山脈資源 (RRC) 2004 Q3 法說會逐字稿

Welcome to the Range Resources 2004 earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements.

After the speakers' remarks, there will be a question and answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome to everyone. Today on the call are John Pinkerton, President, Chief Executive Officer, Jeff Ventura, Executive Vice President and Chief Operating Officer, and Roger Manny, Senior Vice President and Chief Financial Officer. Before turning the call over to John, I'd like to cover a few administrative items. First of all, we have filed our third 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 supplemental financial tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDA, cash margins, dilutive shares as discussed on the call today. The tables will give you detailed information of our current hedge position by quarter, which we periodically update during the quarter.

Range will be presenting at the Friedman Billings investor conference in New York on December 1st. Materials being presented at the conference will be available on our website just prior to the conference. Now let me turn the call over to John.

Thanks, Rodney. Before we review third quarter results, I'll summarize a few key points. First of all, we're very pleased with the third quarter results. Production rose 32% on a year-over-year basis, and 15% on a sequential basis, reaching the top end of our guidance despite weather and pipeline issues. Our capital program is generating very attractive rates of return and we continue to be very pleased with our drilling results, and Jeff will talk about those in his segment. On the cost side of our business progress, you know, we continue to make progress in terms of reducing our unit costs. Over the last three years, total unit costs have been reduced by over 30%. So, pretty good job there. In particular, in this quarter, our DD&A rate fell 13 cents per Mcfe in the quarter, reflecting the favorable recent reserve replacement that we've had. And again, Roger will talk more about that in his review.

On the acquisition front, the integration of Great Lakes, the remaining 50% of Great Lakes that we bought back in June, is progressing with no surprises so everything looks good there. Importantly, the Great Lakes transaction completes an initiative we began several years ago to simplify our balance sheet and organization so we're pleased with that, as well.

Lastly, one of the significant components to long-term growth and consistent growth and profitability is our large multiyear inventory of drilling projects through the combination of the projects that we've organically generated by our technical teams, and the ones we've acquired through the acquisitions, we continue to build our inventory to something over 3700 drilling locations, so we've got a big inventory to drill up over the next three to four to five years. Exploiting this inventory, obviously, is going to give us predictable growth for several years to come, and Jeff is going to talk about the progress of several new exciting projects in his segment that will add to that inventory.

In summary we're significantly ahead of our goals for the year already at the end of the third quarter and we also have the fourth quarter to continue to make further progress. So, we're pretty excited about the year. It's obviously going to be the best in the Company's history. With that, I'll turn over to Roger for the financial review.

Thank you, John. The third quarter 2004 financial results reflect the continued strong operating performance of the Company, with production up 32%, and realized oil and gas prices up 17% from the third quarter of 2003. Record levels of revenue and cash flow were achieved. Progress continues to be made in debt reduction as excess cash flow reduced debt during the quarter by $22 million.

Looking at the third quarter income statement, the first thing to note is the $18.6 million gain on debt retirement in 2003, which distorts the comparison to the 2004 numbers, as noted in our news release, if one adjusts the 2004/2003 net income for the debt retirement gain and other special items, there's a 157% increase in our earnings between the third quarter of this year and last year. Excluding the special items, revenues would have been 54% higher than last year, driven by a similar 54% increase in oil and gas revenue. Third quarter 2004 expense performance was encouraging, especially in light of increasing service costs. Direct operating expense for the quarter was 66 cents per Mcfe compared to 55 cents per Mcfe for the prior year period, which did contain a one-time adjustment. The year-to-date operating expense figure is 64 cents per Mcfe. This compares to last year's figure of 63 cents. So, we're pleased to be only one cent higher than last year, even though service costs and equipment costs have increased.

The sale of nonstrategic properties will further assist us in holding the line against higher operating costs going forward. Production taxes were 28 cents per Mcfe for the third quarter of '04, compared to 21 cents last year, due to higher oil and gas prices. Higher dry hole costs are primarily responsible for the increases in quarterly and year-to-date exploration expense. General and administrative expense was 28 cents per Mcfe for the third quarter, that's down 4 cents from last year. Year-to-date unit cost G&A expense is likewise lower than last year. As a reminder, Range does not capitalize any G&A or interest expense.

There are a couple of G&A items worthy of special mention. First, Range, like all public companies, has experienced increased costs from Sarbanes-Oxley implementation. However, our growth and production volume and greater economies of scale have allowed the Company to absorb the higher absolute costs without increasing our unit costs. And our Sarbanes-Oxley implementation is on schedule with preliminary testing well under way. Second, as has been the case in previous quarters, Range recorded a noncash G&A expense related to the mark-to-market adjustment of its deferred comp plan. The noncash charge totaled $4.8 million in the third quarter, that's up from $4.3 million in the second quarter. These noncash expenses do not represent additional contributions made to the deferred comp plan, but rather they stem from the accounting requirement that changes in the market value of Range stock held in the plan must be run through the income statement.

Rounding out the rest of the unit cost story, interest expense and preferred dividends totaled 39 cents per Mcfe in the third quarter of '04, compared to 37 cents last year. This reflects the shift from lower cost floating rate bank debt to the higher fixed interest rate on Range's additional $100 million of its 7 3/8 notes placed in June. Our fixed to floating rate balance, including our interest rate swaps, is now approximately 50/50, and we're satisfied with this ratio at this point in the interest cycle. Lastly, the DD&A rate for Mcfe, as John mentioned, was $1.36 in the third quarter this year compared to $1.49 per Mcfe last year. I feel this 13-cent reduction is especially significant as it does signal the Company's recent favorable reserve replacement cost and trend. Net income after preferred dividends for the third quarter was 12.1 million, that's a 63% increase from the second quarter this year, but lower than the prior year period due to a large -- the large gain on the debt retirement last year.

The cash flow for the third quarter totaled $56.5 million, that's a $20.8 million or 58% increase from the third quarter of 2003. Year-to-date 2004 cash flow was $142.4 million, a 38% increase over 2003. It's interesting to note that cash flow for the first nine months of this year is essentially equal to the full year of 2003. EBITDA for the third quarter of '04 was 61.9 million, or 52% higher than last year and the year-to-date 2004 period, EBITDA totaled $156.7 million. As Rodney mentioned at the open, listeners are encouraged to visit the Range Resources website for the detailed calculations and reconciliations of these non-GAAP figures.

