Range Resources Corporation Q2 2008 Earnings Call Transcript

| About: Range Resources (RRC)

Range Resources Corporation (NYSE:RRC)

Q2 2008 Earnings Call

July 24, 2008 1:00 pm ET


John Pinkerton - Chairman of the Board, Chief Executive Officer

Roger Manny - Chief Financial Officer, Executive Vice President

Jeff Ventura - President, Chief Operating Officer, Director

David Amend - Investor Relations


Joseph Allman - J.P. Morgan

Rehan Rashid - Friedman, Billings, Ramsey &Co

Ronald Mills - Johnson Rice & Company

Marshall Carver - Capital One Southcoast

Jack Aydin - Keybanc Capital Markets

Thomas Gardner - Simmons & Company

David Heikkinen - Tudor Pickering

Leo Mariani - RBC Capital Markets

Dan McSpirit - BMO Capital Markets


Welcome to the Range Resources second quarter 2008 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.

At this time, I would like to turn the call over to David Amend, Investor Relations Manager of Range Resources.

David Amend

Range reported results for the second quarter of 2008 posting our 22 consecutive quarter of sequential production growth even during the challenging quarter. We have posted on our website supplemental tables to assist you in understanding many of the number in the press release.

In the press release, we have furnished some non-GAAP statements, which allow you to compare our results to our historically reported numbers, which include the Gulf of Mexico operations that we sold during 2007, and in table five of the supplemental tables, we have presented a summary of the reported numbers, which correspond to the analyst's models taking out the non-cash items.

On the call with me today are John Pinkerton, Chairman and Chief Executive Officer, Jeff Ventura, President and Chief Operating Officer and Roger Manny, Executive Vice President and Chief Financial Officer. Before turning the call over to John, I would like to cover a few administrative items. First, we did file 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 of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings, to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you detailed information on our current hedge position by quarter.

We have also updated on investor presentation to reflect information that would be discussed on today’s call and it will be available on our website tomorrow. Second we will be participating in several conferences in August and September, check our website for complete listing. We will be at the intercom energy conference in Denver on August 10, and the Lehman CEO energy conference in New York City on September 2nd. Now let me turn the call over to John.

John Pinkerton

Thanks David. Rodney Waller as many of you all know isn’t with us today due to a illness in his family but he’ll back with shortly. Before Roger reviews the second quarter results, I’ll review the key accomplishment so far this year. On a year-over-year basis second quarter production rose 22% meeting the high-end of our guidance by $6 million today.

As David mentioned this marks the 22nd consecutive quarters of sequential production growth. The driver of the higher than expected production was exceptional performance by really all of the divisions, as you recall I mentioned that in the first quarter it was one of those rare quarters where, everything went right essentially nothing went wrong. For the second quarter we were now as fortunate and that we had a number of issues we had to overcome. Most significantly we had on average $18.5 million a day of Barnett production shut in due to the third party pipeline curtailments.

To offset the shut in production, our operating teams reshuffled the drilling schedule, performed numerous work over, fast forward well turn on and pulled many rabbits our of the hat, so to speak. I’m extremely proud of their performance and more publicly thanks them for extending our production growth to 22 consecutive quarters. On our drilling program, we remained on schedule throughout the quarter and we drilled about 180 wells. We continue to be extremely pleased with the drilling results which Jeff will talk about a number of the wells. We are drilling really fantastic rate of returns and there currently we’ve got 30 rigs running.

The 22% increase in production coupled with the 17% increased in realized prices, drove up cash flow $121 million. This is $64 million or 41% higher than the second quarter of last year, since it was a terrific quarter, by posting record production volumes in the benefit of strong commodity prices, clearly we set the stage for a another record year for Range.

Because of the shut in production and the extra cost we incurred to overcome the shut in coupled with the continue ramp up in personnel, in our Marcellus shale plan in Appalachia. Our unit costs were higher versus the prior year. Once we get the Barnett production back on, which should happens sometime by the end of the year and the Marcellus gas on, we are confident our per-unit cost will drop back down to historical levels.

With regard to the, merging plays a heck of a lot of - headway was made in the second quarter as we mentioned in the press release as Jeff’s going to talk about. We drilled some terrific wells, we continue to expand our acreage positions and our infrastructure projects are on track and look really good. In addition, we continue to build out our technical teams, especially with regard to the Marcellus and really given a great advantage and I think the quality of well speak to that.

At the end of the day, I really couldn’t be more pleased with what we have accomplished so far in the year. It's a real testimony to everybody of Range. With that Roger why don’t you review the financial results?

Roger Manny

Thank you, John. The second quarter of 2008 proved to be true to its name as we have recorded the second highest quarterly oil and gas sales, second highest quarterly EBITDAX, and the second highest quarterly cash flow in our history. For oil and gas sales, including cash settled derivates, were 313 million, 42% higher than the second quarter of last year.

EBITDAX for the quarter, came in at $244 million, 41% higher than the second quarter of ’07 and cash flow was $221 million also 41% higher than last year second quarter. The strong quarterly performance was driven by a 22% year-over-year quarterly production increase and a 17% higher year-over-year quarterly average oil and gas price.

Interestingly, the second quarter of this year unfolded just like the second quarter of last year. The first quarter of ’08 and ’07 both set new record quarterly highest for oil and gas revenues, EBITDAX and cash flow and in both years this first record quarter was followed by a second quarter of second best results. So while production continues to head up into the right, the second quarter 2008 realized oil and gas price per Mcfe of $9.03 was 5.5% below the $9.55 price realized in the first quarter of this year.

The second quarter 2008 cash margins was $6.34 per Mcfe - $6.37 per Mcfe 17% higher than the second quarter of ’07. As per net income oil and gas companies that hedged their production to protect their cash flow had a tough second quarter in ’08 and Range was no exception.

Net income was impacted by several non-cash expenses, first the non-cash 164 million mark-to-market loss on our unrealized oil and gas hedges. Second our non-cash $7.5 million mark-to-market expense, due to the increase in Range’s stock price and third a non-cash $5.3 million reduction in unproved leasehold value.

The 2008, second quarter GAAP net loss was $35 million compared to prior year of second quarter GAAP net income of $64 million. Quarterly earnings calculated as analysts do, were $75 billion or $0.48 per fully diluted share, compared to the analyst estimate of $0.54 per share and the difference was $5.3 million in non cash acreage expirations which were included in DD&A this quarter.

Because the mark-to-markets forward price curves for oil and gas have declined since the quarter end, for illustrated purposes we remark-to-market our quarter end hedge position using the closing oil and gas prices from last night, July 23. We discovered that had oil and gas prices at the end of the quarter been the same as they were from yesterday, the non-cash $164 million pre-tax mark-to-market loss would have been completely eliminated.

Our cash flow per diluted share this quarter was $1.41 matching the analyst consensus. As always please visit the Range Resource’s website for a full reconciliation of all these non-GAAP measures including cash flow of EBITDAX, adjusted net income and cash margins.

Cash direct operating costs for the second quarter of ’08 was $1.05 per Mcfe compared to $0.96 in the first quarter of this year and $0.86 last year. There are several unusual items embedded in this higher cost figure, the largest of which is $0.05 per Mcfe associated with shut-in Barnett gas production. The shut in wells still require maintenance and incur expense even though they are not producing.

Also work over expense for the second quarter was $0.10 per Mcfe and that’s up $0.06 from the first quarter and $0.07 from last year. Adjusting for these items cash direct operating costs would have been $0.96 consistent with our mid to high $0.90 range cost guidance previously provided. Looking forward, we expect cash direct operating expense to run in the high $0.90 range to the rest of the year.

General and administrative expense adjusted for non-cash stock comp expense was $0.49 per Mcfe for the second quarter up from the $0.44 figure in the second quarter of last year. G&A expense like direct operating expense suffered in the second quarter due to higher payroll costs and the production curtailment that John mentioned.

To illustrate the point we now have over 70 full time professionals on our Marcellus team on the ground in Appalachian, building a terrific acreage position, drilling excellent wells, but producing very little gas until the infrastructure is completed, and this is a temporary unit costs increase that reflects the reality of developing a world class resource from scratch as opposed to buying existing production.

Placed in the proper prospective, trading a nickel in short-term G&A expense for finding development and acquisition costs that are dollars below industry average is a good trade for the shareholders. Cash G&A expense will likely remain in the high $0.40 range per Mcfe for the rest of the year.

