山脈資源 (RRC) 2004 Q2 法說會逐字稿

Welcome to the Range Resources 2004 second-quarter earnings 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 statement. 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.

Good afternoon and welcome. On the call today speaking will be John Pinkerton, President and Chief Executive Officer, Jeff Ventura, Executive Vice President and Chief Operating Officer, and Roger Manny, Senior Vice President and Chief Financial Officer.

Before turning the call over to John, I would like to cover a couple of administrative items. First we have filed our second-quarter 10-Q with the SEC. It is now available on our home page of our website, or you can access it through the SEC's EDGAR system. In addition, we have posted on our website some supplemental financial tables which will guide you in the calculation of certain non-GAAP measures of cash flow, EBITDAX, cash margins and diluted shares as will be discussed on the call today. There are also tables that will detail information as to our current hedge position on the Web site.

Range will be presenting at the EnerCom Oil and Gas Conference in Denver next week on Tuesday, August 3. We invite you to attend the presentation in person or via the webcast. Access to the webcast can be made through our website or through www.enercominc.com. Now let me turn the call over to John.

Before we view the first quarter results I will just summarize at least what I think are some of the key aspects of the quarter. Overall we're very pleased with the second quarter results. Production rose 14.8 percent on a year-over-year basis and 2.4 percent on a sequential basis.

Our capital program has gotten off to a very good start, and we are pleased with the drilling results so far in the first half of the year. We are achieving very attractive rates of return on the capital invested. And on average the initial results of the 178 wells drilled so far in the first half have met or exceeded our original expectations.

Turning to the costs out of our business noticeable progress continued to be made in the quarter regarding reduction in unit costs, operating cost, interest expense and DD&A expense were all reduced on an unit production basis. In fact, Roger will give you some more details of that in his review.

On the acquisition front, the Great Lakes acquisition was completed late in the quarter. As a result, Range is now a far larger financially stronger Company. The acquisition is immediately accretive on a per-share basis which will be driven home by our third quarter results.

Importantly, the Great Lakes acquisition really completes a strategic initiative we began several years ago. And that was to simplify the balance sheet and also the organization.

Lastly, one of the keys to long-term consistent growth and profitability is a large multiyear inventory of drilling projects balanced between lower, medium and higher risk. Through the combination of the acquisitions and the projects organically generated by our technical teams, we have continued to build the inventory to over 3,700 drilling locations. The bottom line is we're significantly ahead of our goals for the year, and we still have the remaining half of the year to make further progress.

With that I will turn the call over to Roger to review our financial results.

Much of the financial news in the second quarter relates to the Great Lakes acquisition and the resulting balance sheet changes and improvements. So I thought it would be good idea to start with the balance sheet this time.

Reflecting on the transaction, we did active (ph) the Great Lakes acquisition with the issuance of 12.2 million shares of common stock, generating net proceeds of $143.4 million. The equity offering was supplemented with 100 million added=on issuance of 7 3/8 senior subordinated notes, with net proceeds from the notes of 98.1 million. An expanded 600 million senior bank credit facility was used to finance the remaining portion of the Great Lakes transaction. This credit facility currently carries a $500 million borrowing base. The financings were very successful with the equity, bonds and bank facility all significantly oversubscribed.

Range's shelf registration was fully utilized by the issuance of the new equity, however, so we are in the process of preparing to file a new shelf registration statement after we register and exchange the 144A notes.

The acquisition financing enabled the Company to complete a significant acquisition of long-lived assets with appropriately matched capital without increasing our leverage. The acquisition related financings extend Range's debt maturities with the bank facility maturing in 2008 now, and the senior subordinated notes that represent 40 percent of our total debt maturing in 2013.

The debt maturity profile is now more consistent with the Company's asset profile. The debt to cap ratio was 57 percent at the end of the first quarter this year, and after the transaction it is at 56 percent June 30.

Through excess cash flow and asset sales the rest of this year we look to get the debt back down to 50 percent in 6 months or so -- debt to cap ratio down to 50 percent. Significantly Range now enjoys approximately 180 million of available liquidity under the expanded bank credit facility. Contrasting that, the available capacity in late June just prior to the Great Lakes acquisition was a little less than $50 million.

Before relieve the balance sheet I think it is probably a good idea to reflect briefly on some of the recent changes that have occurred. And the second quarter really serves as a significant milepost in our production to simplify the Company and its balance sheet.

During the past three years we have retired or replaced the IPF bank credit facility, the Great Lakes bank facility, the 8 3/4 seniors subordinated notes, the difficult to understand trust preferred securities. And next Monday, August 2, we will redeem the remainder of our 6 percent convertible subordinated debentures.

The greatly simplified Range balance sheet will include only 2 debt securities, the senior bank credit facility and the 7 3/8 percent senior subordinated notes. Owning 100 percent of Great Lakes further simplifies not only our Company but our financial statements. So we are going to be able to wholly manage and wholly consolidate the Great Lakes entity going forward.

While the Great Lakes acquisition prompted significant changes in the balance sheet, because we only just closed the transaction on June 23rd, the second quarter operating results include only 1 week of 100 percent acquired Great Lakes interest.

Now turning to the income statement. The second quarter of 2004 generated a 22 percent increase in oil and gas revenue driven by 15 percent higher production volumes and 7 percent higher oil and gas prices than in the second quarter of 2003. Oil and gas revenues of 67.6 million set a record high for the second consecutive quarter.