Turning to the balance sheet, continued progress was also made in the third quarter in simplifying our financial structure. On August 2, we redeemed the remainder of our 6% convertible subordinated debentures , the Range balance sheet now includes only two debt securities, the senior bank credit facility and the 7 3/8% senior subordinated notes. Our total leverage continues to move downward. Our debt to capitalization ratio was 57% at the end of the first quarter this year, 56% at the end of the second quarter, and 55% at September 30. Excluding the other comprehensive income adjustment, the debt-to-cap ratio would have been 51% at September 30. The $22 million in debt reduction made during the third quarter represents a meaningful reduction, given the increases in our capital program this year, now, we're going to continue to chip away at our debt using excess cash flow above capital expenditures and based on current prices, projected excess cash flow should reduce our debt-to-cap ratio below 50% sometime in the second quarter of '05. Range's credit statistics continue to improve with annualized third quarter EBITDA interest and preferred dividend coverage. That's 8.3 times. And our total debt to annualized third quarter EBITDA is two times. The bank facility, we had some progress there. On October 1 at the regularly scheduled redetermination date, the Range bank group voted unanimously to approve our requested $500 million borrowing base. Now, we currently have approximately $190 million in available liquidity under that facility.

So, in summary, the third quarter of 2004 represents a solid quarter of executing our growth strategy. The all-in unit cost structure is continuing to improve and as commodity prices increase and our lower price hedges roll off, our margins are expanding. Now, add in the significantly higher production volumes that Jeff's team has delivered, and the result is another record quarter and steadily increasing financial results that should continue in the fourth quarter and throughout 2005. Now back to you, John.

Thanks, Roger. Nice update. I will now turn the call over to Jeff to review the expiration and development activities and the stats of our capital program as well as some of the new projects that we've got -- that we've got under way. Jeff?

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

For the third quarter, production averaged 209.6 million mcfe per day, a 32% increase over the third quarter of 2003, and a 15% increase over the second quarter of 2004. The 209.6 million cubic feet per day is comprised of 101.5 million cubic feet per day, or 48% from the Southwest Division, 71.1 mcf per day or 34% from the Appalachian Division, and 37 mcf per day or 18% from the Gulf Coast Division. This increase was due to the impact of the Great Lakes acquisition and the success of our drilling program. Approximately 70% of the Company's production was natural gas. Our third quarter performance was higher than our plan and guidance, and our operating teams did a terrific job achieving these results. On the cost side, our direct operating expenses on a unit of production basis came in at 66 cents for the quarter. For the first nine months of 2004, they were relatively flat versus the first nine months of 2003, 64 cents versus 63 cents per Mcfe.

Given the high oil and gas price environment we're in, I'm very pleased that we've been able to control our costs since the increased activity in the oil and gas sector has placed upward pressure on oil field goods and services. Part of this is being cost conscious and part of it divesting of marginal high cost properties. We look at this every month and make a priority. Our capital spending for the third quarter 2004 was approximately $53 million excluding acquisitions. Through September 30, our capital spending was approximately $122 million. The $122 million is comprised of $66 million or 54% from the Southwest Division, $34 million or 28% from the Appalachian Division and $22 million or 18% from the Gulf Coast Division. For all of 2004, we're currently projecting capital spending to be $169 million. This reflects the additional 50% ownership that we have in the Appalachian Division, as a result of our recent Great Lakes acquisition, as well as the capital to facilitate additional drilling.

Turning to drilling results, in the third quarter, Range drilled 130 gross or 113 net wells for a 98% success ratio as 3 gross or 2.5 net wells were unproductive. Through September 30, our success ratio was 94%. At quarter-end, 59 wells drilled in the third quarter had been placed on production, while the remaining 71 wells were in various stages of completion, or waiting on pipeline connection. As of this morning, 59 wells are still waiting on pipeline and are anticipated to go in production shortly. As the wells are put on production and we drill new wells, I expect to see continued production growth in the fourth quarter and into 2005 from our drilling program. Currently we have 23 rigs running, 9 in the southwest, 10 in Appalachia, and 4 in the Gulf Coast. I will now review some of the highlights of each of our divisions.

I will start with the Appalachian Division where our recent acquisition of the remaining 50% of Great Lakes Energy is proceeding smoothly and efficiently. For the quarter, 85 wells were drilled in Appalachia, all of which were successful. For the first nine months of the year, the division drilled 214 of 290 wells planned for 2004. 99% of these wells were successful. Presently, 10 rigs are drilling in various project areas in Ohio, Pennsylvania and New York. From an operational point of view, I've continued to spend time with the team in Appalachia and the focus of the division for the remainder of 2004 is to ramp up shallow drilling, further test of refrac potential, continue to build our coal bed methane acreage position, bring online our Shallow Trenton Black River discovery, and continue to drill our acreage position and to test our shale play in Pennsylvania.

I will briefly discuss each of these five projects, starting with the low-risk drilling program and moving to higher risk exploration. Starting with the drilling program, we have approximately 1700 low risk development drilling locations booked, and another 1100 low risk drilling locations identified, mapped, and ready to go that are not yet booked. That's an inventory of 2800 quality locations. The economics of the $4 flat gas price range from 20 to 30% rates of return, and using a 10-year strip price, rates on return are well in excess of 40 to 50%. At a rate of drilling prior to the acquisition, we planned on drilling a total of 260 wells this year, which is an inventory in excess of 10 years. One of our goals post-acquisition was to increase the pace of drilling in order to capture additional net present value, and speed the conversion of nonproven reserves to proven. This year we will drill more than 30 additional wells than originally planned prior to the end of the year. Next year we plan on drilling 400 wells in the Appalachia division. The next project in the division that I want to talk about is refracs.