Second quarter interest expense was $0.69 per Mcfe flat with the first quarter of this year and $0.07 higher than the second quarter of last year and as we’ve continued to increase our debt level and periodically refinance our short-term floating rate bank debt with fixed rate 10 years subordinated notes our interest expense has increased. So expect interest expense per Mcfe to run in the low to mid $0.70 range for the rest of ’08.

Exploration expense for the second quarter of ’08 excluding non-cash topics was $18 million, that’s $8 million higher than the second quarter of last year mostly due to a $6 million increase in seismic expense and it’s been a while since I mentioned it, but please remember that Range does not capitalize any EBITs exploratory or developmental seismic expenses. So they ebb and flow of our seismic activity that timing flows straight through to the bottom line.

Now we anticipate that quarterly expiration expense including non-cash comp will approximate $20 million to $22 million per quarter for the rest of the year. That depends of course on our ongoing drilling success and the timing of seismic purchases.

Depreciation, depletion and amortization per Mcfe for the second quarter of ’08 was $2.24 compared to $1.81 from the second quarter of last year. Of this $2.24 figure $1.95 represents depletion expense, the same as last quarter while $0.14 is attributable to depreciation and accretion expense and as previously mentioned $0.15 or $5.3 million came from leasehold expirations. Our core depletion rates should remain in the $1.95 per Mcfe range for the rest of the year.

Reductions in unproved acreage values are more difficult to predict. However, we do expect to incur $5 million to $8 million per quarter in unproved acreage value reductions primarily from expirations going forward as we continue to drill on a high-grade our acreage portfolio. So, DD&A with the ongoing acreage expirations should run $2.24 to $2.27 per Mcfe for the reminder of the year.

For the six month year-to-date ’08 period oil and gas sales plus settled derivatives totaled $635 million up 42% from the $449 million during the first six months of ’07. EBITDAX for the first six months of ’08 was $509 million, up 44% from last year and cash flow increased to $462 million, 45% higher in ’08 compared to the $318 million figure from last year.

The balance sheet was substantially strengthened during the second quarter through two transactions. First we issued 4.4 million new common shares generating $282 million in proceeds which was used to repay bank debt incurred earlier in the year to fund Barnett Shale acquisitions. Second we refinanced part of our short-term bank debt $250 million of 7.25% 10 year subordinated notes.

Now, with the issuance of equity our debt-to-cap ratio was reduced back below our 40% target, but rose to 43% at the end of the quarter due to the $279 million of negative of the comprehensive income that we recorded due to our hedged position. Range ended the quarter with nearly $800 million in unused committed bank facility funding and we had a $1.3 billion in unused bank borrowing base capacity. We have our strongest balance sheet in recent memory.

As John mentioned, at the start of the call, the first quarter of ’08 was one of those rare quarters when virtually everything went right nothing went wrong and every part of Range organization exceeded their targets. The second quarter of ’08 was not this type of a quarter. Our production curtailments in the Barnett and the need to right size the Marcellus team before infrastructure completion have temporarily increased our unit cost structure, but this should not obscure the fact that top line year-over-year quarterly oil and gas revenue growth is 42% and we have posted 41% year-over-year quarterly EBITDAX and cash flow hereof.

Lastly the balance sheet was substantially improved during the quarter and Range has more than enough liquidity to execute it’s operating strategy going forward. With that John I’ll turn it back to you.

John Pinkerton

Thanks Roger. That was an excellent update. I’ll now turn the call over to Jeff Ventura to review our exploration and development activities. Jeff?

Jeff Ventura

Thanks John. I'll begin by reviewing production. For the second quarter, production averaged $381 million per day to 22% increase over the second quarter of 2007 and then 3% increase over the first quarter of 2008. This represents the highest quarterly production rate in the company's history and the 22nd consecutive quarter of sequential production growth.

Let's now review three of our key projects. First, I'll start with the Barnett Shale in the Fort Worth Basin. During the second quarter we experienced curtailments in the Barnett and they were significant. At times we had a well over $30 million per day shut-in. The good new is that despite that we were still able to beat our production target. We were able to do that because of the strength of our portfolio of opportunities and more importantly because we have a team that consistently rises to the occasion and delivers.

The curtailment situation in the Barnett is improving with the start up of a new gathering/transmission line with the take away capacity of $300 million per day scheduled for later in the third quarter. Another line with additional take away capacity in excess of $700 million per day is scheduled to start off late in the fourth quarter.

Currently, we have six rigs running in the Barnett. Net production is about $90 million per day today and in addition to that we currently have about $22 million per day shut-in. Despite the shut-ins we are still projecting 19% production growth for Range for 2008.

Range currently has a 109,000 net acres in the Barnett Shale play, 42,000 net acres on Tarrant, Johnson Denton, Eastern Parker, Eastern Hood, Northwest Ellis and Southwest Ellis Counties. This is the prudent part of the play and we still have over 700 locations to drill on these areas. That assumes 500 foot spacing, which equates to about 40 acres per well. It also assumes 15% of the acreages developed on 250 foot spacing which may prove to be conservative. This represents 1.2 Tcf of net un-booked upside in the Barnett.

We also have 51,000 net acres in Hill and Southwest and Ellis counties which represents an additional 0.8 Tcf of upside. Combined this is about 2 Tcf which by itself is almost double the size of Range. The recent highlights of our Barnett drilling program are our last four wells in the Carter Industrial Park. They tested at a combined rate of $33 million per day gross or 25 net. That’s an average of $8 million per day per well, which is outstanding.

We also made significant progress reducing our well costs in Eastern Hood County. Our last four wells averaged 10 days from spud to rig release. The cost of chasing point was about $500 and the total completed well cost was about $1.6 million. These wells averaged 2 Bcfe per well, so they have excellent F&D costs well below $1 and great rates of return. Our first well in Northwestern Ellis County came on line at the rate of $2.6 million day and also we previously announced the $5 million per day well in Eastern Parker County.

Our second Southwest Ellis County well was just like the first one. It had good thickness in gas in place but produced at a sub par rate of $1.3 per day. Our Hill County drilling is similar, good thickness in gas in place but disappointing production rates for the initial wells. We still have some experimentation to do though and we’re making progress. Our last well produced at an initial rate of $2.4 million per day.

The other thing will seeing in Hill and Ellis Counties is that although the initial rates are lower, the decline rates are lower than the core of the Barnett. If we can replicate our latest well, we can generate good F&D and good rates of return. The key is our high quality team headed up by Mark Whitley. I’m optimistic that they’ll be able to solve the formula and unlock the gas.

Another very impactful low risk project for us is our Nora area located in Virginia in the Appalachian Basin. This is another project that has the potential to double Ranges reserves. There is significant upside in all the three horizons in Nora, coal bed methane, tight gas sands and the Huron Shale.

Range continues to drill successful CBM and tight gas sand wells in the field. F&D cost nets Range continued to be around a $1, which is amongst the lowest in the country. In addition the wells produced very little water and have low lift cost. Given this location in the Appalachian Basin, these wells received premium to NYMEX. This in combination with low F&D and low LOEs results in very good rates of return for these wells. Given a large number of wells to be drilled in current spacing and assuming successful down spacing, which it appears that it’s happening, there are approximately 6,000 wells left to drill.

The latest development in Nora is horizontal drilling in the Huron Shale. Our first well, which was completed in the fourth quarter last year, came online at an initial rate of $1.1 million per day. It cost about $1.2 million to drill and complete and although it's still early initial reserve are about 1 Bcf. Given our working interest and net revenue interest and remembering that Range owns the minerals, our net finding and development cost is about $1.07 per Mcf. This year, we expect to be drilling 10 horizontal delineation wells across the 250,000 Nora block.

We know that the Huron Shale has a good thickness and gas content across the 250,000 acres because there are 107 producing vertical Huron Shale wells on this acreage. The purpose of the 10 horizontal delineation wells is to verify that horizontal drilling is an effective way to economically develop these reserves. If the Huron wells are successful, they will de-risk about 1 Tcf of net gas reserves to Range by year end.

We recently just completed our first three horizontal shale well in our 2008 program, two of these wells are inline; one of the wells had an initial rates of $1.2 million per day. This well had a 3200ft lateral and was completed with eight stages. The other well had drilling difficulties which resulted in only 17 19ft of lateral. This well had an initial rate of 565 Mcf per day. The difference in rate is proportional for lateral length.