Transportation and gathering revenue was about 600,000 lower for the second quarter of 2004 from the prior year. That was due primarily to the impact of pipeline and labor costs from the December 2003 Conger Field acquisition. These costs represent the services of Conger Pipeline employees who joined Range with the acquisition to provide compressor and pipeline operating and maintenance activities. So while the net pipeline revenues are down due to higher cost, the overall field profitability is enhanced by their services.

The other revenue line for the second quarter does include an effectiveness hedging gain of 971,000. And that is as compared to a 2.1 million loss in the second quarter of '03.

The second quarter of 2004 expense performance was encouraging as well. Oil and gas revenues were up 22 percent, while direct operating expense rose only 9 percent. And then not as dramatic as in the first quarter, we did continue to see unit cost reductions in several areas. Specifically, the direct operating expense for the quarter was 63 cents a Mcfe compared to 66 cents per Mcfe for the second quarter of last year.

Production and ad valorem taxes were 29 cents per Mcfe for the first quarter compared to 22 cents a Mcfe last year. And that is due of course to the higher oil and gas prices we're experiencing.

G&A expense was 31 cents a Mcfe in the second quarter of '04, which was level with the second quarter of '03, the slightly higher than that 27 cents that we reported in the first quarter of this year. So the increase in unit cost between first and second quarter in the G&A category, you can attribute that to the personnel and consulting expenses that we incurred due, first, to higher levels of drilling activity and, second, 2 additional professional fees associated with Sarbanes-Oxley Act implementation. As a reminder, Range does not capitalize any of its G&A expense.

Looking at interest expense and preferred dividends, they totaled 31 cents per Mcfe in the second quarter of 2004. And that's down on a unit cost basis 14 percent from last year. Again as a reminder, Range doesn't capitalize any interest expense.

Lastly, the DD&A rate per Mcfe was $1.36 in the second quarter of '04 compared to $1.48 a Mcfe during the second quarter of this year. This equates to an 8 percent decrease.

As was the case in the first quarter of 2004, however, Range recorded a significant non-cash G&A charge related to the mark-to-market adjustment of its deferred compensation plan. The non-cash charge totaled 4.3 million during the second quarter, compared to approximately 900,000 in the second quarter of last year. As listeners will recall that this expense results from increases in the value of Range stock that tailed into the deferred compensation plan, and the accounting requirements that the corresponding mark-to-market adjustment be run through the income statement.

These non-cash expenses do not represent additional contributions made to the plan. The adjustment relates solely to the Range stock held in the plan that was contributed over a period of the last seven years.

The income tax provision for the quarter was calculated at 37 percent and a modest 44,000 was taken as current. Net income available to common for the second quarter of 2004 were 7.5 million, representing a 62 percent increase from the second quarter of last year.

Cash flow for the second quarter totaled 43.7 million, a 9.3 million or 27 percent increase from the second quarter of last year. Year-to-date, 2004 6 month total cash flow was 85.9 million, an 18.6 million or 26 percent increase from 2003. And for the last 12 months cash flow totaled $160.2 million.

EBITDAX for the second quarter of 2004 was 47.8 million, a 21 percent increase over the second quarter of last year. For the year-to-date 2004 period EBITDAX totaled 94.7 million. As Rodney mentioned earlier, listeners are encouraged to visit the Range Resources Web site for detailed calculations and reconciliations of these non-GAAP measures.

Turning back toward to our unit cost structure for just a bit, our year-to-date unit cost performance continues to show improvement from last year, and looking back to prior years reveals a more dramatic improvement. For example, total unit cost for the year 2001 using a 3 year average for reserve replacement costs was $3.90 a Mcfe. Based on results today and an estimate for the remainder of the year we currently project the all-in unit cost figure for 2004 to be approximately $2.70 a Mcfe. This represents over a 30 percent decrease in our unit costs from 2001.

The bulk of this unit cost improvement has been in the reserve replacement cost metric, which is mirrored by reductions in the Company's DD&A rate that you've seen. Also, significant reductions in interest expense have been resulting from our debt reduction efforts.

Now looking forward to the last half of 2004, LOE before production taxes is anticipated to range 62 to 64 cents a Mcfe. G&A expense should approximate 28 to 30 cents a Mcfe. And interest expense, including preferred dividends and the Great Lakes acquisition related financings, is anticipated to be 40 to 42 cents a Mcfe.

Now the best news about the lower 2004 unit cost is how this is going to impact our results going forward. Because when you combine the lower unit costs with the rolling off of a substantial portion of our lower-priced hedges, our margin will continue to expand. Our 2003 unit cost margin was 88 cents a Mcfe and 2004 or is estimated to be around $1.68 a Mcfe. In 2004 -- I'm sorry, 2005 that margin is projected to exceed $2 a Mcfe. So as you can see, for the last half of '04 and into '05 we look to report record results for essentially all the key financial metrics.

From a financial standpoint, the mid year 2004 report card in summary is as follows. The balance sheet is far stronger, with longer debt maturities that better match our asset base. Liquidity under the expanded credit facility is at an all-time high of 180 million. Significant progress has been made reducing unit cost and increasing our all-in margin. And financial results, including cash flow and earnings per share, are anticipated to increase significantly in both the last half of 2004 and throughout 2005.

With that I will turn it back to you, John.

