In our view, the third quarter like the first and second quarters will be important that it will continue to demonstrate solid quarter-to-quarter execution of our plan. It all starts with production.

We're looking for third quarter production to come in at approximately 287 to 288 million a day representing an 18% increase year-over-year. As Roger mentioned, these volumes do not include the Stroud/Austin Chalk properties that we intend to sell. Assuming today's future prices and the hedges that we have in place we anticipate third quarter price realizations after hedging to be in the $6.40 to $6.50 per mcfe range.

This is slightly higher than the $6.33 per mcfe realized in the third quarter of 2005. With a slightly higher anticipated prices and the 18% projected ramp-up in production, third quarter 2006 oil and gas revenues are anticipated to increase year-over-year by roughly 20%. So it's a very healthy increase.

Looking further ahead we anticipate production to continue to increase in the fourth quarter '06 and for each quarter in 2007 so we expect to continue our streak of consecutive production increases.

As all of us have said as a result of the Stroud acquisition and also our larger capital budget, we've increased our production growth targets for both 2006 and 2007 from roughly 10% to 15%. So a 50% increase in production growth compared to where we thought we were. So that's pretty promising as well.

For the year cash flow from operations is anticipated to increase by about 30% over 2005. You can see 2006 shapes up to be a tremendous year.

Looking a little further ahead and kind of thinking out loud, we continued to drill some pretty high impact wells as Jeff mentioned. We've got four or five exploration wells that are pretty exciting right now. Chad and his team continue to look at acquisitions. The good news is that we're not going to require any successes in these areas to meet our 2006 goals. Executing our plan and successfully drilling our development program is already adding significant shareholder value so far in '06. Any additional exploration success or acquisitions will, in my mind, just be icing on the cake.

Stepping back a little bit, over the long term we believe shareholder value is determined by the degree of success an oil and gas has generating attractive returns through the wise investment of capital. The efforts and quality of our technical team are critical to this process. At Range we've built a high quality technical team that is generating attractive opportunities in each of our areas of operations. As Jeff mentioned, we continue to add some very high quality technical people even as just a few weeks ago, months ago in terms of Ray Walker and some of those guys.

Couple with all that today we have the largest drilling inventory in our history with over 8,000 projects comprised of a very large number of lower-risk development and exploration projects and diversified group of higher-risk, higher-potential exploration projects.

We believe Range is unique in that for our size we have a very large transparent drilling inventory and an even larger 3 million plus acre resale position. And as Jeff mentioned we've really worked hard at building and maintain a top-core tower cost structure and expanded our drilling inventory to drive the long-term growth and profitability of the Company.

My last point really focuses on our capital program. As mentioned in our news release and as Roger's mentioned we increased our capital spending for the year to $551 million for the year. This is $122 million higher than our beginning of the year budget.

The increase is attributable to a number of areas. 52 million is attributable to exploring the recently acquired Stroud properties. 42 million is for additional leasehold and seismic, which almost exclusively is in areas were we've had drilling success and/or is in our shale plays. 12 million result from taking larger working interest in wells in areas where we've had recent drilling success. 11 million is attributable to service cost inflation and lastly 5 million is for additional pipelines and facilities.

The capital is directly related to increasing our 2006 and 2007 production growth targets 50% from 10% to 15%. We view the key driver for increasing the per share values generating attractive returns on capital expended. Since Jeff, Roger and I approve on expenditures over $200,000 we are focused on making sure we spend our capital wisely. Expenditures are only approved if they meet our hurdle a rate of return based on our AFC price debt which currently at $6.50 for gas through the end of 2006, $6 for 2007 and $5 for 2008 and beyond.

While the much-- obviously while the much considerably higher future strip prices result in much higher returns, we're not relying on them to meet our baseline hurdle rates return.

Also important in my view is the competitive capital allocation process. Because of our large inventory we have the issue of balancing our capital spending with our cash flow. As Roger mentioned, cash flow, coupled with the asset divestitures, will more than cover our 2006 capital spending. Therefore, we will not have to increase debt to fund our capital program.