So far I’m encouraged with the Huron Shale potential in the Nora field. Net project will be starting at Nora’s horizontal development in the Brea sandstones which we believe has excellent potential on our acreage as well and the Brea is on of the existing type gas sands that we’ve been developing vertically for years in our excellent wells.

And other high impact opportunity for Range is on Marcellus shale plane in the northern part of the Appalachian basin. Last week we announced that we have now 1.4 million acres of Marcellus Shale acreage. We believe our high graded acreage now stands at 850,000 acres which equates at 15 to 22 Tcfe of net un-risked reserve potential. Of that 10 to 15 Tcfe are located in the Southwest of the play with the remainder in the northeast. To date we have drilled and completed 22 horizontal Marcellus Shale wells and have an additional three horizontal wells waiting on completion.

In yesterday’s release we announced our last seven horizontal completions which had an initial production rates that averaged 4.9 million per day. This compares to 4.1 million per day for the 10 wells prior to that. Range also recently announced these well should costs $3 million to $4 million in the development mode and we expect reserves to be 3 to 4 Bcfe per well. That generates finding and development cost of $0.90 to a $1.60 per Mcfe. We have also announced an agreement with MarkWest to develop the midstream infrastructure and we’ve also announced that to date we have secured firm capacity on the pipelines with $150 million per day and are currently negotiating for additional capacity.

In terms of water source and water disposal require to hydraulically fracture Marcellus wells, Range is making excellent progress in handling these requirements for our projects. It’s interesting to note that Pennsylvania second only to Alaska in terms of water resources. We continue to work within the states regulations to securities these water sources and have made excellent progress. We’ve also recently signed four agreements with existing regulatory approved water disposal facilities that should more than handle our water disposal requirements for the next several years.

Our current focus is to begin development of our core areas, continue to delineate our acreage and aggressively add to our Marcellus leasehold in selected areas. We currently have three rigs running and we’ll drill approximately 40 horizontal Marcellus Shale wells this year. 2008 will primarily be a year of delineation, acreage acquisition and building infrastructure. We expect significant volume growth will occur in 2009 and beyond.

In addition to pursuing the Marcellus Shale we’ve also initiated studies on the Utica Shale, Berquette, Genesse and Limestreet Shales. There is good potential for all of these horizons on our existing acreage in the Appalachian Basin. Range now owns 2.7 million growth, 2.3 million net acreage of leasehold in Appalachian. I’d like to switch gears and talk about the curtailments that we had in the second quarter and things we did to overcome them.

Range has a strong portfolio of projects that we draw on when we are confronted with challenges and the high quality team that consistently rises to the occasion. For the second quarter both the Midcontinent and Appalachian teams rose to the occasion. In the Midcontinent the team drove some very good wells in the Granite Wash and the Texas Panhandle and also in the Watonga, Chickasha area.

In particular the Granite Wash is developing into a very nice opportunity for Range. Currently it looks like we have an excess of 200 Granite Wash wells drilled in three different places. Two are on the Texas Panhandle and one is in Western Oklahoma. One is a horizontal Granite Wash play on the Southern part of our portion ranch area. The Granite Wash target zone here is about 50 feet thick and the wells are about 9300 feet true vertical depth.

The wells come online at about $2 million to $3 million per day. The other Texas Panhandle Granite Wash play southeast of there, where the Granite Wash is over 600 feet thick. This is a vertical development and the wells are about 12,000 feet deep and come online at rates of $2.5 million to more than $3 million per day.

In addition to achieving good drilling results, the Midcontinent team also cramped up the re-completion or work over effort. The best one of the bunch was the re-completion to our Douglas zone in a well and quotient ranch. This re-completion cost about $400,000 and resulted in a strong well that came online at the rate of $6.6 million per day and its still producing at about that rate.

The Midcontinent team also optimized the pumping at some of our oil wells in northern Oklahoma, by changing the steel rods for fiberglass rods. This increased the oil production of our well there. The best results from an individual well resulted in a gain of more than 100 barrels of oil per day. We’ve also optimized gas gathering there which increased production by more than a million per day.

The Appalachian team also stepped up and helped the company to achieve our results. In particular, our team in Virginia did a great job of drilling some exceptional high gas sand wells, the five gas wells, but particularly noticed a big line well at Nora they came online at a rate of $2 million per day and it’s still a very strong producer. Prior to that and noteworthy is the Ravenscliff well that drilled and came online at $2.4 million per day and it’s also a very strong producer.

In the northern part of the basin, the teams drilled two exceptional Beakmantown well, that combine and were inline at about $2 million per day. There are numerous small projects across all of the divisions that when combined overcame came the shut-ins and resulted in beating our production target and posting our 22nd consecutive quarter of production growth. That did come with a cost however. If we were not at being curtailed had not had the scrambled over comment, we would have lowered our LOE by about $0.06 per Mcf for the quarter.

Clearly we would choose not to be curtailed. At this point in time though, we know that today we have 22 million cubic feet per day shut-in. By year-end all of that should be back online. Although we‘ve experienced curtailments during the third quarter, we still should produce about 384 million to 386 million cubic feet equivalent per day and post our 23rd consecutive quarter growth.

The fourth quarter should be 395 million to 400 million cubic feet equivalent per day, which will gives us our 24th quarter of growth and 19% production growth for the year. 2009 should start out strong with the ramp up in the Marcellus Shale production. We’re targeting 30 million per day from the first quarter of 2009.

To summarize Range is in a great position. We have a proven reserve base of 2.2 Tcfe. On top of that we have identified upside of between 20.5 to 22 or 28.2 Tcfes, primarily a lower as coal bed methane, shale gas and tight gas sand place. We have a great track record of converting that to value for our shareholders. Range is where we want it to be, a low cost producer with a lot of low risk built-in growth. In summary we are in a terrific position to continue to build shareholder value on into the future. Back to you John.

John Pinkerton

Thanks Jeff, terrific update. Looking to the second half of ’08, we see continued strong operating and financial results. As Jeff mentioned for the third quarter, we’re looking for production to come in at approximately 384 million to 386 million a day, that’s 18% higher than the prior year. With higher production and strong process, we again anticipate third quarter revenues cash flow and earnings will be substantially higher than the prior period.

Looking to the third quarter we anticipate production to continue to increase. It should be in the range of $395 million to $400 million equivalence a day. Given what we know today we anticipate that the shale-in production, bio-production to come in by the end of the year after the pipeline expansions are completed. I think the key point here is that we still currently anticipate reaching our 19% production growth target for the year despite the shut in from the Barnett, so I think that’s really good news.

Due to the higher volumes and the prices for the year cash flow from operations anticipate to increase by more than 30% over 2007. So as you can see 2008 should be a tremendous year financially for Range and its shareholders.

While we focused on having our wells drilled and hitting our quarterly production targets we also continue to expand our drilling inventory and make exciting progress with our emerging plays. As you heard form Jeff our technical teams have drilled some additional high rig wills in several different plays with regards to the Marcellus Shale play, in particular the 4.9 million average test rig from our most recent seven wells is extremely encouraging.

Given our success and the additional opportunities we have identified we’ll move quickly and aggressively. Our expanded Marcellus team gives us the ability to be aggressive; however we’ll maintain our disciplined approach and financial regimen.

Importantly our gas gathering and processing infrastructure projects in the Marcellus are making solid process and we’re right on track. We’re right on tract to begin ramping up our Marcellus production in the first quarter of ’09. We’re also on track to significantly increase our Marcellus drilling activity in 2009 and beyond as we’ve tied up additional drilling rigs as well as the water infrastructure.

As Jeff mentioned we recently execute four additional agreements regarding the water source and disposal. These arrangements coupled with our existing arrangements will give us plenty of running room in terms of that part of our business. Of the pipeline and infrastructure we have, we’ve made arrangements that provide for a considerable take away capacity, so when you think about the way we look at it while our water and pipeline issue may limit some of the operators in the play, these issues shouldn’t limit us given the actions that we’ve already taken, so we feel really good about that.

For those of you that have been shareholders when we initiated the Marcellus play you’re trust and patients is very close to paying off as we are just around the corner from seeing material production volumes and cash flows from this exciting play. There is no doubt in my mind that the Marcellus Shale plays will be a key driver to the value of Range for many years to come.