During our last conference call, I mentioned that we had significant potential from refracting. Our initial study in the Cooperstown Kramerton field in NW Pennsylvania identified approximately 200 refrac candidates. Since then, we've completed 4 refracs. The refracs yielded an average daily increase of 60 mcf per day per well. The estimated finding cost of the new reserve adds from the refracs is 52 cents per Mcf and the rate of return is over 100%. 10 more refracs are planned prior to year-end and assuming success the program will be pursued aggressively in 2005. If the refrac program is successful, we plan on doing at least 100 wells next year.

The technical strategy with the refracs has been to identify wells that look good on logs, but that have underperformed as compared to wells that look similar on logs. We believe the reason for the underperformance is because many of the wells were drilled more than 10 years ago and were completed with technology from that timeframe, which was to hydrolically fracture the wells with water that contained gels. Modern completion technology is to frac these wells with 70 quality nitrogen foam fracs. This creates adequate fracture dimensions, but eliminates a lot of the water and all of the gel, which are damaging to low permeability clay-filled sandstones in the Medina formation.

Moving on, we completed drilling the first 5 wells of the coal bed methane program and all of the wells are now on-line. Early results are encouraging and at this point, we're producing more gas than expected and less water than expected at this point in time. In this area, coal bed methane wells are about 1300 feet deep. Successful wells produce 35 to 40 mcf per day, and have grown ultimate recoveries of 175 million cubic feet per well or more. Finding and development costs are about $1.20 per Mcf, and the rate of return on a $4 flat price case is about 20%. At strip pricing, it's greater than a 50% rate of return. We currently have 25,000 acres and 4 separate projects in southwestern Pennsylvania. These wells can be drilled on 40 acre spacing, therefore, the potential upside of this project, with our current acreage position, is more than 600 wells. Prior to year-end, we plan on drilling 5 to 10 more wells and aggressively expand our coal bed methane acreage position. In the Trenton Black River play, we plan on drilling five more shallow wells in New York prior to year-end, including an offset to our Harper discovery well. Our drilling in the deeper portion of the play will occur next year.

Two key developments have occurred near our 81,000 acres in the deeper portion of the play in northern Pennsylvania. Recent significant drilling success by Talisman has occurred within two miles of the eastern portion of the block, and recent drilling success has occurred within 2 miles to the north of the block by another operator. We are currently reprocessing existing seismic data on the block and may acquire new data prior to drilling next year. We have also recently added a key explorationist to our Appalachian team who has exploration successes in the area. Our working interest in this acreage block ranges from 12% to 69%, which we're looking to increase.

Finally, our highest risk opportunity in the Basin is our shale test in Pennsylvania. We have 100% working interest and 38,000 acre position in the shale play that in many aspects looks analagous to the Barnett shale play in Texas. Obviously, we're a long way from the Barnett, but our plans are to pump a Barnett-style frac on the shale,, which will be a million gallon frac shelf. Previously, typical fracs in the area have been 10,000 to 20,000 gallons with the previous largest frac being 60,000 gallons. We'll be keeping the results of this test confidential probably through year-end. If successful, we believe we can significantly expand our acreage position. If this test fails, the total cost to test this high potential play is only around half a million dollars. We should have the initial results within 60 days. That being said, I do think this type of project could take several twists and turns before we determine whether or not it's commercial.

In the Southwest Division, our Conger Field acquisition that we completed in the fourth quarter of 2003 is continuing to perform well. The two redrilling program that we began in March is currently drilling the last 25 wells planned for the year. To date, 20 wells have been completed and placed on production, are making a combined incremental rate of 8.2 million per day gross or 6.2 million net. As I mentioned during the last conference call, we're also evaluating the refrac and recompletion potential of the field, which may hold considerable upside. We will have tested this concept by year-end and if successful, will aggressively pursue this opportunity in 2005. At the West Fuhrman-Mascho Unit in Andrews County, Texas, Range has expanded its drilling program to include 2 rigs and is currently drilling the 38th and 39th well of the 51-well infield program. So far, nine refracs have been done, adding 2.2 million gross or 1.7 million cubic feet per day net. We believe that we have more than 30 additional refracs to do. As a result of the new drilling and refracs, the field is now producing 13.4 million cubic feet per day, versus 4.5 million in January. This is where most of our increased oil production is coming from.

Also in west Texas, Range's Valverde team continues to enhance the value of our property there through a successful recompletion program. 18 wells have been recompleted adding incremental production of 6.2 million per day gross or 4.7 net. Previously, Range announced an onshore Texas discovery that recently tested 4 million per day gross or 0.8 million per day net, at over 10,000 pounds flowing tubing pressure. By year-end, pipeline construction and facility installation should be completed to begin sales in the areas of discovery, Range has nearly 15,000 acres of lease holdings with working interest bearing between 25% and 100%. Also in the area, Range has the 25% interest in approximately 30,000 acres of lease hold options. In addition to the zone that was tested, there's significant (dehide pipe) potential. Plans are to begin an additional well prior to year-end. Currently 3 rigs are drilling in OK and 2 others are drilling in the Texas Panhandle.

During the third quarter, 10 wells were drilled in the Mid-Continent, all of which were successful. The Galileo No. 1 in Oklahoma is producing 2.3 million per day gross. 0.9 million per day net and has four additional zones behind pike. In the Texas Panhandle, we've successfully tested two new horizons on our acreage. The Hunton discovery was recently tested at 2.7 million per day gross, or 1.8 million per day net and is expected to begin sales in 10 days. This well also has three additional zones behind pipe.

Also important is our new Brown Dolomite drilling in the Texas Panhandle. We now have three new Brown Dolomite producers, which are producing at a combined rate of 4.2 million per day gross or 2.3 million per day net. The Brown Dolomite in these wells is found at 3600 feet. We have identified 5 potential new Brown Dolomite locations, we've also just recently completed 2 new acreage transactions in the Mid-continent region. Combined, these transactions added about 76,000 gross acres with more than 65 attractive new drilling opportunities to the division's portfolio. We believe that our technical expertise and drilling success in the region as well as our reputation of being a good company to work with, were the keys to completing these transactions.

As a result of these transactions, combined with the additional new leases, we'll continue our current pace of running 4 to 6 rigs in the Mid-Continent. In the past, we've typically run 2 rigs.