All this being said, we are constantly looking for ways to high grade our capital spending. We have the drilling inventory to spend far more than the 551 million currently budgeted for 2006. Also we turned down plenty of interesting projects that meet our risk return hurdles but not as attractive as our other projects that we're putting money into.

Another factor is that-- as we become more confident in our CBM and shale projects and other emergent plays we have increased our acreage acquisition budget in those areas. For the year our land budget now totals $59 million. If we are successful acquiring the lease budgeted, I and the rest of the shareholders will be rewarded as the risk potential of this acreage is quiet high.

The difficult part will be for our land department to execute and pick up the acreage on favorable terms. So far they've done really a very terrific job.

So in summary, I think there's four main points-- take away points in terms of capital budget: one, the increased capital budget will lead directly to higher production; two, we're not depending on higher prices to achieve our target rates of return; three, the capital increase will not require the increase of debt; and fourth, a portion of capital is going to land acquisition and play, at least that in our view have the potential to double the value of the company.

All in all I'm extremely confident that we're been good stewards of our capital and I am excited that it will significantly benefit to per-share value of our stock over time.

With that, operator let's turn the call over to questions.

Thank you, Mr. Pinkerton. [OPERATOR INSTRUCTIONS] Your first question comes from Robert Lynd of Simmons & Company.

Good afternoon. You mentioned your 50% interest in Appalachia drilling contractor. Can you tell me how many rigs are currently in the fleet and their depth capability?

Robert, John Pinkerton here. Just give you a little background, this is a small contractor, private company that we have done business with, as Roger mentioned I thin, for well over ten years. We have a lot of confidence in their capabilities.

Really, what we're trying to do here is really give contractors like this, that we have that relationship, a way to monetize some of the value gain without them having to sell out to some of the bigger guys because obviously the bigger guys want to continue to increase rates. So that's really to concept, but importantly we don't want to be in the drilling business. So it was important for us for the founder of the company to stay on board and continue the management. The good news is it's not located, at least that company is not located where our main Appalachia office is, so that will keep our guys from going over there and bargaining. I think it's a good fit.

To directly answer your questions, there's nine drilling rigs. And there's about nine service rigs in total. And these things are capable of drilling anywhere from 3,000 to about 9,000 feet. So it really focuses on our gas and drilling and some of our shale gas drilling. We won't use these rigs, for example, to drill the Trenton Black River wells that are-- at least the deeper ones that are below 10,000 feet. We do have some TBR wells that are shallower, so we have 4,000 feet that these rigs could do. These are focussed on tight gas end wells and our shale wells will be drilling -- we'll need three or four times this many rigs on an ongoing basis over the next three or four years so this is really just to -- it really supports about a third of what we think the ongoing is going.

I think a good decision obviously not a whole lot of money. We think it's a good way to tie up some rigs at a reasonable price.

Right, thanks. While we're talking about the Devonian Shale, can you explain what you saw in the initial horizontal wells? Is it looking like you're not getting the reserves there to justify the additional well cost? Can you give us an idea what you need from a horizontal well to make it work.

Let me just talk about it generally.

When you look at a lot of the plays, ultimately the shale plays whether it's the Barnett or Woodford or Fayetteville went from vertical drilling several vertical wells to drilling horizontal to where the horizontal wells really outperformed vertical. You've go to remember we're very early on here in our play. We've got three verticals online, about to have a fourth and we drilled a couple of horizontals and by the end of the year we'll have ten verticals and three horizontals.

As you go through there and you learn what works and what doesn't work, as we go forward, we're putting together our budget for next year, we'll be significantly ramping that up. We don't have numbers yet. And based upon what we learn we'll go out and try some different things next year. I think what's important, if you look at technical teams in the industry, there's a lot of good people out there but I'll put our team against anybody out there. I think we got a lot of smart people working on it and I am sure we'll continue to make improvements.