In summary, looking our Range today we have the largest drilling inventory in our history with over 11,000 projects. Our inventory together with our emerging plays represents 21 to 28 Tcf of future growth potential. This equates to 9 to 13 times our existing proved reserves. We are excited about the growth potential of Range and we’re intently focused on delivering each and every quarter.

The second quarter in particular is a shining example of this commitment by all the employees at Range. Prior to opening up the call to questions, I would like to make one final comment. I want to show all of our shareholders that we’re maintaining our sharp focus on per share value. As I mentioned many times at Range we care about our stock price not our market capitalization.

Several acquisitions have recently been announced in which we participated in the bidding process. We lost out on those acquisitions because we were unwilling to undertake acquisitions that make us bigger but don’t result at any higher per share value. No matter how much we lack at property, we will not buy unless it clearly increases our per share value.

This disciplined approach is built on our confidence that we can continue to deliver double digit growth at low costs for many years to come with our existing portfolio of properties. While we continue to take acquisitions we will do so only when we believe, it benefits our existing shareholders by making those shares more valuable. With that operator let we open up the call to questions.

Question and answer session


(Operator Instructions) Our first question comes from the line of Joe Allman with J.P. Morgan.

Joseph Allman - J.P. Morgan

John or Jeff, those four agreements in the Marcellus Shale for water handling just to clarify so those would give you water access and will also take care of you for water disposal; could you talk about those and how long is that going to last for and what are the geographic areas covered there?

Jeffrey Ventura

Yes, the agreements are both for water procurement and for water disposal, it will take of us for the next few years and of course along with that in parallel we’ll continue to pursue, otherwise in additional ways optimize handling of water, but our teams has done a great job there. We are looking at not just drilling wells but we’re looking at the sources of water, the uses of water, gathering system, pipelines, firm transportation, procuring drilling rigs, pumping services and all the things that we need like John said to carry out our program for the next several years.

We’ve got multiple areas we’re looking at developing and those agreements will cover multiple areas. As I bet a lot of people know we have great acreage position, we’re drilled when you’re adding all of our wells, close to a 100 well, now veridical and horizontal and cross and Marcellus plus we have all the control points from all Appalachia wells that were drilled, the good Chesapeake wells that they announced as well as others, so we’ve got multiple areas.

We think from the perspective some of our drilling this time, we’ve drilled some really significant stepped out well along ways from each other. So we’re developing a lot of areas, but as you’re aware of and I think most of you are aware of a lot of our initial drilling and development is going to come in the Southwest parts.

Joseph Allman - J.P. Morgan

And can you talk about any other regulatory or environmental issues that you need to confront in developing this play?

Jeff Ventura

We’re constantly working with all of the agencies out there and we think we are going down all of the paths we need to go down. Yes, I think that at the end of the day, it’s not just a great opportunity for Range it’s great opportunity for the state of Pennsylvania.

Just like the Barnett Shale here and the Fort Worth Basin has created close to a 100,000 jobs. I think we have the potential to create more than that up in Pennsylvania. So, it’s going to be a great opportunity for job creation and great opportunity for bringing a lot of industry in there, wells for the land owners and the mineral owners, as well as it’s a good deal for the country. It’s natural gas, it’s clean burning, it’s a domestic fuel, so we’re talking to State and local people constantly and we think we’re making and building good relationships.

Unlike all projects, there maybe bumps along the way, but we think we’re along ways down the road and importantly like we’ve talked about we are going to come on in the significant way in the first quarter. We expect production to reach, 30 million per day in the first quarter we expect to ramp up to 8 rigs sometime in 2008 and continue to drive our volumes up in significant ways. We’re securing more additional firm capacity beyond a 130 million a day; we’re well in excess of the 150 million per day that we talked about. So we are excited about the project and just like in the Barnett here the guys have done a great job.

With just 6 rigs we grow production up in the Barnett to close to a 100 per day and if you add in the shut volumes which will occur, we’ll get all of those volumes back online by the end of the year. We’re going to be a well over a $120 million per day in that just running six rigs in a two year timeframe, so planning on going to eight rigs, initially in the Marcellus, but those are the things what we’ll find too in the August, September and this fall and towards the end of the year and early next year. We’ll continue to putout more updates in terms of the play.

Joseph Allman - J.P. Morgan

That $30 million in the first quarter of ’09, so that’s not an average rate that’s just a level that you will reach at some point during the quarter, is that right?

Jeff Ventura

Yes, but I’m confident of our guys will hit that and continue to drive it up.

Joseph Allman - J.P. Morgan

Okay, and then on the Barnett, are you expecting to grow the Barnett between now and the time you get those pipeline initiatives or it’s going to be relative flats and then if so what’s really going on the drive, what areas are going to drive the production growth?

Jeff Ventura

That’s really important and one of the comments I wanted to get across in this call. Quite frankly I think a lot of people there have though a few things where you guys have the Carter Industrial Park, it’s great, but it’s only 2000 acres and there’s not a lot of drilling and you have to drill in Ellis County, that’s really not true. We have a really significant position in the Barnett, and like I said we’ve got 42,000 acres and more than 700 wells on conservative spacing assumptions of 40 acres or better. They’re right in the guts of the play.

On our website, which David is going to update and it will be out I believe tomorrow or not later than Monday, we’re going to highlight some of those other areas. There’ll actually be specific slides up on our website showing what we’re doing in Eastern Parker or Eastern Hood, Southern County, Southeast County, some more Johnson County drilling, that have really nothing to do with the expansionary.

So, when you look at the curtailments the whole play isn’t curtailed. Really all the curtailments we’ve experienced today are just in the Carter Industrial Park. So, the answer is yes, Mark Whitley and his team are going to continue drive up production and working with the pipeline companies we’re going to get all that on by the end of the year.

There’s two big programs, that’s ETC’s Paris line that’s supposed to come on literally sometime within the next 30 days, take away capacity of 300 million per day and then the other one is Crawley line, which will be online by the end of the year. They could add depending on what pressure you’re pumping, 700 million to up to 1 Bcf per day and it has not going to come on all at once, it will come on in parts starting in September and October and through November.

So, we’ll be drilling in the Barnett and areas where we’re currently not curtailed, but when the curtailments comeback on we’re going to get that production. Just like I said in my notes it’s a negative thing that we were curtailed, but since it happened now you can view it as a positive. We’ve got 22 million of per day that’s literally just opening wells to get it back online, no additional costs, no additional effort other than the third party pipelines that are going to put in place.


Thank you. Our next question comes from the line of Rehan Rashid with Friedman, Billings, Ramsey. Please proceed with your question.

Rehan Rashid - Friedman, Billings, Ramsey &Co.,

On the Marcellus from a water standpoint I thought I read in Halliburton earnings transcript that they might be looking into something that would allow you to use Brine rather than portable water; does that kind of ring a bill, any thoughts there?

Jeff Ventura

Yes it’s a good point. There is a lot of technological things that are in the process that can really help out. What we’re doing is we’re planning for existing conditions as it exists and we’ll have enough capacity for current technology, but what we’re right on to referring to is the big issue with reusing frac water is friction reducers don’t work in the sailing water.

The service companies all are working on the technology to come up with friction reducers that will work in sailing water. If that’s true then we can really reuse a lot of the frac water, so there is real upside in terms of technology that’ll come down the line just like we’re not counting reserves and rates from refracting horizontal wells, I really believe that in time the industry will figure that out, that technology exists and we’ll get the benefit of that as well.

So you’re right Rehan, that’s a nice technology that we’re looking at in order to be more efficient with water use and there is literally three or four other things as well that we’re doing as well as the industry.

Rehan Rashid - Friedman, Billings, Ramsey &Co.,

Okay. On the Barnett take away capacity, 1 to 1.3 Bcf roughly around end of the year, how about beyond that? Is there more on the table to come from what I understood there might be a couple of more Bcfs that are being proposed; any thoughts on that front please.

Jeff Ventura

There’s other projects that are in the works and are being talked about to continue to expand and take away capacity out of the Barnett. The Barnett’s being a great field. I think it’s the biggest on shore gas field now in the U.S. and a very economy place to drill, very robust economics and production growth, so the pipeline companies are continuing to work with the producers in getting additional take away capacity out of the base.