Moving on to the Gulf Coast Division, the Highland 119-a 1 was placed on-line and is producing more than 30 million cubic feet per day gross, 2.6 million cubic feet per day net. An offset development well, the 8-2, just completed drilling last weekend and is successful. It should be on-line in the fourth quarter. A third well, the A-3, will spud shortly. Two other wells just finished drilling, the Falcon prospect in East Cameron 33 recently reached total depth. Current information suggests a primary objective may be wet. However, the operator is conducting further tests in the primary objectives as well as in up hole zones. We have a 25% working interest in this well.

Another well which recently reached total depth is the Smith No. 2. That's an offset to the Smith No. 1 onshore discovery in Orange County, Texas. It encountered a combined 70 feet of net gas pay and 2 with gateway intervals. The well, in which we own a 67.5% working interest, is expected to be online by mid-November. Smith No. 1 continues to produce at 9.3 million cubic feet per day equivalent or 4.6 net from the lower 28 feet of gas pays off. The Smith No. 1 has a total of 55 feet of net gas pay versus 70 feet in our new discovery.

Another well is currently drilling in the Gulf of Mexico. This is an exploratory test in west Cameron 36, in which Range has a 33% working interest. The prospect is a 12,400 foot well that has most likely gross reserves of 40 Bcf. A working interest is 33% and our net dry hole exposure is $1.7 million. It's a technically sound quality prospect with good AVO support. The well should be logged within two weeks. Also, our high potential onshore Northrup test looks like it will spud in the first quarter of 2005 as we continue to build our acreage position. In summary, I'm very pleased with our third quarter results of 32% year-over-year growth. We will greatly exceed our reserve and production targets that we set at the beginning of the year. Excluding property sales, it looks like our reserves will grow at 40%, which is a 470% production replacement for 2004. Before sales, we're currently estimating our cost of find and development will be $1.35 per Mcfe.

The key is we're not just growing production, but keeping our eye on the ball and keeping our finding and development costs at very attractive levels. I believe that with these metrics we will be in the top of our pier group.

2004 looks to be a great year for Range and I'm excited about the future. The key is the drilling inventory and the in fact we have a balanced portfolio of projects, Ranging from a large inventory of low risk, good, solid economic projects that will continue to drive more production growth to higher risk, higher return projects and could have significant impact on the Company. In total, we have more than 3700 gross wells in inventory that represents exposure to approximately 1.1 Tcf of net reserves. As a sidenote, we're not depending on one or two projects for future growth, having a large balanced inventory is a real key in my mind.

Looking back over the last year, Range has made a lot of progress and is in a significantly better position today. I say that because I believe the prospect inventory and the technical teams are stronger today. I'm now going to take a few moments and talk about what's new today versus one year ago in regards to our prospect inventory.

I will start with the Mid-Continent. As compared to a year ago, as compared to one year ago, we have 76,000 new acres with more than 65 new prospects and I believe this will grow with time. In the Texas Panhandle, we've opened up two new productive horizons, the Hunton and Brown Dolomite, and both have multiple offsets. I believe it will open up a third new horizon shortly. We have a new shallow plan Oklahoma that I haven't discussed yet, however, early results look very encouraging. This project could lead to drilling over 100 wells. In the Permian, we have the new East Texas discovery, which should be online by year-end. It's a high-rate well that could have multiple offsets. It could have a chauk field above it, as well.

In Congo field we still have multiple canyon wells to drill, bur over the last year, we've opened up new Cisco potential. We're currently testing an exciting behind pipe wolf camp interval that has unconventional looking pay that really has a lot of repeatability in the field. At Fuhrman, we have multiple wells to drill but within the last year we've proven the viability of refracs. In New Mexico, we're currently drilling our first well on our new acreage. If it's successful it could lead to drilling 25 wells.

In Appalachia, we now own 100% of the project versus 50% at this time last year. We now have 25,000 acres of coal bed methane acreage and have 5 producing wells with encouraging initial results. We're aggressively growing our acreage position there. And Kramerven Cooperstown our early results on refracs looked encouraging. In 2005, we're looking at a significantly expanded drilling program. Currently we have significant Trenton Black River discoveries offsetting our Bradford county and testing a new shale play. In the Gulf Coast, we have a new Yegua discovery in Orange County with recent offset drilling success.

We have a new Highland 119 discovery with recent offset drilling success. We have an exciting new deep onshore Northrup play. We have new projects in Parish, east of our Walu area and currently drilling a good exploratory prospect on west Cameron 36. All of this is new since last year. More importantly, we've grown our technical team to approximately 70 people. This is a talented group who is responsible for generating all of the projects that I've just mentioned and is continuing to generate exciting new opportunities.

At the end of the day, it's a fairly simple business. The key is to grow production and reserves with good finding and lift costs. The difficult part is to do it consistently over the time. However, with our technical staff and inventory, we're well-positioned to do just that. Back to you, John.

Thanks, Jeff. Before I turn thoughts to the remainder of the year and '05, I'll just cover a few other miscellaneous areas. 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 third quarter, IPF receivable balance was reduced by about $3 million, 34%. And for the year, the receivable balance has been reduced by over $6 million. And by year-end, the balance should be well under $5 million. So, good progress there.

Turning to the hedging front, as many of you will recall,mid-'03, we changed our hedging strategy to place greater emphasis on (costless) collars versus straight swaps. We believe the callers give us downside protection but allows us to retain a significant part of the up side. Looking to the fourth quarter of '04, 30% of our hedges are collars. That increases to 59% in '05 and then 91% in '06. So, we're changing the texture of our hedges dramatically. When you're looking at future price realizations, there are really three important factors regarding Range. First is the underlying futures price is for, obviously for oil and gas, are very strong. Second, a significant portion of our lower priced swaps roll off at the end of '04, thank goodness. Third, our Appalachia gas production currently receives a positive 35-cent basis differential or NYMEX due to the proximity of the northeast gas markets. And so as a result of the greater ax acquisition, it is having a larger impact on our overall realizations. When you combine all of these factors together, the projected price realizations for '05, based on current futures prices, are currently estimated to be over 20, 25% higher than what we're projecting for '04.