One follow-up question to that. With these initial test wells, are you staying near existing gathering and transportation infrastructure. Can you just remind us what that --

We've got good capacity and good room to ramp and growth from where we are. We're actually the first three wells are selling gas. They are going into a sales line. We're in a great area in terms of markets. We've got capacity to ramp up significantly through next year so we're in good position there. We're near a good infrastructure.

Great. Thank you. That's all I had.

Yeah, Robert, just to add on, this is John, one of the competitive advantages we have in the area, we own about 5,000 miles of gathering transportation lines in Appalachia ourselves so the good news, in a number of these projects we already have tight gas end wells feeding directly into our pipeline system. So, again, as Jeff mentioned, there's a number of what we think are competitive advantages to it. That is one as well.

So as you step out in the play you're not having to build up infrastructure as you move further away from what you started?

There's a gathering things that you'll have to add but there's very good infrastructure in and around where we are.

Okay. Thank you very much.

Your next question comes from Andrew O'Connor of Wells Capital Management

Good afternoon, guys.

Hey, Andy.

Nice cost control in the second quarter. I wanted to know, can you elaborate on what you think unit costs will be in the third quarter or the second half of the year? Operating expense, production taxes, G&A. Roger, I thought I heard you say that G&A would be flat with the second quarter, $0.39 per mcfe

It is going to be right around that $0.39, $0.40 range. We put Stroud in, Stroud being a full cost for capitalized of G&A so we made some G&A reductions there. They're going to come out of the final costs number, not the G&A number. Long story short, that $0.40 number is a good number for the rest of this year.

Can you speak to operating expense on production taxes?

This is John again. The out-cost ought to be level essentially where we are in the second quarter, maybe a penny or two higher for the rest of the year. On production [inaudible] just-- directly reflect on whatever prices do, so. You think prices are going to increase, I would increase, if you think they're going to decrease, I would decrease it. It's just a pure function of price.

Thanks, John. Your expiration expense in the quarter also was good. Any comments going ahead?

Yeah. Jeff mentioned we are drilling some pretty high-potential exploration wells. The good news, if they work we'll all be fat and happy. If they don't work we'll not only be fat but we'll have a $20 million exploration expense number. Again, it all depends on the success.

I think the 7 million is way on the low side. I think $10 million a quarter, and if we don't -- those wells aren't successful, it could be as high as 20 in a quarter. As we move along here a little bit as we -- as some of these wells drill out, we'll make sure we keep everybody apprised. Because that variable-- that's something that we'll know in real time and we'll make sure we announce that so everybody can adjust their numbers accordingly.

Thanks for that and lastly, how would you compare your service costs increases currently relative to what you were experiencing at the beginning of the year? Thanks so much.

I would say, generally speaking, it looks like there might be flattening of that. In the long run it will follow what oil and gas prices do. The good news is there's a moderating effect there.

Thanks again.

Your next question comes from Rahan Rashid or Friedman, Billings, Ramsey.

Good morning, Jeff, John. On the Nora/Haysi 30-acre down spacing, you'd mentioned maybe 1,000 wells already on our acreage and 2500 more locations or can I just double that in terms of 3500 more locations over time, obviously, but-- or should we think about it in some different fashion?

That's simplistically, I think that's the correct thing to do. You get into some areas as you get towards the fringes or edges of the fields it depends on what prices are and what the economics are. There may be some surface locations that are hard to get to because you're in rugged terrain and things like that. Generally speaking your logic is right.

And remind me again what's the reserves per well in the Nora/Haysi area?

To date it's been 400 million cubic foot per well.

We talked about at some point in time might there's an upside to that number as well, maybe the recovery rate is higher than what you have modeled in or is that to early?

It's early. There are some things in terms of better completion technology, re-completing more coals, things like that. It could potential enhance some of that but it's a little early to talk about that.

On the Pennsylvania shale vertical wells, given F&D and put your LOE all the other overhead costs on it, what kind of gas price you think you'll need to make that work?

I think that it's early but a $5 gas price or something like for [inaudible] that is not unreasonable to get rates of return over 20%.

A 20% rate return on that number, okay.