Rehan Rashid - Friedman, Billings, Ramsey &Co.,

One last top down question; when you are trying to plan all across the board and everybody else is working on all different kind of shale plays as well. How are you thinking to your other infrastructure needs, tubular goods, frac capacity; how are you kind of -- I’m not generically speaking of planning for it but maybe some time lines in terms of how far ahead you need to plan for tubular goods, frac and anything else that comes to mind.

Jeff Ventura

Well, for instance all of our teams and areas, we take all of our properties and we forecast them out through the life of the properties. So we have plans that look at not just development of our existing proved reserves but the probable and possible and the merging plays beyond that and then we work with our pipeline guys and commercial guys like up in the appellation base and not only plans for lying the infrastructure to it, but make sure we have firm take away capacity for the volumes of gas that we expect to produce up there.

Same on the drilling side. We know for 2008 or end of this year obviously all the way through 2009 and we’re already looking at 2010 in terms of the number rigs and types of rigs. We talked about in our release two special built for purpose rigs that we were in for the Marcellus Shale play up there, so the guys do a good job forward planning.

The proof is in the track record, but that we didn’t get the 22 consecutive quarters or five years of meeting or beating our marks with out forward thinking in terms of what we’re trying to do, but we realize with some of the bigger projects like the Marcellus Shale and some of the growth we have in the Barnett and other areas that we need to do a lot of that kind of planning and we do, do that.

John Pinkerton

Yes, I think one thing Rehan, this is John. We’ve met with every single large take away capacity pipeline in the Appalachian Basin in terms because they all want to understand what in Marcellus plays all about, the potential and we obviously since we’re related we have more information and have a better perspective than anybody else and the most encouraging thing is that essentially all of these big pipeline companies and you tell these want to be in the Marcellus Shale play in terms of providing take away capacity and a number of companies, dominion and all the others, several others have announced new projects and what not and we’re right in the middle of all that. So, there is no better place on the plant earth to sell natural gas than the Marcellus Shale plays.

So, in terms the location I think 60% of the United States lives within 300 or 400 miles at the center of the play. So it’s a marvelous place to have gas and to be selling gas over a long period of time, and that there is no doubt in my mind, that just what I’ve seeing so far and the encouragement that I’ve seeing from the other pipeline companies, it’s just a matter of time and I don’t think its going to take that long. I mean, the infrastructure we’re putting in place that should be up and running in the first quarters is really going to allow us to ramp up dramatically and you can just from some of the take away capacities we’re tying up, we absolutely are pretty confident in terms of the commerciality of the play.

So, again I think you guys step back a little bit and just think about it. We’ve got 850,000 acres that we think we high graded. So it’s huge for us and so therefore we’re planning to add more than I think we’ve ever had in terms of looking at some of that stuff. I am very encouraged in terms of where we’ll be one, two or three years from now. I think its going to be for those shareholders that were kind of with us in the beginning they’re going to see this through. It’s really going to payoff, I think it’s just a little patience here and its going to -- what we’re seeing today is that all of a sudden the market will realize it and I think it’ll be reflected in our stock price.


Thank you. Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question.

Ronald Mills - Johnson Rice & Company

Jeff could you explain a little bit on the Barnett Shale and when you walk through 700 locations, are you breaking the 500 foot spacing and 250 foot spacing among individual project areas or how should we look at that inventory?

Jeff Ventura

Well, yes I mean these are specifically we have all of our acreage and we have a 3D seismic covering all of it and we have wells on all of it to, so it’s the low risk knowing part and our guys are going back through and literally hosted up the wells that they think or good quality, high quality economic well to drill in the acreage where you got all the technical work, the production date of the geology and the geophysics.

On the stuff David Amend is going to put up on the website we are going to actually include some of those maps. So, you’ll see some of our areas and it will show the number of locations we have in the areas, it will show quality of well, the recent results of our wells and some other people in and amongst those areas. In some cases it will talk about reserves and rates, well cost, so we are going to try to put that out on the website.

David told me it will be up tomorrow. I’m giving him an extra day, so say the weekend, so by Monday it will up there. When we are out and about it in our other conferences it will become part of our pitch book. So, we are really just revised our pitch book to include all that, to make it more transparent...

Ronald Mills - Johnson Rice & Company

Have you’ll drilled any wells on the 10 acre or 250 foot spacing, to gather that data?

Jeff Ventura

Again on the 250, foot spacing we assume 15% of our acreage would have that. So a small percentage and the acreage we are assuming are in the thick part of the play in Tarrant and Tallian and areas like, but we are in and amongst -- it’s why Devon is drilled like that, why EOG is drilled like that, so this year we’ll be drilling our first 250 foot well like in Carter Industrial Park. Other people in the industry have drilled in those areas and are proving that it works.

Ronald Mills - Johnson Rice & Company

Okay and then you mentioned that the Chesapeake wells, as I recall those were in Ellis County; did that do anything in terms of your standpoint in terms of validating some acreage that you thought may have been potentially more French as that moves further west from where some of your early activities were.

Jeff Ventura

Absolutely. I mean if you look at our wells at this point, the distance between our too farthest horizontal wells is a little over 40 miles, which is huge in our oil and gas terms and we’ve got quality wells in those areas.

When you factor in the Chesapeake wells which were in the West Virginia Panhandle, farther west of where we are, thinner and oilier if you want to say it that way, that’s quite the right words, less mature maybe is a better way to say. Yes having those wells out there is great news for us, and then also factoring in all the Appalas wells even though Appalas -- and I haven’t seen the latest presentation, but talking the Rich Webber and seeing their presentations in April they got over vertical wells that look really good.

We are not just looking at all wells in the play. When you factor in our 100 wells and Appalas is now probably 70 wells and Chesapeake’s new wells including the poor wells that were drilled by, I think they threw out some of the companies, so I won’t but some of the poor wells that we’re drilled in other parts of the play and outside of those areas I think we have a really strong geologic model that works and makes sense, that’s why I’m excited about the play and confident.

At some point hopefully next March, plus or minus when the acreage is tied up, we’ll have an analyst day and we’ll really walk through our geologic model and it’s really interesting in terms of why did we target what we target, how do we targeted, how do we drill in complete, why we do that and why do we pick certain areas, but yes jumping back to your question though, those Chesapeake wells are really good news. I’m glad for Chesapeake.

I know Steve Dixon and the guys out there -- Steve usually listens to our call, so hello Steve if you are dialing in now; I’m sure you’ll be on tomorrow and the great guys; I’m happy for them, but I am glad for us because it’s good news and for those that haven’t heard they announced two wells at 9 million per day. So, 4.5 million per day wells in the thinner west matured areas is good news.

Ronald Mills - Johnson Rice & Company

Right, and then Roger, because you’ve been left out a little bit here, can you walkthrough the liquidity situation you talked about. I think you said you had 800 million available and then the next breadth 1.3 billion of liquidity; can you walkthrough that balance sheet again?

Roger Manny

Sure, thank you Ron, let me clarify that. We have what’s known as an accordion facility with the bank group and what it enables us to do is we have a legally binding commitment of $1 billion under the commitment. They have under written our asset base and are willing to land up to a $1.5 billion in the borrowing base if we need it, but we don’t want to pay for that extra 500 million and they don’t want to have to book it as commitment and improve capital on it.

So, really if you want to go from $1 billion to a $1.5 billion we tender a notice with the agent and they survey the banks and they have 20 days to basically reallocate the exposure amongst themselves and comeback to us with it. It’s a not a committed over line, but it’s the closest thing you can get to it without paying for it. So, my numbers there, we have 800 million left on the committed liability of $1 billion and if you have 800 to the extra 500, you get the $1.3 billion I mentioned.

Ronald Mills - Johnson Rice & Company

Okay, great and then just on your cost guidance, I missed what your expectations were from of our G&A level and the numbers you give me, should we assume that excludes the non-cash compensation and also on the production cost, it sounded like you expected your LOEs to stay around the $1 to $1.05 Range all in including work overs and we do the curtailing.

Roger Manny

I think we’ll do a little better in that Ron. Work overs are just notorious and difficult to predict and the $0.10 we had this quarter was among the highest quarters we’ve had in my memory. I think we’ll be in the high $0.90 range when we take those non-recurring ones. As for G&A, the cash number, cash G&A for the last quarter was $0.49. I think that’s going to hold where it is until we get some more production on; high $0.40 range is a good number.