So, you can see, you know, we're going to have a pretty healthy increase in revenues just from the price realizations. With regards to asset sales, we focused on divesting the properties with high lift cost and limited upside. We believe this is really a great environment to maximize these types of assets. Through the first nine months of the year, we sold $5 million of property and a number of small transactions. But just in the next couple of days we ought to close roughly $20 million of sales. So, that number will jump up. And when you include the sales we've done at IPF, we should complete over $30 million of divestitures for 2004.

Now let's look to the last quarter of the year. Obviously based on what you just heard from Jeff, we expect to have very strong operating performance in the quarter, we're looking for production to come in at about 213 million cubic feet a day, which will be an all-time record production for the Company. And it also represents a 29% increase year-over-year. The asset sales I just spoke about will reduce production by 3 to 4 million a day, which has already been factored into the guidance numbers, so you don't need to reduce it.

In addition to the asset sales, we've got several properties down for repairs and also I think it's important that throughout our regions we see an increase in downtime from third party pipeline and compressors. You know, we really see this as an increasing trend in the industry as the infrastructure is obviously pretty old and is being operated to a maximum full-out capacity. In the guidance number above, we've tried to take into account these types of issues, but hopefully it won't be any big things, but tried to take most of the things we can foresee in those numbers. I think the 213 number is something we feel pretty good about. As I mentioned above, despite these issues, this production number is going to be roughly 30% higher than the prior year quarter. But, you know, the really encouraging point to me is that Range is hitting, you know, we're hitting our production plan and our guidance numbers despite the downtime associated with the weather or hurricanes and these third party pipelines I spoke about. You know, from my perspective companies that can consistently perform irrespective of the ups and downs that occur in this industry are the companies that will exhibit the best share price performance.

We believe our diversified property base and our large drilling inventory certainly was evident in the third quarter in terms of hitting those guidance numbers despite the hurricane. And we believe we're well on our way toward our goal of making Range one of those companies that consistently performs. Returning to fourth quarter expectations, we anticipate revenues will continue to rise due to higher production and stronger prices. Assuming current futures prices and the hedges we have in place, we anticipate fourth quarter price realizations to be in the 475 to 480 Range per Mcfe. This is 31 to 36 cents higher than the $4.44 per m that we realized in the third quarter. We anticipate production revenues, cash flow and earnings to all reach record high levels in the fourth quarter, and to give you a perspective, we anticipate fourth quarter '04 earnings to be roughly 4 times that of '03.

Now let's take a quick peek at '05. As Jeff said, we're pretty excited about what we're seeing. Assuming no significant exploration successes and no additional acquisitions, we're looking for production to increase no less than 15%. I will be pretty disappointed if it's not over 20, quite frankly. With the material portion of our lower price swaps rolling off, the realized prices that we anticipate for '05, from what we're seeing today, should be at least 20% higher than what's projected for '04. So, you've got, you know, increasing production, you have prices higher as well, so, '05 revenues, cash flow and earnings should far exceed those for '04.

Earnings per share are projected to be more than double in '05 while cash flow per share is expected increase well over a $1per share. Higher revenues coupled with our lowered unit cost that Roger spoke about is going to generate some substantial excess cash flow. We'll use the excess cash flow first to lower our debt-to-cap to below 50%. That should be sometime early to mid second quarter. With the remainder will be available to fund acquisitions and additional drilling. You know, from our perspective, the key components of these results will be, you know, prudently exploring our large drilling inventory. I see this as important for several reasons. First, the drilling and MP will allow us to steadily increase production at attractive finding costs. One of the things happening in the industry is the finding costs are rising fairly rapidly. Our DD&A rate is actually going down. Again, I think it's a testimony to some of the good projects we've got and some of the reserves we're adding.

Second, it allows to us have -- have a good solid drilling allows us to be opportunistic but also very disciplined toward acquisitions. What I mean here is we don't have to complete acquisitions for baseline growth. We can focus on acquisitions, opportunities that have attractive economics but -- but more importantly also build long-term value, so, we're not looking for acquisitions to be a short-term fix. Obviously the key as in any strategy, will be to execute and stay focused and disciplined. So, that will be our hallmark for the remainder of the year, as well as '05. At this point, Monica, let's go ahead and open the call for questions.

Thank you. (OPERATOR INSTRUCTIONS) Your first question comes from the line of Rehan Rashid of FBR.

Good afternoon, gentlemen. Great quarter.

Thanks, Rehan.

Quick question for Jeff. Appalachia, a lot of stuff planned. Of course I'm sure you've got the infrastructure and the process laid out, as well, but give us some comfort that, you know, you will be able to release 400 wells on the normal side that you're planning, plus maybe drill what -- 100 wells for the refracs and then the CBM. Any -- I guess the question is really logistically speaking, any concerns to -- to execute such a full plate?

No, I think -- John and I have been talking with Steve Gross and the team up there now for a few months and, you know, really thought through well all the logistics, in terms of rigs and people and equipment, pipelines, facilities, all that type of thing. I think we're well positioned to do that. We have a good team up there. We have 300 employees, you know, throughout that region. That's, you know, pumpers, secretaries and everybody. But we have a good, strong team, thought through it well. They're excited about that challenge and I'm confident that they will meet it or exceed it.

Okay.

And just to interject, we're adding people up is there, as well. So, I mean we're not naive enough to that we can just deal with the existing staff. So, we're adding key quality staff up there as we go through the process. But the good news is we really approach them with this idea several months ago. So they've had adequate time, as Jeff mentioned, to plan and to think through all the issues logistically, you know, pipelines, have you. So, I think we're in good shape, but the proof will be in the pudding.

Gotcha. Gotcha. And less concerns from the supplier side, service companies and what not?

It's the same thing, it's part of that preplanning, also telling all of those people the equipment and supplies and number of wells we're going to drill of what we will need and they're prearranging a lot of thing ahead of time.