Before I turn the call over to Jeff, I just want to take a moment to recognize the great work that Roger and Dorrie Jan (ph), our Controller, and the rest of the financial and accounting team have done. Not only did they perform exceptionally well with regards to our 2 security offerings and the new expanded bank facility, but we are reporting our second quarter results roughly a week earlier. Isn't that right Roger? About a week early? I think it is pretty remarkable given the fact that they had to fold in the Great Lakes acquisition and all the financings and whatnot, so again great job.

With that I will now turn the call over to Jeff Ventura, our Chief Operating Officer, to review or E&P activities and our capital budget.

I will begin by reviewing production. For the second quarter production averaged 181.7 million cubic feet equivalent per day, a 14.8 percent increase over the second quarter of 2003, and a 2.4 percent increase over the first quarter of 2004. The 181.7 million cubic feet per day is comprised of 101.7 million cubic feet per day, or 56 percent in the Southwest Division, 41.4 million cubic feet equivalent per day, or 23 percent from the Gulf Coast Division, and 38.6 million cubic feet equivalent per day, or 21 percent from the Appalachian Division. This increase was due to the success of our drilling program and our acquisition program.

Approximately 70 percent of the Company's production was natural gas. I'm very happy with these results. Our second quarter performance was higher than our plan and guidance. And our operating teams did a great job achieving these results.

Our capital spending for second quarter 2004 was approximately $40 million excluding acquisitions. For the first half of 2004 our capital spending was approximately 68 million. The 68 million is comprised of 38 million or 55 percent from the Southwest Division, 16 million or 23 percent from the Gulf Coast Division, and 14 million or 22 percent from the Appalachian Division.

For all of 2004 we are currently projecting capital spending to be 150 million. This reflects the additional 50 percent ownership that we will have in the Appalachian Division as a result of our recent Great Lakes acquisition. We're also evaluating an additional $10 million capital expenditure that is related to accelerating the pace of drilling in the Appalachian Division.

Turning to drilling results, in the second quarter Range drilled 115 gross or 64 net wells for a 95 percent success ratio as only 6 gross wells or 3.5 net were unproductive. For the first half of 2004 our success ratio was 92 percent.

As of June 30, 44 -- or 42 wells were drilled in the second quarter have been placed in production, while remaining 73 wells were in various stages of completion or waiting on pipeline connection. As of this morning, 42 wells are still waiting on pipeline, and are anticipated to go into production shortly.

As these new wells are put on production and we drill new wells, I expect to see continued production growth in 2004 from our drilling program. Currently we have 17 rigs running, 6 in the Southwest, 10 in Appalachian, and 1 in the Gulf Coast.

I will now review some of the highlights of each of our divisions. I will start in the Appalachian Division where we just completed the acquisition of the remaining 50 percent of Great Lakes Energy. Since we already own 50 percent of the joint venture and operated it, the acquisition integration is proceeding smoothly and efficiently. From an operational point of view, I've recently spent some time with the team in Appalachia and the focus of the division for the remainder of 2004 will be to ramp up shallow drilling, test the refrac potential, continue to build our coalbed methane acreage position, bring online our shallow Trenton Black River discovery and continue to test our acreage position, and to test a potentially significant shelf play in Pennsylvania.

For the quarter, 75 wells were drilled in Appalachia of which 72 were successful. In the first half of the year the division drilled 118 of 259 wells planned for 2004. Currently we're evaluating drilling an additional 40 wells for 2004 for roughly $10 million. Presently 10 rigs are drilling in various project areas in Ohio, Pennsylvania and New York.

In the second half of 2004 4 wells are planned in the shallow portion of the Trenton Black River play in the vicinity of our Harper discovery in New York. And 1 will be drilled in northern Pennsylvania in the deeper portion of the play.

Range has also finished drilling the first 5 wells of the coalbed methane project in southwestern Pennsylvania, and is currently the process of completing the wells. The first production should occur within a month. A second 5 well program will commence later this year.

Let me step back for a couple of minutes and explain why I'm so excited about our position in the Appalachian Basin. From a low-risk development drilling perspective, we have approximately 1,700 proved undeveloped locations to drill that have a rate of return of 20 to 30 percent at a $4 per Mcf flat gas price. At today's 10 year strip, the rate of return on these wells exceeds 50 percent.

On top of that we have an additional 1,100 low-risk locations identified, mapped and ready to go that are not yet booked that have economics similar to the wells that I have just mentioned. So that is an inventory of 2,800 quality locations with attractive economics.

In our largest field, Cooperstown Kramer (ph), plumber a frac (ph) experts, Holberson & Associates (ph), completed a study of the field and believe that there is significant refrac potential of our wells there.

We have 1,659 producing wells in the field. If refracing is successful on 200 of the wells, and if each refrac averages an incremental gain of 50 to 100 Mcf per day per well, that alone has the potential to add 10 to 20 million cubic feet per day. The economics of refracing are very good. We will be testing refracts over the next few months and should know by then if they are successful.

From an exploratory point of view, the Appalachian Basin is the largest onshore basin in the U.S. It is also least explored basin in the U.S. with only 1 percent of the wells drilled in the basin penetrating 7,500 feet. Of those wells very few have been drilled below 10,000 feet, which is considered shallow anywhere else in the U.S. or in the world. The Basin holds potentially productive formations down to 20,000 feet in the center of the Basin. Range is one of the largest acreage holders in the Basin with 1.5 million acres. A lot of this acreage is held by a production with all depth rights, except for the shallow shoals, with wells that will produce for 20 to 30 years or more.