Again, if you look at all shale plays over time, if you get in a mode where you're drilling 500 or 1,000 or 2,000 wells people usually get smarter about how to drill them and save money and conversely they get smarter about how complete them and usually get a little bit more out.

Fair enough. We talked about having access to drilling rigs now in the Appalachian between yourselves, [inaudible], Cabbot, equitable to put everybody else credible put egg everybody else together in terms of services do we have or will we be able to build capacity to ramp up to drilling the kind of numbers that we could talking about as an industry? In '07, '08 short enough of a timeframe. I guess.

I mean those are things I think in time you'll have to see some expansion just like in the Fort Worth basin, and it's interesting Whitley really led the effort when Mark started in the Fort Worth Basin in the Barnett Shale. The basin didn't have all those things. Now you can get anything that you want from multiple vendors. Maybe that's the model for the Appalachia basin as well.

Remember, Rehan, at Nora you're talking about truck-mounted rigs, the Ohio area your talking about very shallow type of rigs. You're not asking for huge capacity wells unless you're really going to be drilling horizontally. And the Trenton Black River and those kind of where your demand will clearly outsource the supply.

So, Rodney, with your statement am I to presume that you don't need that kind of an expansion and service capacity speciality for your Nora/Haysi drilling ramp?

Well like Rodney said for Nora/Haysi, one rig you can do two wells per week. One rig can drill a hundred wells a year basically.

I am not sure I understand the rig part but other services components--

Fracting isn't a big issue. They're relatively simplistic. It's a basic kind of operation. In time there will need to be gathering on the gathering side there will need to be some expansion.

Our Appalachian team is really focused on logistics. They plan these programs on an annual basis. They are already anticipating locations and moving rigs on there. They'll be ahead on their locations and doing the completion work. It's all Logistics and working with our vendor is really key to keep them informed and once a vendor sees you've got the need it will nationally start gravitating for additional services to be there. They can see the need to expand with their own capital because the rates or return are [inaudible] so it's a very joint effort in developing these programs.

Two more quick questions on the operational front. Jeff, I didn't quite catch the project with that you referred to in conjunction with Marathon could you remind me again what that is and also in the Widen field, should we at this point in time think about the same $5 gas number to give us the 20% rate of return or would that be something higher?

In terms of mentioned Marathon I was talking about our deep drilling, the Marrow/Springer drilling in southern Oklahoma. There's a big area we've got real nice acreage position in excess of 14,000 acres. On that, on simplicity straight, our discovery well is on a big structure, big feature about five miles away, which is pretty far. Our Marathon well is on that same general area or same kind of feature. Their well came on 20 million a day, strong producer flowing into a pipeline at high pressure. I believe once we get our well on-line we could be looking at 10 to 20 million a day from ours. In between those two five mile wells we're drilling two wells to the similar formations. So they have nice upside and lots of running room if it works and a lot of rate growth for us. You could be looking for-- I said our reserves could be 100 million per day. You know our net rates from those things could--

Net rate could be 100, what do you own in this discovery valve and the other two wells that are going to get drilled?

We own in the discovery well our interest varies across the structure in the first discovery well that's being completed we're 16%. In the two wells we're drilling we're at 72% on one and 44 on the other.

Rehan, that means I'm rooting for the 72% well.

I'll take 44% of [inaudible] million a day.

Rehan, it's important, it's John, we do not own an interest in a Marathon well.

Fair enough.

Just to make sure it's clear.

John mentioned but on all of our economics across the Company, we pressure test everything-- at basically it tills down but in essence it's a $5 flat gas price going forward. On that price deck unless our projects need a rate of return of 20% or better, some of them may be high teens but almost all of them are 20% or better. A lot of them are 30 or 40 under that flat case. We won't do it. So Widen again meets that criteria. That's the kind of pressure test we do on our economics with a strong focus also on unit cost. Typically we like to see our finding and development costs under $2. Again there may be some exceptions to that for different reasons. Those are some of the criteria we look at.

Going back to those Springer/Morrow wells the two wells should be done by when?

End of the year.

I'm going to presume that's not in the next year 15% growth guidance?