Ronald Mills - Johnson Rice & Company

Okay and then production taxes really know -- any shift in your production breakdown geographically? Should we anticipate any changes in that?

Roger Manny

No, we continue to file and get abatements in the Barnett for production tax plus production tax as you know Ron is based on well price not hedge price so that makes a difference, but now just a percent of production however we modeled it should continue to work fine.


Thank you. Our next question comes from the line of Marshall Carver with Capital Ones. Please proceed with your question.

Marshall Carver - Capital One Southcoast

Yes a couple of questions. First of all, the number of wells per rig, per year in the Marcellus with the ramp up, I’m just trying to get a feel for how many horizontals you’ll probably be drilling in 2009?

Jeff Ventura

We’ve talked about going to eight rigs and wells it’s really early. Typically, what we do just for the people who aren’t familiar with this, usually in August, I usually ask the divisions on a wish list given the finding cost and rate of return criteria that they need to meet and LOE cost, what would they like to do for next year and we go through it and enter into a process.

So, it’s really early to talk about that, but then to try to answer your question in a rough range and I’m going to put a pretty wide band around it, you’re probably looked at 80 to 100 wells or something like that and again eight rigs, we’re saying, we’re going to ramp up through the year and in next year to buy the eight rigs. It’s not eight rigs on day one or eight rigs at a certain time, so you’ve got to sort of filter them in across the year, but it’s preliminary it’s early, we got to run it by the board in December and we’ll put it out next year.

Marshall Carver - Capital One Southcoast

Okay, that’s helpful. So and 2009 guidance for the whole company would probably coming out sometime this fall?

Jeff Ventura

That’s fair Marshall.


Thank you. Our next question comes from the line of Jack Aydin with Keybanc Capital Markets. Proceed with your question.

Jack Aydin - Keybanc Capital Markets

Roger, the tax rate for the second quarter, the corporate tax rate was about 40%. First of all why was it higher than it used to be and going forward what kind of tax rate you’re thinking off?

Roger Manny

Yes, thank you Jack. Tax rate should be at the 38% going forward. We had a blip in the first quarter and year-to-date numbers from some deferred tax accounts that needed to be reallocated but it will be 38% going forward.

Jack Aydin - Keybanc Capital Markets

As it relates to the amortization of leases that will expire, Jeff could you give us a hint where those leases are and at what timetable, how long those leases are and what percentage of your acreage, it lends itself to those type of expiration?

Jeffrey Ventura

Rob dug into that a lot and Roger has that so let me turn that question over to Roger and I may comment at the end?

Roger Manny

Yes, good question Jack, because this is something that’s a little new and let me answer it by first kind of putting it in perspective. Our total unproved property balance into the quarter is $422 million, that’s 8.6% of our total assets. So when you look at in perspective, our unproved is way smaller than our peer group especially those with similar shale emerging play upside.

My point is we watch unproved properties very, very closely. We treat it as all of our assets, we manage it very efficiently and it’s our interpretation of the accounting rules and it’s shared by our auditors that even though you account for your unproved on a pool basis, that anytime you have a lease that expires that you have a carrying value associated with it, you must take an impairment of that lease that expired and what you’re seeing in our numbers.

I’m not sure quite frankly why you’re not seeing them in our peer group numbers, is that when you enter a play such as the Barnett, when we repurchased strout, we booked a fair amount of acreage value on the transaction two years ago and of course as in any acreage purchase it’s not all going to be good all the time, but when you make your purchase price allocation and this is going on across the industry Jack as you know. A lot of purchase price is being allocated to unproved acreage. When that acreage expires you’ve got a pretty big number that’s rolled in through the DD&A.

To directly answer your question some of the strout acreage that’s coming up on the two year mark that was already a year or so old when we bought the company or in areas that we don’t choose to pursue any longer and we’re allowing to expire, but it went on the books at 10,000 an acre. So it doesn’t take much acreage to create the write-down.

Conversely in areas where you’ve got acreage down the street that’s a 200 acre or less and that’s a very small adjustment. So even thought you look at it on a pool basis, you can't look at the pool and say well my acreage value went up, so I’m going to mark it up to offset the expirations, you can’t do that. So, to answer your questions its mainly acreage that was acquired in various transactions and right now most of it seems to be in the Barnett and looking forward the guidance I gave you, the 5 million to 8 million per quarter should be sufficient to cover those expirations.

Jack Aydin - Keybanc Capital Markets

You mean you’re telling me with all the interest in Barnett and everything you could not get somebody to drill wells on this acreage or you don’t care to drill wells on this as a – with your own volume, somebody else’s volume?

Jeff Ventura

Jack when you look at our old maps it shows the Barnett acreage. The good news is 95% of what was in the expanding core and of course we are going to putout very specific maps so you can see the areas we are talking about now, but when we say 95% of it was in the expanding core that means 5% of its not.

So, the stuffs that’s all down in Boskie County, there’s a tiny, tiny bit in Hamilton County, a little bit way out West. Our strategy is simple; we want to grow production, double digit or better this year, 19% or we want it all in cost structure being a tough curtail or better, we are not going to drill core wells in some of the more fringe areas or even renew those leases, we would rather focus our areas in the highest rates of return, best F&D, more certain areas than we would extend or drill some of the more marginal or fringe stuff, that’s really what it is.

Jack Aydin - Keybanc Capital Markets

Okay thank you. John did you give the production number or guidance for the third quarter?

John Pinkerton

Yes, we think -- let me just go back over that Jack. We actually gave for the third and the fourth quarter. Third quarter were 384 million to 386 million and fourth quarter 395 million to 400 million.


Thank you. Our next question comes from line of Tom Gardner with Simmons & Company. Please proceed with your question.

Thomas Gardner - Simmons & Company

I wanted to get some additional clarity on your Marcellus reserve expectations specifically what percentage or what fraction of your high graded acreage would you apply this to 3 to 4 Bcf range?

Jeff Ventura

All of it.

Thomas Gardner - Simmons & Company

Do you see any reason to differentiate between your Northeast area or your Southwest area?

Jeff Ventura

Yes -- oh in terms of recovery per well?

Thomas Gardner - Simmons & Company


Jeff Ventura

No. Those are our other distinguishing things and obviously we have chosen to start a big development in the Southwest for a number of reason, but we think we’ve drilled some very good wells in the Northeast as well and again where we will in time become more and more transparent as the different models and all the inveteracy’s, but because of competitiveness and leasing we’re going to going to withhold some of that, but in terms of the reserves per well we’ll go with the 3 to 4 Bcfe.

In terms of costs per well depending in the Southwest, its shallower typically and you’re out of the spine of the mountain. So, wells will tend to be cheaper down there. Those are going to be, I think towards the low end of the range there. If you’re up into the mountains and areas to the Northeast particularly, some of those areas, the Marcellus can be 8000 or 8500 feet deep. So, those would be -- I would distinguish the cost, but I would not distinguish the reserves. That made sense?

Thomas Gardner - Simmons & Company

Yeah, it really does, I appreciate that.

John Pinkerton

The other thing if I could -- Tom if I can just butt in and make a point. The one thing in the Shale plays is really, really important in terms the cost side of the business is really important and the interesting thing -- I’ll give you an example in the Barnett and try to relate it back to the Marcellus.

Down in Hood County, we own 67,000 acres in the Barnett and we drilled some really good wells and Jeff mentioned in this call now that’s we’ve really gotten the cost down and those wells when we first started drilling them we used to beak in 5900 horse power or topped rigs and the costs were $4 million per well.

David and our drilling team really learned a lot. We’ve drilled 15 to 20 wells by now, we picked up more acreage and the three wells we drilled, we drilled three wells in 30 days that costs $1.6 million of drill. So, we drilled three wells for the cost of what one well costed in the very beginning and that same thing overtime is going to happen in the Marcellus and the onetime that, one really competitive advantage that we’ve got because we own so much acreage in the beginning and we bought so much acreage for $100 and $200 an acre before the play went well.

We’ve got some huge blocks of acres and now I’m convinced overtime the same thing is going to happen on our big blocks in the Marcellus as what we’re doing in the Barnett and where we can go in and start drilling five or six wells from a pad side and get the purpose rigs. We’ve got a really first class drilling team up in the Marcellus, head up by John who’s got 30 plus years of experience maybe 40. So, I’m convinced overtime that $3 million that Jeff used, we’ll beat that overtime.