Most of our new undrilled leases have 10 year terms. That allows a lot of time for new exploration and development plays to develop across the acreage position.

We will also be there to take advantage of new technologies as they develop. In that way it is analogous to Mitchell's position in Fort Worth Basin. Mitchell was the largest acreage holder in the Basin for years. By having the large acreage position held by our production, they were there as new frac technology, new drilling technology and increased gas prices combined to make the Barnett shelf play one of the largest gas development in the last decade. The Barnett is now producing over 900 million cubic feet per day.

From an exploratory point of view, one of the target Range will be focusing on is the Trenton Black River. Talisman is having great success there, and is producing at least 115 million cubic feet per day from about 10 wells at about 10,000 feet. Talisman is ahead of us on the learning curve. And they entered the play in the U.S. a couple of years ago based on their experience with the Trenton Black River in eastern Canada, as well as analogous plays in western Canada.

They've knocked the cover off the ball so far with what they have done in the U.S. Fortunately Range has a lot of time left on its leases and is continuing to come up the learning curve. We will be expanding our technical staff and look to increase our activity later this year and in 2005. We will also be pursuing 2 unconventional gas plays. We will be testing our coalbed methane acreage and aggressively expanding our acreage position there.

We also have 40,000 acres leased on a Shell gas play in Pennsylvania that we will be testing within the next 90 days. It is similar to the Barnett in terms of depth, thickness and various other geologic properties. It is a high-risk test where we will be trying new technology a long way from the producing analogy. However, it is fairly inexpensive to try and it has huge upside.

In summary, we have a strong team in place with a great portfolio of projects. We also have an extensive gathering system in the Basin totaling over 5,000 miles, which gives us the ability to tap essentially all major gas markets in the Northeast. As a result of the proximity we're currently receiving NYMEX plus a positive Basin differential of 30 cents -- 35 cents for Appalachian gas.

In the Southwest division our Conger Field acquisition that we completed in the fourth quarter of 2003 is performing well. Actual production volume for the properties are running slightly ahead of the projected volume. The cost savings that were projected for the acquisition are coming in greater than what was projected, and we're realizing them ahead of schedule.

The 2 big drilling program that we began in March is currently drilling the 16th and 17th of 25 wells planned for the year. To date 9 newly drilled wells and 1 recompletion are making the combined incremental rate of 7.2 million per day gross or 5.7 net. Based on the initial drilling results we're also evaluating the refrac and recompletion potential of the field, which hold considerable upside.

The recompletion and refrac potential were identified based on Range's technical team's new completion technique. These wells typically have multiple productive sands in both the Cisco and Canyon formations which are separated by about 300 feet. The company that originally drilled and completed the wells would frac both of the intervals within the same day and crew (ph) them together.

Range's technical team has been fetching (ph) each formation separately, and has found that the Cisco currently has much higher pressure than the Canyon. Our focused efforts are on effectively stimulating the Cisco -- has resulted in the initial drilling results being better than planned. Based on what we have learned, we will be testing the refrac potential of the Cisco formation over the next few months. We have approximately 500 wells that have the Cisco formation in them.

If 100 to 200 of the wells can be successfully refraced, and if refrac's average 100 Mcf per day per well the potential upside, if successful, is 10 to 20 million cubic feet per day.

At the West Fuhrman Moscow (ph) unit in Andrews County, Texas Range recently initiated an additional 10 well program for the shallow 4,600 foot San Andres formation Based on the successful results of an 18 well program completed earlier this spring. Our refrac program is also underway with 4 refracs completed so far which resulted in an incremental rate of 1.5 million cubic feet per day. Additional refracs are being considered based on the initial success of the program.

Also, in West Texas, Range's Val Verde team continues to enhance the value our properties there through a successful recompletion program. 12 wells have been recently recompleted, adding incremental production of 3.1 million gross or 2.4 million cubic feet per day net.

Significantly Range has completed a new discovery onshore Texas that recently tested 4 million per day gross or .8 million per day net at over 10,000 pounds flowing tubing pressure. I can't be more specific as to the exact area since we're still acquiring additional leaseholds. In the area of the discovery Range has nearly 13,000 acres of lease holdings with working interest varying between 25 and 65 percent. Also in the area Range has a quarter interest in approximately 30,000 acres of leasehold options. In addition to the zone that was tested, there is significant behind pipe potential.

Currently 1 rig is drilling in the Oklahoma Panhandle and 2 others are drilling on the Corson (ph) Ranch in the Texas Panhandle. Recent successful drilling in the midcontinent and has resulted in 9 wells that are expected to yield an initial rate of 6.2 million cubic feet per day gross or 2.9 net when placed online, which should occur within the next 30 days.

We have also recently completed a farming of acreage in the Texas Panhandle from a major. And as a result we have expanded our acreage position both in the Corson Ranch and Benthill areas through an innovative farming arrangement. The farming covers nearly 6,000 acres. And we're hoping that with success they can expand it.

We're also in separate discussions with another major and another independent regarding joint ventures in the midcontinent region. Because of our technical expertise and drilling success in the region, as well as our reputation of being a good company to work with, both the major and independent are particularly interested in dealing with us. If successful with either or both of the transactions, we'll continue to add quality acreage and drilling opportunities to the division's portfolio.