Gotcha, thanks. A couple of more quick questions. On the coal bed methane side, when, roughly, do you think we will be able to get a feel for the production rates here or the averages that you gave earlier, kind of will hold for your acreage, as well? And then on the refrac side you had mentioned (undenvelts) next year, but how do you envision this program growing beyond that? What will it take? And what are the other milestones that you will look forward to?

Okay, in terms of coal bed methane, you know, the encouraging thing is that we saw such quick gas production and really at lower water rates initially than the analogous field that we're looking at. Really over the next 30 to 45 days, we will have a pretty good feel for that first (pievan), and if we're encouraged we will be drilling additional wells by the end of the year. So, that -- that looks good. In terms of the refracs, you know, I'd like to see us do a minimum of -- if it works, we're going start into the next 10 wells, if those 10 wells hold up, we will just go on with the program. We've identified 200 and what we're going to try to do is start those in January and, you know, we can probably do those at a pace of, you know, 2 to 4 per week or something, once we get up and running. So, you know, obviously if the first four look good, the next 10 look good, if the next 100 look good, we will proceed into the next 100 and that was really our initial study. So, the other thing we will do is kick off a second study and third study to look at other opportunities in that field, and then expand and grow it out from there. We've got a lot of wells in the area, you know, I'm not -- not all of those are going to be refrac candidates, but, you know, even if it ends up being 200 and the 60 Mcf a day holds, that's 12 million a day just from refracs at 50 cents per m finding costs and over 100% rate of return. So, there is an opportunity for that to grow from there, though.

Okay thanks. I will jump off and come back later. Thanks.

Your next question is come Ron Mills of Johnson Rice.

Good afternoon. You did a good enough job on the discussion to head off a lot of questions, but in terms of property sales, John, you mentioned, I think it's 4 or $5 million a day the production associated with those sales that you factored into the guidance. Any information on the amount of reserves associated with the property sales?

I think the number is about $4 million a day that we're talking about. It's roughly , best I can recall, it will be in the 20 to 25 Bcf Range. So, it's -- it's -- it will be roughly -- for those probably about a buck an m, which sounds low, but a lot of these properties really are on the -- ones that have pretty high lift costs and at the tail. You know, there's no -- there's no real upside to them. So, but I think the number is around 20, 25 Bcf. It could be a little bit lower than that. But I think that's a good ballpark number.

And were the numbers in terms of the -- the reserve growth, your new reserve growth target or expectation to hit 40% and -- and your finding cost, too, is that -- did that already include the impact of the property sales?

Those were -- all of those numbers that I said were excluding property sales so I was saying that for 2004, excluding property sales and at really constant pricing year-over-year, the reserves will grow at 470% replacement and at about $1.35.

Okay.

You'd have to take out that 20, 25 Bcf out of that number.

Okay. And in terms of the Brown Dolomite and the Hunton formations that you spoke of, can you just provide a little more color in terms of what the expectations are there, in terms of running room and what kind of reserve potential those formations could provide?

Yeah, the brown dolomite is 3600 feet, fairly prolific. The initial rates on the wells have been, you know, a million to two million per day. In terms of finding and development costs, you're adding reserves for less than 50 cents an m. They're very economic. Payouts will be literally a half year or less, plus or minus the current pricing. We've got five additional locations identified and as we continue to work our acreage and new acreage, I mean there's the opportunity for that to grow. So, it's very attractive play to continue to pursue. In some cases you can stack them with deeper (moro) tests. In terms of the Hunton, the Hunton well, you know, I talked about the gas rate and the gas rate on that was, you know, on the order of, you know, 2.5, 3 million per day, but also at very high cubic pressure, 2700 pound cubic pressure. The Hunton wells in that part of the world are at about 11,000 feet, very reasonable depths. Again, it will be great economics, great payout. We see probably a minimum of three offsets to it. Plus, that well found -- you know, had three behind pipe pays in it. When we drill our first offset to it, We will be drill stem testing on the way down, some of those behind pipe pays. If it they work that will open up and could open up a number of additional locations there. So, really what it says is the technical team sifting through the data said in the wells in the area continuing to generate where we were primarily chasing the (morrow) or morrow sands, they had gone pretty much from a single marrow sand to multiple marrow sands, now we're finding potential -- and the marrow there is 9,000 feet, now potential in the Hunton and Brown Dolomite and by the end of the year I feel pretty confident that we will have a nice Douglas field there, about 5800 feet. So, we're continuing to add horizons, opportunities and at the same time, significantly growing our acreage position. 76,000 new acres in the Mid-Continent is a real nice addition in terms of acreage.

And in terms of the onshore Texas discovery, is that located in the Texas Panhandle/Oklahoma area?

No, that's in East Texas.

Not the -- not the Smith 2, but --

No, that's a new discovery. It's a different well. The A well discovery is down around -- it's in Orange County around Beaumont. The other is in traditional East Texas. I don't know if that helps a lot of people. I want to be -- we have to be a little -- you know, it's a very competitive area, we're still picking up some leases, but it's east of here, east of Dallas/Ft. Worth.

Okay, and then -- and then finally before I jump off, the Northrup play sounds like that's a 2005 test but what kind of potential are we looking at there? And what are the -- what -- how does -- I guess how does it differ from some of your other projects? I'm just not familiar with that play?

Okay, it's a -- it has really big potential. If you remember from some of our presentations, we showed the pyramid of prospects and the top of it at the higher risk, higher potential. The analogy for that, this would be on top of the pyramid. High risk, but high potential. The analogy is offshore Mobile bay that will have gross ultimate recovery on the order of 7 Tcf or so. And the key part about that play is those wells average about 50 Bcf a well. So, they're very big wells. Individual wells will be 50 Bcf per well. The guy who generated and had a lot of success in the offshore is the guy who generated this prospect and its onshore it has a very unique seismic signature and character to it and it's just in an area where it's untested. It is deep, it is below 20,000 feet. But drilling in Mississippi, given the pressures and temperatures there, it is a fairly inexpensive deep well if you want to look at it that way. We will have 25% of the project. If it's successful, we've identified a number of these things with the growth reserves could be well in excess of a 0.5 to 1Tcf gross or more, just from the Northwood. We will have 25% of that project. That gives you a feel for what the upside could be. If it the first couple of wells are successful, then the chance of success will go way up. You know, we know the signature, where to look and identified a number of them. It's a very exciting play.