Jeff Ventura

To make it even more direct, John talked about those Hood County wells, they’re 6500 feet deep that’s what Marcellus is on the Southwest and a lot of the step we’re drilling they’re 3000, 3500 foot laterals similar to down in the Marcellus and number of stages. There’s a lot of similarities granted the surface is rougher and granted you don’t have the infrastructure in the Appalachian basin, but I agree with John’s assessment that in time well I think we’ll actually beat those numbers.

John Pinkerton

I’ll now argue that the infrastructure in Appalachian is actually -- the large pipeline infrastructure, the take away lines are actually better in Appalachian, but you don’t have other gathering systems. The gathering systems are relatively cheap, so the good news is I think in the Marcellus once these gathering systems -- and we’ve got a number of them working and just not one, but as we develop the systems there is a lot more take away capacity and the good thing about the Marcellus, it’s on the front end of all the Shale play.

So, Marcellus gas is going to demand a premium over Hainslow gas or Barnett gas or any Woodford gas. If any of this other gas, the Marcellus gas is going to get the highest price because it’s closest to the end-user and it’s got -- I think within a rough analysis, I think six of the eight largest pipeline systems in the U.S. run through our Marcellus acreage block. So, it’s just a matter in the gathering systems build. Now is that easy to do, no because it’s got shales, but we’ve been operating up there for years.

We’ve got ends of miles of gathering systems, we’ve got this deal with MarkWest, we’re taking about deals with other midstream. So, it’s just a matter of time. I convinced it’s going to work and the good news is in a quarter or two, we’ll quit talking about it and all we’ll about is we’re 30 million a day, we’re blank, blank and blank and where we project it and everybody will forget about all this over the infrastructure.

I will continue to focus and tell you guys that the infrastructure it’s just a matter of time, it’s coming; there is a lot of people chasing the infrastructure out there with a lot of money. It’s going to in time, it will get better.

Jeff Ventura

Yes, and I agree with that. Marcellus doesn’t have the same infrastructure, I was talking about just like the Barnett Shale if you go back in your early years talking about Mark Whitley and the original natural gas, when a lot of other operation really ramped up and we had a lot of more drilling companies, a lot of more pumping companies and all those types of things, but all those companies, we already talked to, they all want to be there. A lot of our moment equipment up there, so I agree with John that will happen.

Thomas Gardner - Simmons & Company

Well, then the question is, how fast can you go. I mean you’re planning eight rigs for 2009, can you walk us through the possible upsides there, the activity in 2009 and beyond?

Jeff Ventura

Yes, I think I would just draw -- you can draw the analogies and an easy analogies maybe is back to the builder or some of the other plays. I think we’ll be able to ramp up significantly. In 2000 we talked about 2009 being at 8 rigs plus or minus, we’re working on that. Now, we’ll have a significant ramp up in 2010 and ‘11 and beyond and as you know as it’s conceivable we could get to 20, 30 or 40 rigs. At some point in the future with continued development and continued good acreage, I think the answer is yes but obviously its early say that and we need to continue to drill wells. We’ll be planning, we’re looking at optimizing, we’re in the process of choosing.

If you go back in 2004 when we started it was an idea; could the Marcellus Shale be significant shale play and we were the industry leader in that, we came up with the idea, we pioneered it, we tried it. Now we’re moving from “yeah it does work; we’ve drilled a number of excellent wells.” I mean talking about the last seven wells here at 4.9 million per day those will be excellent wells in Tarrant County, those will be good wells in Johnson County and that will be phenomenal wells.

Now we are going from does the idea work to can we return it into a development project, which is what we are currently doing and then it comes back to ramping up and optimizing NPV, but we all understand we want there to be a good storage in the shareholder money, we are all heavily invested in the company and clearly we want to maximize that value for our shareholders and our selves.

Thomas Gardner - Simmons & Company

One last question and then I’ll hop off here. On the Huron Shale just an idea of what your reserve expectations and well cost are going forward and what is the greatest risk for this to become a successful resource play?

Jeff Ventura

Well, I think the easiest thing to look at there is all the work that equitable did right across the border in Kentucky plus we now have three wells on our own property. It looks like based on the equitable stuff they released I think they’re talking about reserves, of 0.8 to 1.5 base per well for from a possible 1 million to 1.6 million per well or something like that.

Based on our early work in Nora those numbers seem to hold out. I’m absolutely confident with the shale, because you got over a 100 control points with existing vertical wells and that’s why we are convinced to know that its full of gas and I know that now that horizontal drilling works at least in three spots. So we’ll be basically, equally distributing those wells across the bulk of the acreage and by the end of the year if it works and that to us will be risk about a Bcf and half and that’s basically using roughly a 100 acreage spacing and a Bcf per well, which is inline with the equitable thing that we were seeing really on.

The other thing I talked about is and I just mentioned it; that is the potential for the horizontal Bureau there. Bureau is really one of the original formations that was developed from that 1950s and beyond in the vertical Bureau wells were good, but again equitable in the area, in the vicinity has tried horizontal Bureau well and last I heard and they obviously would have more up to date information; they had two wells and per well each of those wells averaged over 2 million per day per well for the first 30 days.

We have a big Bureau fair way on our Nora block that’s an excellent candidate for horizontal drilling and there is a chance we may take a couple of those 10 wells and just drill maybe perhaps eight wells and convert a couple of those to horizontal Bureau. That’s a tremendous target too. They could in addition add several 100 Bcf net to range as well as equitable.


Thank you. Our next question comes from the line of Brad Pattarozzi with Tudor Pickering. Please proceed with your question.

David Heikkinen - Tudor Pickering

Actually you’ve got David Heikkinen and thanks for the long call. I think I’ll get to the question. John and Jeff you’ve talked about efficiency in the Barnett and Steven focused on rig count. I think something I just wonder about is as you thinking about Marcellus, thinking about efficiency and base the drill with your current rigs, kind of the purpose of the rigs, any of the characteristics of that and thinking about more of a wells count on an efficiencies basis as you improve; what has your ideal well been. If you did everything right on the 25 horizontal wells that you’ve drilled can you give us any of that information?

Jeffrey Ventura

Yes today if we did everything right we took the trouble of being literally like 3.3 million per well for our wells in Southeast Pennsylvania horizontal, so that’s assuming no additional productivity gains, no built for purpose rigs, no pad drilling, no optimization of bids from HUD system or anything like that. That’s why I’ve said it for a while now and I feel confident we’ll get in that $3 million per well drilling complete range and actually like John said I believe we’ll got an A plus team out there. I believe in time they’ll be it, whether some wells are 50 or a 100 or whatever well it is, but if we’ve got several thousand wells to drill I grantee you those guys will do good a job driving that down because we know there’s other things we can do to get better than that. That’s just eliminating the trouble and taking the time out of our existing wells, guess is to that 3.3 million today.

David Heikkinen - Tudor Pickering

Okay, that’s helpful, and then just on the Bureau you’ve talked about a fair way, you also then talked about testing the Huron, going up in the Pennsylvania and Brine Street and the other -- how much capital do you invest in testing kind of the new ventures in the back half of the year?

Jeffrey Ventura

The Bureau is pretty interesting and pretty easy because we have several 100 vertical wells that are already built through it, literally about 600 of them. So we know in the Nora block exactly where the burrier is and what the thicknesses are and rock properties and all that kind of stuff, and it’s a great vertical target. I just believe it will be even a better horizontal target, so we’ll probably take two of the ten Huron wells that we have scheduled down there, horizontal Huron wells and convert them burrier wells, so it won’t be any incremental capital, we’ll just reallocate some capital.

In terms of the Utica, we’ve actually been studying the Utica for a long time regarding to the Marcellus in 2004, and several good other flinch things have popped out of it. One we’ve recognized the Utica potential, so we’ve been looking about that and talking about it and now it’s just up in our offices about three weeks ago and so a pretty complete study on the Utica. So I would imagine sometime next year we’ll probably drill our first Utica well.

The other thing to remember as we’ve got such a big footprint up there 2.6 million gross acres, we already have the acreage. So there is no incremental acreage cost, it’s just going out and trying it, so next year when we haven’t put our budget together; like I said we typically do that in the fall, but we’ll probably have one or two Utica wells in therefore next year.