Moving onto the Gulf Coast division. The Smith No. 1 well, our successful onshore exploratory well in Orange County, Texas, was placed online in March and continues to produce 7.7 million cubic feet equivalent per day gross or 3.8 net. This well, which was drilled to 14,500 feet encountered 56 feet of high-quality pay in the Gatewell (ph) formation, which the bottom 30 feet were perforated, so we still have an additional 26 feet up hole. Range will spud an offset to this well in early September.

Offshore, Range's successful development well in the West Delta 30 field recently came online at 6.6 million cubic feet per day gross or 2.6 net from the lower string of the built (ph) completion.

The Short String should be online within a week. This well logged over 100 feet of pay and has other productive zones behind pipe. Total measured depth for this well is about 9,700 feet. And Range has a 49 percent working interest in the well.

Range recently spudded its 17,500 foot East Cameron 33 No. 9 Falcon Prospect. We have a quarter -- quarter working interest before casing point and a 37.5 percent working interest after casing point in the well. While this is an exploratory test with significant risk, if successful, it could have a very positive impact on production and reserves. The well should reach TD within 90 days.

In summary, I'm very pleased with our second-quarter results of 14.8 percent year-over-year growth. Looking forward, the remainder of 2004 looks very encouraging. Given the Great Lakes acquisition we will greatly exceed our reserve and production targets that we set at the beginning of year. This was a great acquisition and it is getting better.

Range's production is rising and our balanced drilling program is on target. I believe the key to our drilling inventory is that we have a balanced portfolio of projects ranging from a large inventory of low-risk, good solid economic projects that will continue to drive our production growth, to higher risk, high return projects that can have a significant impact on the Company. In total, we have more than 3,700 gross wells in inventory that represent exposure to approximately 1.1 Tcf of net reserves.

Our technical staff is generating attractive opportunities and our prospect inventory is expanding. Recently we have added 3 new impactful plays. The first is a refrac program that I have mentioned at Conger field, Cooperstown Kramer field and at Fuhrman Moscow field. Combined, if successful, the unrisked potential from the refracs is 20 to 40 million cubic feet equivalent per day.

The second new program is a North Litt (ph) play onshore Mississippi. It is analogous to the prolific Mobile Bay field, which will have a gross ultimate recovery of more than 7 Tcf, with individual well recoveries that will average 50 Bcf. The play we have onshore was generated by the same geologist who was responsible for the discovery of some of the big Mobile Bay production. Although high-risk, if successful, this onshore play has the potential to be in excess of half a Tcf with well recoveries in the 50 Bcf range. Range has a 25 percent interest in this project, which should spud in the second half of this year.

The third new project is a Shell play in Pennsylvania that has some of the same characteristics of the Barnett. We currently have approximately 40,000 acres and we will have 100 percent working interest in this project, which if successful will be several hundred Bcf. Although the risk for the play is high, it is relatively inexpensive to test and it has huge upside potential.

In summary, Range has an excellent technical staff and an excellent inventory, and both are growing. At the end of the day it is a fairly simple business. The key is to grow production and reserves with good finding and lift costs. The difficult part is to do this consistently over time. However, with our technical staff and inventory we are well positioned to do just that. Back to you, John.

As you all can tell, we've got a lot going on in terms of our drilling program and the new projects. And I couldn't be more pleased with Jeff and his team and what they're doing.

Before we turn our thoughts to the remainder of the year, there is a few other areas I will cover. First, at IPF we continue to make progress in monetizing the portfolio. We're using the cash flow generated IPF to help fund our E&P program. During the second quarter the receivable balance at IPF was reduced $2.1 million or 19 percent. For the six months ended the receivable balance has been reduced $3.6 (ph) million or nearly 30 percent. And we continue to expect this trend to continue.

Turning to the hedging front, as you recall in mid 2003 we changed our hedging strategy to place a greater emphasis on costless collars versus straight swaps. Collars gives us, as you all know, the downside protection, but also allow us retain a portion of the upside.

Looking to the last half of 2004, 30 percent of our hedges now are collars; that increases to 53 percent in 2005 and to 84 percent in 2006. When you're looking at our future price realizations there are really 4 important factors working. First, the underlying futures prices for both oil and gas are obviously very strong.

Second, a significant portion of our lower-priced swaps roll off by the end of 2004. Third, the Great Lakes production that we just acquired came to us unhedged. We subsequently hedged a portion of it via collars at very attractive prices. Fourth, the Great Lakes production -- gas production currently receives a positive 35 cent basis differential at NYMEX due to its proximity to the Northeast gas market.

Given the recent Great Lakes acquisition, this positive basis differential will obviously have a larger impact on our overall realizations. When you combine all 4 of these factors, our projected price realizations for 2005 are currently estimated to be roughly 15 percent higher than that projected for 2004.

Looking to the last half of '04, we, as Roger and Jeff have said, we see continued strong operating and financial performance. We're looking for second quarter production to come in at approximately 208 to 210 million a day, representing over a 30 percent increase in year-over-year production.

We are in process of selling some minor value properties which have been factored into this guidance number. We think it is a great time to be selling marginal properties, especially on the oil side with these oil prices as it helps us -- it will help us to continue to drive down and beat down those unit costs that Roger spoke about. The offset however, is that we will lose production volumes as a result.