Correct.

Quick house-keeping question. Share count Rodney after the Stroud deal?

We have about 138 million shares outstanding and then with your diluted with respect to stock options [inaudible] fully diluted shares ought to be about 142 million.

Thank you.

Your next question comes from Rodney Clayton of J. P. Morgan.

Good afternoon.

Hey, Rodney, how are you doing?

I'm fine. Couple questions. First of all, have you seen any issues with line pressure or given the storage that we have and so in what regions and have you had any production curtailments to go along with that? Secondly, a few of your competitors have recently announced plans to pursue NLP or LLC structures. Do you see that as a potential in any of your regions?

I'll answer the first one. So far we have not seen increased line pressures or curtailments in the regions that we're in.

Hi, this is John. I'll answer the second one. In terms of the MOP idea, and I won't spend a lot of time on it anybody wants to talk to me feel free to call me personally. We have -- we've studied those quite intensively over the years. Rodney Waller and I when we were at Schneider Oil [inaudible], I think the second production MOP that were done many, many moons ago. So we're familiar with them. There are obviously positives and negatives about them. The one thing I think everybody needs to be clear on is oil and gas production does decline. MLP investors like to have steady to increasing distributions. That is where the rubber meets the road. So I would advise everybody to be very careful on this front and I know everybody will be. That's my advertisement.

Okay, that sounds good. Thanks a lot.

Your next question comes from the line of Ron Mills of Johnson Rice.

Most questions have been answered. But John, -- or Jeff, as it relates to the Trenton Black River, what's the timing on that well? It sounds like it spudded. But what's the timing on the well drilling and the plans over the remainder of the year?

You're looking at roughly 40 days, 45 days to get the TD on the well that's currently drilling. We're in the process of working out some of the future plans with our partner Talisman as well as what we're going to do in the north. And we will be drilling some shallower wells up in New York as well.

Is it planned to spud at least one more deep test later this year?

We're working on that. I would say I wouldn't be surprised. That's a possibility but it's a little too early to say. I think you'll see more drilling next year but it could be potentially another well this year.

[inaudible]If we were in total control we would know exactly but we don't want to circumvent what Talisman wants to do since they are the lead operator.

Okay. Then from the Pennsylvania shale, the vertical wells and the potential you outlined, Jeff, almost two and a half keys of upside, did you imply that as you learn more through the play the horizontal idea still may eventually work but the economics on vertical wells and the upside is still something that doesn't concern you all at all? And actually leaves you all excited about that play?

Absolutely. That's a great way to characterize it. When you look at the vertical well, I'm pretty encouraged early on, on our first three tries we have vertical wells that look like they're going to generate reasonable rates of return and good finding costs and could be highly repeatable with our first three tries. But, just like you said, I would not write off horizontal wells. From an engineering point of view, theoretically, ultimately a horizontal well in all the other place so far has really delivered superior results. Time will tell what direction we go. That's still a big upside one that the vertical wells could get better and two that horizontal wells may be able to improve on that.

Okay. Finally, you walked through, John, the CapEx increase, the $550 million As you look out to '07 would you expect a similar type capital budget or a slightly higher one to enable you to reach that 15% growth target you talked about?

I think there's no doubt it will be higher. I just don't know how much higher. And we need to get closer. The good news is there are hedges in place our cash flow through '07 is going to be dramatically higher than our cash flow in '06. That's almost guaranteed because we've got such a big part of our production has, a great deal of it $9.00 and there's some really attractive collars on there as well. We've got a pretty good idea where our cash flow is going to be. We typically try to balance our cash flow and our capital expending. I'd like to spend 100% of our cash flow if we could achieve those target rates of return. Because I think that's what our shareholders are paying our management and employees to do. I'd be disappointed if we didn't do that. If we can do better than that, we'll spend 110% but we're not going to go crazy and way overspend our cash flow. We just don't think that's prudent long-term.