And one more before I jump off. Just related to that. What kind of cost would those wells have, then? Obviously --

You're looking at, you know, those wells -- initial wells will probably be 22, 23,000 feet. Your dry hole cost on that will probably be a little under $4 million, but rounded off to $4 million dry hole, 25% of it is so our exposure on the first dry hole will be $1 million.

And --

A million dollar exposure and gross reserve potential of a half Tcf or beyond, of which we will have 25%.

Okay, I will give guys a chance. I will come back. Thanks.

Your next question comes from the line of Jack Aydin of Keybanc Capital Markets.

Hi, guys.

Hi, Jack.

Jeff, you didn't talk on the -- you didn't say anything on Woodbine. Did rename that well differently?

Yeah, I think we're trying to be a little -- calling it East Texas. That's what it is.

Okay.

Trying to be a little coy there. It's the East Texas stuff.

Okay. Now, the second question, second question: The 76,000 acre joint venture, what is involved? What's your share? What is your commitment? And, you know, a little bit more color on that acreage?

The work on that acreage in general, our working interest varies. It probably averages in the 60 to 70% working interest. The commitments are fairly light. I don't want to get into the specifics and really they're with two different transactions and neither company really wants us to mention their names for various reasons, but it's high quality acreage. They're in stack-pay areas, areas with very good track records. The drilling depths are very reasonable. It's low risk drilling. We think the economics are good. All the locations we have were already identified. I think as we continue to work the acreage we will generate new opportunities, plus offsets to the wells that we're drilling. So, it's right in and amongst the core areas that we're currently operating in. I'm really excited about both of them.

What was the cost per well? And how deep and what kind of reserve?

The cost per wells will vary probably from $800,000 to $1.2 million per well, you know, rough kind of numbers. I think you're looking the finding costs on those will probably be, you know, in the $1.00 to $1.50 range, depending on the well .

Potential reserve?

You could back calculate it from the cost. You could sort of back into that with the numbers I gave you. But if you think of Watonga Chickoshee and our panhandle area into Texas, this acreage I -- if we had picture phones and if I could show you a map for next time you come to my office, I will, the acreage, you know, is -- fits hand in glove. If you look at our acreage and the new acreage, it's a great geographic fit, right in our core areas that we're working. If you think of our typical Watonga Chickaohee wells, they'll look just like those.

Thanks a million.

I think the key here is that in some cases we approached these companies. In some cases they approached us. In one case, in the bigger block, it's owned by a much bigger company and they simply weren't working it, they were focused on other areas of the U.S. and of the world, quite frankly and they saw the success we had, our technical people know them. They, you know, they had a got rapport and wanted to work with a company that thought they had good technical staff to get things done quickly. We're going to move rigs out there -- we're moving them as we speak. So, I think it's one of those things where it was a combination we worked very hard on this, this took many, many months to put together. I think it's noteworthy because especially with a big company, they've got, you know, millions of acres. That's one of those things, if we do a good job, hopefully they will continue to do those deals with us and it will be a good deal for them and for us. It's an interesting deal and a testimony to our technical staff up there and what they've been able to do and really, as Jeff said, it really, really spring boards them, we're going to immediately add 2 or 3 more rigs and so I think what you will see throughout '05 is that the production through the Mid-Continent division, which is at about 30 million a day now, which was, you know, four years ago, only 5 million a day, you can see that dramatically increase in '05, which is what we are hoping will happen. The key is just to be disciplined and take it one well at a time and drill it out and see what we get.

Thank you.

Your next question is from Brad Beago, Calyon Securities.

Good afternoon, guys. I guess several of my questions have been answered. Great job going through operations Jeff, one question on operating costs and you hit on this a little bit and just thinking about going forward. If I look at the last four quarters, LOE has gone up about, you know, 2, 3 cents a quarter. Would you continue that trend pretty much going into -- going throughout '05?

Well, I think, Brad, when you start looking at '05, unless the mix of our properties dramatically change, I think we will still stay in that LOE Range of 60 to 65 cents per Mcfe, depending on workovers, et cetera, would probably be the biggest variant to that.

But, you know, as we mentioned, we're trying to keep our rising cost environment, trying to keep our costs down and marginal property sales, John talked about those being high cost properties. I mean those were the highest cost properties we had. Some of those were in the $1.50 to $2.00 type number. So, you know, even though it's a small volume, those will come out and continue to keep the lid on costs.

Yeah, if you look at our -- if you look at our op costs per M in '03 was 63 cents and for '04 we're looking at a yearly rate around 63, 64 cents. So, you know, from our perspective, we think the costs are going to be the same from '03 to '04, except maybe a penny. Looking into '05, I'd expect you'd see some creep. So, between 63, 64, 65 cents I think is a good number, but no reason why they should be going up all that much. Obviously service costs and those things are going up, but we've also got and some of these fields we're drilling, especially in Appalachia, infield drilling and Conger and other things, the costs are coming down with the increased efficiencies. Hopefully the efficiencies with the minor assets continue just to be penny pinchers but will allow us to, you know, keep the costs, you know, in the 65 cents or lower range.

Okay. And just real quick on Appalachia, I think you said you had 10 rigs running today?

Yes.

Is that correct?

Yes.

And if you ran 10 throughout next year, does that equate to your 400 wells?

No, it's -- you know, it's just running, you know, it's -- it's it's just running -- we might get up to 11, 12 rigs, something like that, but it will be trying to run a couple more rigs in the winter time and keeping onto the higher rig count longer.

Okay.

So, it's a -- it is a good stretch goal for those guys but something I think they will achieve.

And -- and I know it's far out, but if you went into 2006, do you think you could accomplish another ramp-up?

Yeah, I think that we can.

Okay. Great. I think that's it for me. Please move the conference call to another day!

Why don't you ask your other clients to do that?

I have! [ Laughter ] All seven of them!

We'll try to be a day earlier next time.

Thanks.

You're welcome.

Thank you.

Your next question is from Ray Deacon of Harris Nesbitt.