In addition to the asset sales, we have one offshore platform down for repairs. Also at Duke Pipeline, through which we sell gas from a high rate Smith No. 1 well that Jeff just spoke about, it is also currently down for maintenance. And also we have several newly drilled wells in the MidCon in East Texas. They are experiencing much longer than normal pipeline connection times which are also dampened our third-quarter production.

As I mentioned above, however, despite these issues third quarter production is projected to be over 30 percent higher than the prior quarter, so it will be a spectacular quarter in terms of production growth.

On the revenue side, revenues are expected to continue to rise through the higher production, but also stronger prices. Assuming current futures prices hold for the third quarter, we anticipate third quarter gas price -- I mean -- third quarter price realizations across the board to be $4.40 per Mcfe or higher. This is 31 cents better than what we recorded in the second quarter. As you recall, the second quarter was $4.09 on a Mcfe basis.

When you run all that through the model we anticipate production EBITDAX, cash flow and earnings to reach record levels in both the third and fourth quarters. The key will be to continue to execute the plan and stay focused and disciplined, which is what we have been focused on in the past several quarters.

That really completes our prepared remarks. At this point in time, operator, let's go-ahead and open the call for questions.

(OPERATOR INSTRUCTIONS). Rehan Rashid with Friedman, Billings, Ramsey.

A quick question, Jeff, on the refracs for the Appalachian Basin. The finds you said definitely shows that there is some potential here. Could you give us a little bit more color what has to happen, what are the risks? And I think timing you mentioned third quarter, correct?

Yes. You have wells that have been completed over a number of years. And it is a huge field -- Cooperstown Kramer, three-quarters of a Tcf ultimate recovery -- was discovered a while ago. And you had just frac technology over time develop. In the '70s and really up through the '80s people fraced with heavy gel concentrations in the fluids. And one of the things when you get the gel in there we find that the gel tends to be very damaging. As frac technology evolved through the '90s and really late '90s and through 2004 people started fracing those wells with higher concentrations of CO2 fracs, so you're putting last gel, less fluid on the formation and it tends to be a lot less damaging.

So the opportunity is to go back into those older wells which have some of the original frac jobs on them like that and restimulate them and remove that damage and to see what that does. And because we have so many wells in the field, to the extent we have success it is very repeatable. And the rates of return on those tend to be very high.

An Appalachian -- okay. That's what we were talking about, right? I'm sorry I missed that --?

Yes, that's the refracing potential in Appalachia. It is a little bit different down in Conger Field. There it is going back where people used to stack together 2 different zones separated by 300 feet. And it is a long story, I will try to make it short.

When you do that in one day you don't adequately allow each zone to flow back. Plus to go back and pick up the lower zone, they drilled through it with fluid to knock out rich plugs. They put a lot of fluid back on the upper zone. And it appears that upper zone has much higher pressure. There we have actually gone back and recompleted a couple, not refracs, but we have picked up recompletions in that upper zone, and have made some of the best wells in the field.

And then back in the refrac potential in Fuhrman is the same thing. Frac technology evolved with time. Now we're putting longer fracs, basically thinner cracks with less profit, but getting a lot longer distance. And going back and just fracing wells that used to be fraced with some of the old technology. We've tried 4 of them there and they look great. In fact, one of the wells on a refrac had a better rate after refrac than the initial rate on the well, which is pretty impressive.

On the Trenton Deep stuff the one that we are going to jail is that close to Talisman acreage position? And does that really make a difference to be close to Talisman I guess from a coalology (ph) perspective? Or could you give us a very quick maybe overview of how -- what you think about the Trenton Deep potential?

The Talisman stuff that they're having success with is probably 4 to 5 miles to the north. Although Belden and Blake in each resource have had some success that are probably within a couple of miles of our position.

That acreage block that we have in Northern Pennsylvania is about 65,000 acres. About 50,000 of that is about 12 percent working interest, and about 15,000 is 65 percent working interest. So the well we will be drilling is the lower interest well. But I think the key is we've got a lot of acreage in the -- big acreage position in the Basin. And reality is Trenton runs across the Basin. We've got 1.5 million acres of the Trenton is there. Not that the Trenton is a blanket sand. There are specific parts to that will produce, but as we build our technical team, as we go up the learning curve, as we expose ourselves to more of those opportunities a lot of which will be next year, there's big upside.

And then coming back to this year we are going to get our shallow Harper well online and we will look at offsetting that. And in the vicinity of that we have about 50,000 acres of which are working interest on a small fraction is 50 percent, and on a lot of that it's 100 percent.

Ron Mills of Johnson Rice.

Can you guys -- of I guess, Jeff, this is for you as well -- expand a little bit more on the Shell play in Appalachia in terms of what your expectations are? Has it been tested before in the past? Or have you gone through the formation in terms of thickness and, hopefully, and what you ultimately think reserves can be in that area?

It is a formation that people have drilled through in the past. And typically when you drill through it, it is a trouble zone where you get a lot of gas shows, and there's a big gas influx. Very few people have attempted to complete it, but when they have, they have put very small fracs on it, on the order of 10,000 to 20,000 gallons. I think the biggest one maybe is 50 or 60.

But when you look at that Shell interval it is about the same depth as the Barnett. It has about the same thickness. The logs look similar. You gets big gas shows through it. Some of the geologic things that talk about -- it is in the gas window. The vitranites (ph) reflectance and total organic content, some of that stuff is similar to what the Barnett has.