The other thing, the other shale’s that (Inaudible) our all Devonian eight shale’s that are above the Marcellus. So as we’ve drilled our roughly hundred vertical and horizontal Marcellus shale well, we’ve drilled right through those three intervals. So, when we run our ECS logs, we already have ECS logs across those intervals. We’ve already gotten the core data and across some of those interval and we think there is some really good opportunity out there, some of our existing acreage.

We haven’t put out or quantified it yet or released any of that information, but next year, you can be assured we’ll be testing some of that as well and probably between now and end of the year, we’ll quantify the upside of all those various horizons and as the appropriate whether we do it at the end of this year or really next year, when we update our pyramid and emerging place we’ll have those other horizons in there.

David Heikkinen - Tudor Pickering

And then just a final question, acreage in the Ardmore Basin now, did you add acreage there or what's you total?

Jeffrey Ventura

We have about 16,000 net acres in the Ardmore Basin. Its over 100,000 acres gross, so we actually we have a pretty good big footprint. In some areas we actually operate and control, the other areas that we don’t are either operated by XTO or Chesapeake and both of those companies are drilling on their acreage and we’re drilling where we operate.

Its early on, there’s something encouraging things coming out that and the big thing to remember of the Ardmore Basin, Woodford versus Oklahoma this is the wells are significantly cheaper. It’s easier drilling for a number of reasons. So, the well cost are about half and we’ve gotten some interest and its early, but we have some interesting results so far, probably need another quarter or two of testing before we put a lot of information out, but we’ll know lot more by the end of the year, but I’m something encouraging and that could be 400 days or so in that range, so far so good.


Thank you. Our next question comes from the line Leo Mariani with RBC. Please proceed with your question.

Leo Mariani - RBC Capital Markets

Just a follow-up on the Marcellus here. I guess at the point you guys have 22 wells that you’ve tested horizontally; are any of those on production at this point of time or are they waiting for the higher pressure gathering to come into the first quarter of ’09.

Jeffrey Ventura

Some of those are in production and some of them have been in production for basically, approximately a year. So, we have a year’s work of history. That’s the other thing, when you talk about shales and other shale plays in generally. The good news again we’ve got 100 total wells, 22 horizontal and all those veridical wells that have been on since the end of 2004 and our oldest horizontal for about a year.

So we are gathering reasonable production data. You’re right though we have a number of wells we’ve drilled, that we have drilled and tested in some cases we are testing them up to 30 days. So we’ve got good long-term test on them not for a day or two, but for 30 days and when we get our facilities and equipment in place those will come online and we are telling you that’s the first quarter next year.

So not only that we have $22.5 million of Barnett production that will come online by the end of the year, we’ve got a significant amount of Marcellus production that we feel will come online and that’s why we are coming out with -- we’ll be at 30 million a day by the first quarter of next year.

Leo Mariani - RBC Capital Markets

So those couple of horizontal wells that are online in Marcellus, are those been curtailed at this point or were there some areas we had the gathering that could handle that kind of volume.

Jeffrey Ventura

No, we have some gathering and it’s not just a couple there is several of them. So, we have good long-term tests on a number of wells that are un-curtailed, so we have a good feel for how they actually produced.

Leo Mariani - RBC Capital Markets

Okay, and in terms of just kind of taking a look at 2009 you talked about, just 30 million a day in the first quarter and I mean is it reasonable to assume you guys talked about 130 million a day of firm take away that you’re going to able to step that up sequentially each quarters as we go forward, or are you guys are working on gathering projects to get out there and hook up more well each quarter successfully there?

Jeff Ventura

Yes, Let me clarify I said a 130 by mistake, it’s a 150 million a day that’s what’s in the release and that’s what we currently have secured, but we’re well in the process of doing more than that, but yeah we’ll continue to look that ramping up and optimizing in that positive shale.


Thank you. We’re nearing the end of today’s conference. We will go to Dan McSpirit with BMO Capital Markets for our final question. Please proceed.

Dan McSpirit - BMO Capital Markets

Certainly a lot more gas will be coming out of the Appalachian Basin in years 2009 and beyond. Could you comment on and what you think happens to the premium placed on that gas today, and I guess I asked that in the phase of maybe, sluggish to down or flat demand growth in the Northeast markets?

John Pinkerton

Well a couples of things. I think production will -- I think it’ll be primarily, that’s quite frankly will be up, but I don’t think it’s going to be, it’s going to flow through the market. I think as we’ve said it will ramp up overtime and we are the leader in the play and so I think everybody else will be a bit behind us, in total way, but I think gas will come on overtime and I think there is a number, that when you look at the landscape in terms of the Northeast, there is a number. It’s not an easy equation, but I think, there is a lot of things that may have actually given me very much a boom in terms of natural gas one, it’s trading roughly 50% of what the crude oil was trading before, so I think there will be upward pressure on natural gas in terms of just being a commodity versus.

For oil there is a lot of a ledger generations that’s got to be built in the Northeast very quickly over the next five to 10 years. I think natural gas, that won’t be nuclear. I think a lot of coal is being challenged due to the carbon footprint; even clean coal which I think is a miss number can’t compete with natural gas. I think the whole processes are up substantially.

So I think natural gas is going to be clearly the victory in Northeast. I think that’ll be in the other parts of the U.S. too. So, I’m not too concerned quite frankly and the good news is that we heard our Marcellus play is going to be about 50 or better in terms of finding cost, so I don’t worry about gas whether it’s $7, $8, $10 or $12, I think we’ll be highly successful, I think we’ll be very economic.

When you step back, when we look at natural gas, it is the only thing that I see, and I’m trying to be objective here but obviously it’s all because it’s natural gas. When I look at all the different sources of the MGI because it’s going to drive all this, to me in the short-term and I mean short-term zero to 10 years, natural gas is the only one that in a material way that can cover that, unless we want to continue importing coal and oil, which I think, if we don’t do it in time, it will 200 barrels or if you want to continue to pollute the environment with some of the other dirty refines.

So, I think at the end of the day, its all going to comeback to natural gas and the good news is while these big electric generation facilities are going to need firm long-term commitments and we’ve already been talking to a number of them that’s come to us wanting to firm that up. So, I’m actually seeing it real time in terms of some of the enquiries from of some of the big power generators up in the Northeast. So, I think we will it be adapted if a hurricane doesn’t come or the weather is a little different and all that kind of stuff and I think those are short-term events, but when I look over the next one, two, three, four, five year for natural gas, I’m very bullish and I think where our gas is and where the Marcellus play even makes me more bullish in term of that.

Jeff Ventura

Well, I like to just add one thing. John mentioned the economics and referred to the economics in the Marcellus. The stuff I talked about earlier, David Heikkinen’s going to have a graph out on our website either tomorrow or Monday and of course we use different analyst stuff, but Shannon Nome with Deutsche Bank just completed a study of all the Shale plays across the U.S. including the Marcellus and the Hindville and Woodford and Barnett, core and non-core and that will be up on our website and I think it’s a good piece of work and I would encourage you to look at that as well.


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

John Pinkerton

Well, I want to thank everybody for staying on. I know we’ve run over, but I think there were a number of questions that we needed to answer that you all wanted us to answer. So, hopefully we’re able to answer a lot of those questions. I think as I talked to our shareholders, the things they tend to want to know are these things that we kind of -- the hard things you get your arms around which is some of the water issues in the Marcellus and some of the permanent things and I just want to make sure that we are on top of that, we know what we’re doing and we’ve got the right people doing the right things.

We wouldn’t commit eight rigs, we wouldn’t be committing the 150 million of that capacity, it’s probably more than double by year end if we weren’t confident that these things were going to resolve themselves overtime. We obviously know a lot that we’re not disclosing for competitive reasons, but we’re very confident in terms of the information we’re given you, in terms of the ramp up of the Marcellus, the project, the progress we’re making in terms of our infrastructure.

I think those of you all who have been in the Range stock for a time in ’04 and ’05 I think if there is any I can give you advice on is that we are just around the corner here. I think everybody is going to be pleasantly surprised with some of the stuff, especially as Jeff said when we come out with some of the more of the technical data. We rode this point for a while. I suggest you stay on our backs and we’ll get you to the finish line I promise you that.

With that again we appreciate you staying on, if there is any question you didn’t get to, feel free to call. Roger, I, Jeff, David or the others at Range will be happy to answer. Thank you very much.

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