So the book value on your assets for sale is about $140 million on your balance sheet. To clarify it, is that solely the Stroud/Chalk assets or does that include some of the legacy Range/Chalk assets as you all contemplated throwing in that package

Ron, that is solely the allocated value of the Stroud/Chalk assets. That really is an accounting number and I don't think you should perceive it anything other than that.

Okay. And when you pursue that sale, any additional data or thoughts on including the Range/Chalk properties with that?

Well, everything at a price, is for sale. Right now, what we're focused on is the Stroud/Chalk properties. The Range/Chalk properties actually have a fair amount-- we've got five to seven to eight more wells to drill, to develop out the acreage. Wouldn't surprise me then if we wouldn't sell it. There are different points in their age and maturity. That's really the difference between the two asset packages.

They're in different counties. The production characteristics are different, the finding costs and all that kind of stuff. Like John said we're open to doing the right thing for the shareholders, whatever that is.

All right. Let me let someone else jump on. Thanks.

Anybody that calls and would like to buy it, feel free to call Mr. Stephens.

Your next question comes from Marshall Carver of Pickering Energy.

Just a couple quick questions. Good quarter by the way. On DD&A rates you talked about a $1.60 was that for the full year or just the second half of the year?

Full year.

If the first half was below that, the second half should be above?

The second half ought to be in the $1.65. The first half is $1.55 so you average $1.60.

Okay. And a couple of questions on the Floyde Shale, would that first well be a vertical or horizontal well?

The first well probably be a vertical well. Again, we'll look at it, we'll study it, we'll do the right thing, but I think our guys that have a lot of expertise think that's the way to start in a lot of these plays to really understand it with the vertical wells gather data and then use that to design and decide what we want to do horizontally.

Is there any-- the cost of the well or anything like that, that you could give me rates you would be excited about it, things like that?

It's too early on that.

Then on the Appalachian shale, the vertical wells you talked about a full-development it would be 900,000 a million dollars per well, [break in audio] is there some additional cost we should be adding to that? Basically all in. Thank you very much.

We own a lot of gathering in the area so it's really just tie-ins. There's no material. This is unlike the Delaware basin play out there where aren't much pipeline-- there's quiet a few pipelines in the area.

There's no expensive 3-Ds, the land costs are relatively low.

Okay. Okay, thank you very much. Good quarter.

Thank you.

We are nearing the end of today's conference. We will go to our Pavel Molchanov of Raymond James for our final question.

Thanks very much. You guys put the assets you're selling on the balance sheet at 140 million. I was wondering if you have a sense of in the marketplace what kind of number might you be looking at in an actual sale? I know that's kind of a speculative question.

What do you think commodity prices are? Beauty is in the eye of beholder. It's just hard to say. In reality, you know, the market will determine it. We've gotten the number -- the good news is we've gotten a whole slew of people that have called us that want to look at it. Chad and his team are putting together the packages to show it to people. The market will determine that. I think the thing that we shouldn't get too caught up with is my theory is we need to get it sold and move off to the next thing. It's not whether we get 20 million or 30 million plus or minus I don't think really matters. We need to get the thing sold and take that capital because we got plenty other places to use the capital. If we don't, obviously we'll be happy to shrink the equity size of the Company. I think the key is just be very methodical, be very disciplined, get it done, move onto the next thing.

Thanks very much.

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

I'd like to thank everybody that joined us today. We're obviously very pleased with the results. There's a lot of really exciting things going on at Range in terms of our shale plays our CBM plays, and a number of really high potential exploration projects as Jeff alluded to. I'm really proud of our teams keeping our costs under control, which is obviously difficult in this environment.

The good news is it sounds like we're firing on all cylinders. That's a little scaring me. We'll keep our hands clearly on the steering wheel and not lose focus here. If there's any of you all -- I know we've gone over a bit. If there's anybody that didn't get an answer or didn't get a chance to ask a question, pardon me, feel free to call Rodney or any of us. We'll be happy to answer your questions.

Thank you all for joining us. We look forward to the rest of the year. This is going to be terrific. We're very excited about what we're doing. We're really looking for stock price to be continue to go up. So thanks again. We'll see you next quarter.

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