What people haven't tried though is a Barnett sized simulation. So we're going to pump the first Barnett-type simulation, which is going to be on the order of 1 million gallons into that formation. It is high risk. It is a long way away from the Barnett, but that Shell interval goes across a large area.

You're literally talking -- it is very high risk and it may not work, but if it works, you're talking about several hundred Bcf or more -- Fbcf (ph) type numbers or greater. So it has a very low cost to test but a very huge upside.

What is -- what you mean by a low cost to test?

Less than $500,000.

Per well or for the program to know if you think it will work or not?

For this first test that we will be trying. It will be under that. You're talking about a -- for this particular well, your risk investment is less than $500,000. Your upside is probably 500 Bcf or greater. The risk reward -- the numbers are going in the right direction.

You said you have 40,000 acres up there?

Right.

And would the hope be successful that that too becomes kind of 40 acre type spacing like Barnett?

Yes. And I think we can expand and build the acreage position too.

I know you highlighted the Conger Field. From the acquisition you made, the two rigs that you have going there now, it sounds like from both a reserve and a production standpoint that you all are happy with what you have seen. Any thoughts of adding a third rig out there, and (multiple speakers)?

Yes, we have been very happy with what we have seen. I think once we drill this program we're going to let those -- we will finish our program for this year. We will see if another one for next year. And that will allow the guys time to focus on testing the refracs out there, which have a big upside as well as testing some other recompletion opportunities. So I think we will let the rigs go work on refracs and recompletions and then pick the rigs back up next year.

I know when you all acquired those you all talked about 40 fud (ph) locations and a number of unbooked locations. Is that what you plan on doing between the 25 wells this year and what the number that you plan on next year, or have you seen those numbers in terms of potential drilling locations move up?

Yes, that has increased. We have additional locations -- additional things to do. And really if we go through our budget process this fall we will be looking at the number of wells we want to put out there next year. You're looking at a big inventory. It's probably a three-year inventory or more.

Three-year inventory based on that 25 wells a year?

Right. And that number, like I said if we continue to work that hopefully that will grow.

And then finally to touch on the February acquisition in the Permian, is there any additional information that we can gather on that property at this time?

Yes, well, we did that actually -- we closed on that -- was it in the April? -- it was in April. And we've gone out so far and we've done 3 recompletions. The recompletions are as good or better than what was projected. We're looking at picking up a drilling rig. And we will have a drilling out there sometime in the third quarter. So far so good. And we hope to continue to build that and grow that.

Another thing we are really looking at is expanding the acreage around there as well. And I think we will be able to do that. There is also some opportunity there to increase our interest potentially from buying out partners as well. So we're going to expand it potentially through some small acquisitions, through some leasing in the area. But so far so good. The guys have gotten out there quick, and it looks as good or better than we thought.

And then, John, just to clarify the production numbers you gave, the 208, the 210 million is that for the third quarter or for the second half?

That's for the third quarter.

Does that already include some -- the impact of expected property sales?

Yes, that's net net net. That's the property sales we've done and those are the ones we have got teed up that we are pretty -- we are pretty sure that we will close this quarter.

But for fourth quarter then you expect to see those numbers start ramping up again based on everything that you have talked about today?

Yes.

(OPERATOR INSTRUCTIONS). Jack Aydin of KeyBanc Capital Markets.

I have 3 or 4 questions. Roger, you mentioned about unit cost, everything except DD&A. Could you talk to us about the DD&A going forward, what kind of rate?

I think that $1.38 number is a good number.

How about deferred tax portion? In the second quarter you didn't pay much deferred -- you didn't pay too much current tax. What kind of rate we should use going forward for deferred taxes?

37 percent deferred -- what you saw there current was just small AFP (ph) payment, so that is --.

So you are assuming -- we assume all deferred?

Yes.

And the third question, this is now to Jeff. Jeff, could you talk a little bit more on the Shell. If this well comes through -- let us assume successful the way you want -- is this'll make the project economics and we should assume it is a good deal, or you would require more?

If we had one successful pit, obviously we would be very happy. And then what we would want to do is go there and replicate that a couple of more times. But the good news is that interval is fairly consistent and it goes across a large area. So if you were successful with the first one, the chance of the next one and the next few being successful would be high.

So the good news is, it is a fairly well-known interval -- the expense that goes across a large area. But from my perspective certainly you would want to get 3 or 4 good tests in there before you are off to the races. But I would be very, very, very encouraged if the first one was good.

How much brand-new well -- how much will it cost you to drill a grass roots one?

Fortunately we have an existing well we can test it in. I am going to guess a brand-new well to drill and complete in that might be on the order of it could be -- I would say probably less than $1 million, probably $750,000. And if you really got into a program mode I think you could get your costs down. But of course the first few wells of may be higher.

What kind of reserve are you talking about if we all successful?

Similar to a Barnett vertical well. And then -- if you wanted to simple math you could take 40,000 acres and divide by 40 acres per well, which would give you number of wells. And take an average vertical Barnett well times that. That is the kind of upside it could have. So it has great upside. But again remember tie (ph) risk it's a long ways away from the Barnett. But it is encouraging that it has those kinds of characteristics and it is a fairly inexpensive test.

Now, John, to you now. On the production of the third quarter you mentioned three items that basically asset sales, a platform down, and pipeline connection. If we at all those together, how much of production we are losing during the third quarter?

I would say it is in the 10 million a day range.

Oh, significant.