Yes, hey, Jeff, are you going to have any activity in the Gulf in the fourth quarter?

Yeah. We have -- we have one well currently drilling and that's the west Cameron well that I mentioned.

Okay. And is that -- is that -- I missed that, is it an exploration well or development?

It's an exploratory well. We have a 33% working interest or dry hole exposure is 1.7 million. If it works it will be, you know, about 40 Bcf. It's 12,400 foot well.

Okay, got it. And, you know, with the -- with the Yegua play and the deep Hunton play, do you see other follow-up opportunities there? Or... Kind of one-off things.

Well, the Hunton play that we just announced that was a success, you know, two and a half to three million a day at 2400 pounds or whatever is about 11,000 feet. It comes back to route. I wouldn't call it deep, sort of intermediate to me. There is follow-up. There will be at least two to three additional offsets to that. I think there is other follow-up. With the Yegua well, we put the first well on-line, it performed very well. We will put the second well on-line. If it continues to perform well, you know, we may have some additional drilling there.

Okay. Got it.

The first well has done great.

Right. Yeah. So, hey, and is there any analogy in Pennsylvania or the surrounding area to the -- to the shale play that you're talking about? Is there any economic production in the area? Or is this, you know, total -- total wildcat --

If terms of if you're talking about Pennsylvania or in the -- the immediate vicinity, no, it's a -- it's a wildcat. It's a high risk opportunity. It's like I said all along, it's high risk, but high potential and fairly inexpensive to test.

Right. Right and what's the key? I mean if the first one doesn't work, does that condemn the play? What are you trying to find? Is it, you know, natural fracturing, you know, absence of water is that set basically it?

Well, you know, there's always various outcomes from -- let me back up, within the shale play, you have a lot of shale in place. It's very low permeability, you know, very poor quality rock, but you have, you know, a known resource with a lot of gas in place. The question is can you get it out commercially? You know, if you go back and look at the Barnett as an analogy, people knew the Barnett was there for a long time truly took gas price coming up and took changes and went from gel fracs to slick water fracs to a certain size to horizontal well. It took a lot of tweaking on the technology side coupled with a high price environment to make it work. And this is a similar to that. You are a shale section, that in a lot of ways looks like the Barnett, but got really poor quality rock. The question is can you make it commercial?

Uh-huh. Okay. Got it. Thank you.

We have --

Just to -- just to hit on what Ray said, I mean question -- and Jeff said, I think the key here is that, again, there's been a lot of penetrations, we know there's gas there. I mean what we're going to be doing, our first test is going to be going in a vertical well and putting a Barnett-style frac on it. So, that will tell us something. I think there will be, like Jeff said, lots of twists and turns on this thing and I think, you know, the good news is there are some other deeper horizons in the area we will be drilling for. We will be able to continue to work on this. I think, you know, we've got visions of doing some horizontal work in it, as well. It's going to take some turns. The good news is, though, again, it's -- it's relatively cheap given the upside potential. We're already in the area, we know there's gas there. So, it's just a question of doing it. I don't think it's something that's going to happen overnight, but again, I think we've got the Barnett to kind of look after, so, it's not completely in the dark, but it's going take some tries and some time and effort but clearly from our perspective worth the -- worth the try.

We are near the end of today's conference. We will go to Ron Mills of Johnson Rice for our final question.

Ray just hit on the shale, but in terms of the activity you've done to date, John, or Jeff, I know first of all you're going to re-enter an old well. Have you all completed that yet? Or have you seen any results that would make you feel positive or negative about the outlook?

The strategy is still the same, Ron, we're going to re-enter an existing well bore that we've got and we're in the process of doing that and as Jeff said, we should have some result fund-raise that in 30 to 60 days, we're going to be fairly quiet about it through the end of the year, as we continue to build our acreage position about it. So, we are -- we are working on it as we speak.

Okay. And then this would probably be for -- for Rodney: The -- the 15 to 20% production that -- that John was eluding to, if you back off kind of the -- the -- the big Great Lakes additions of that 15 to 20%, are you all expecting that your -- your base or organic growth could represent roughly half of that growth? In the acquisition -- providing the rest?

Let me state what I said, is I think that the guidance we're giving you is 15%.

Right.

Which is, you know, 8 or 9% of that will be Great Lakes and then 6 to 7 of that is kind of organic growth. I said I will be disappointed if we don't do better than that and get to 20, which, obviously, is the -- is just the organic side going from 6 you know, 6 up to 10 or 11. So...

Okay, I was frying to get to that 6 to 7% organic is a step up from what you all had been doing of 4 to 5% organic.

Right. I think that comes -- a little bit of that is just optimism comes from, you know, again, you know, from this big 76,000 acre farm because that's pretty -- that's pretty low risk stuff. It's stuff that we're doing -- the -- the increase in the Appalachia is pretty low risk -- pretty predictable stuff that we're talking about. So, I mean those are the kinds of things that we're predicting that growth on. We're not -- I can assure you we're not counting on the shale play or, you know, you know, a big huge refrac program or going crazy in the coal bed methane or Northlan -- we're not counting on that stuff to get us there. Our baseline growth, that's 6 or 7%, 8%, is going to be through the things that we can kind of see very, very clearly. We're not going to get ahead of ourselves.

All righty. Thank you, guys.

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.

Well, thanks. certainly -- we're excited about the quarter. We felt like we kind of hit everything. You know, one thing I will say it was a fairly exciting morning in the market for our stock. I think we opened up going down and hit $14.96 or so, is what Rodney says, now back up a little bit. Just to give you an idea on that, in terms of evaluation, we think we've got a long ways to go. We're trading currently at less than, you know, way less than 4 -- I mean 4 times '05 cash flow and on an EBITDA basis, I mean if you mark-to-market the hedges as debt and as opposed to deducting from EBITDA, we're trading at less than 4 times '05 EBITDA multiples. So, we -- from our perspective, we still think the stock has a ways to go. We will still -- we are all still fully invested personally and we hope that the -- over time the market will give us some credit for some of the things we're doing, but we understand it will take time. With that bit of advertisement, I will -- operator, why don't we close it down.

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