Yes. I think you make a good point. And I think it is probably important to take a step back and think about all this. The one thing that we're starting to see at Range that is probably more pronounced them let's say 60 to 90, 120 days ago, is the whole service side of the business.

Obviously the rig rates, as everybody had seen, has gone from roughly 1,000 to almost 1,200 today. So rig prices are going up. Not only that is there is more delay between getting rigs. The good news is a lot of our drilling is program drilling, especially in Appalachia and Conger and some of these other places where we keep rigs busy all the time and we're a pretty big operator. So that is a concern of ours, but still a concern.

The second thing is obviously pipe prices have gone through the roof. So both on production casing, pipeline, everything, pipe prices are just sky high. And based on what you're seeing in terms of the scrap market seems to be something that is going to persist for awhile.

Also, you are starting to see just delay in services between frac jobs. We would like to do more frac jobs, these recompletions out in Conger -- we're having a hard time just, again, scheduling those and getting those working just because of the services.

So I think one of the things that we're going to see -- we're starting to see -- and the good news is again so much of ours are concentrated in big fields that we've got some competitive advantages. But still you're going to see wells get delayed because of completions. Wells get delayed spud base in terms of terms of finding rigs. Wells production in terms of getting wells put on production.

So again it is something that we have noticed. You would expect it to happen well before this, with $40 wells and $6 gas. To some degree I think we're a bit lucky that it hadn't happen already. But at least we're seeing -- starting to see those attributes in our operations. And Jeff has talked to the operating personnel. We think we will manage through it effectively. But again it will be something that will -- I think it will be something that will be industrywide, especially if these prices continue to stay up, which they certainly look like they well, especially given today's storage numbers. So I think that is just -- it is part of the -- we want to obviously give you a number that we feel very confident in.

Final question. This is not mine, but a client asked this question, and let me ask you this question. It looks like most of us analysts, we have been missing numbers a little bit because of price realization. My question is, is that due to volatility, hedging, basis differentials or because crude prices or gas prices move so fast that basically we haven't been able to get it right, or what do you think?

I think it is a combination of a lot of things. I think the old days where it was a fairly simple process, those days are over with. You've got the cash market. You have got futures market. You have got hedges. In our case you have got swaps, you have got collars. In our case you've got the NYMEX gas prices in Appalachia being the premium. And you'll see that flow into the third quarter with some of the things.

But that is exactly the reason why I gave you that price realization guidance number of $4.40 for the third quarter versus the 4.09 number that we realized in the second quarter is to give the market and you and your client and all the others a number that we -- at least we feel confident given the futures market as it stands today. Obviously if the futures market changes dramatically it will change somewhat. Not totally direct because of the swaps and the collars and the other things. But I think it is just the fact that it is so more complicated than it was than before. Plus you got a lot of factors changing.

I think too that as you know we've posted on the Web site much more details on the tranches of our hedges, rather than simple weighted averages that we kind of put in the press release. That can have an effect on your price realizations. In addition, just the mix that is coming out of our properties is changing, which changes the differential in the first place.

And as you know, trying to measure NYMEX prices against the standard is a problem. I think the analysts understand it. It is sometimes more difficult for the market to understand the that a lot of our gas is marketed on big week, which is basically a month behind the bids for the volatility on the NYMEX strip. So you can have a current NYMEX growing crazy in a month, but that month's production has already been bid the last week of the previous month. So there is a lag loud effect there.

So a lot of it is how you calculate NYMEX and how you calculate the standard. And we struggle with the same thing, but again as the analysts have lower prices we will try to give you benchmarks as to where those can happen, and kind of running against our model. But it is a very difficult thing to pick.

I was more asking for a philosophical questions, not tied to your Company, but you did answer me. 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.

Thank you all for joining us today. I think in summary we had a solid second quarter, from our prospective right down the middle of the fairway. I think the good news is is that the real impact of the Great Lakes transaction, all the financings plus the impact of our drilling program in the first half of the year, is really going to come through in terms of the third quarter financial results. They are going to be terrific, unless we see a dramatic downward pressure on prices.

Our costs are down. Our production, as I mentioned, will be over 30 percent higher year-over-year. So really -- the rest of this year and particularly '05 really looks really, really promising for our Company. And quite frankly we're quite excited about that and the prospects when you look at the -- how our stock trades versus our peers. And once that additional information gets out in the market we're cautiously optimistic we will continue to see stock appreciation as well.

All in all very pleased. But with that we're going to stay disciplined. We going to stay paranoid in terms of all the things that can go wrong in this business, like I mentioned in terms of things taking longer and wells going off. But the good news is we've got a big cross-section of properties. We've got some diversity. We've got a big drilling program that has got diversity. We've got things that Jeff and his teams like refracs are coming up that are relatively low in capital but big on impact. And again, if any one of those works, it will have a big impact.

So again, we are very cautiously optimistic in terms of that. But in the overall sense, we're very pleased where we are strategically and really feel like that as we continue to put the numbers on the board from quarter to quarter, that as we prove ourselves, that we will move into this -- the higher multiple groups that a lot of the long lived companies with large drilling inventories are trading more in the 6 to 12 times multiple versus us, which we are trading in the 4.5 times multiple. So we think there's a lot of room there. But I think the onerous is on us. The market is very small. As we continue to perform that will take care of itself. So our charge is just to perform and execute, and that is what we plan to do.

So thank you again very much, and you'll see you at the third quarter. Goodbye.

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