山脈資源 (RRC) 2006 Q1 法說會逐字稿

Welcome to the Range Resources First Quarter Financial Results 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 fact 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.

Thank you, operator. Good afternoon and welcome. Range continues to report record results for the first quarter of 2006 driven by a 12% increase in production and a 46% increase in realized prices over the prior year. More importantly, we continue to focus on the execution of our 2006 plan, which should continue to drive record results for the year.

We are pleased to discuss our results with you today. On the call today with me are John Pinkerton, President and Chief Executive Officer; Jeff Ventura, Executive Vice President and Chief Operating Officer; and Roger Manny, Senior Vice President and Chief Financial Officer.

Before turning the call over to John, I would like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It is now available on the homepage of our website, or you can access it through the SEC's EDGAR system. In addition we have posted on our website supplemental tables which will guide you in the calculation of non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliations of our non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you detailed information of our current hedge position by quarter.

Secondly, Range has mailed its proxy for our 2006 Annual Meeting to be held in Fort Worth on Wednesday, May the 24th. We have two proposals concerning our equity compensation plan, which require each stockholders' vote. Since the brokers do not have the power to vote on these two items on your behalf, we hope you will consider all the proposals carefully and return your proxies as soon as possible. Now, let me turn the call over to John.

Thanks Rodney. Before Roger reviews our first quarter financial results, I'll review some of our key accomplishments for the quarter. Obviously, we're very pleased with first quarter results on a year-over-year basis. Production rose 12.4%, beeting the high end of our guidance. This also marks the 13th consecutive quarter of sequential production growth.

On the drilling side, our drilling program was on schedule throughout the quarter as we drilled 206 wells. We continue to be very pleased with the drilling results and we're generating very attractive rates of return. On the cost side of our business, we continue to experience upward pressure like the rest of the industry. Offsetting this is the fact that our unit cost structure continued to be one of the lowest of our peer group, and Jeff and the operating teams are being very proactive in terms of trying to moderate the impact. Despite the rising costs, our cash margins were up 58% for the quarter from $3.50 per Mcfe in the first quarter of '05 to $5.51 per Mcfe in the first quarter of '06.

As Rodney mentioned, importantly, the rolling off of the lower priced hedges at yearend '05, our first quarter financial results provided, in our view, a clear picture of Range's operating and financial horsepower by posting record production volumes and record financial results. We believe we set the stage to what we believe will be a terrific year for Range and its stockholders.

Lastly, as you'll note from Jeff's discussion, which is coming up, our technical teams are doing an excellent job expanding our drilling inventory and our emerging plays. We have several new plays that are pretty exciting also in the pipeline. When you step back and look at the big picture of Range, we believe we've got a terrific portfolio of projects that's growing and expanding. The upside potential, we believe, is substantially greater today versus one year or two years ago. So we really look forward to the remainder of the year and some of the exciting things we expect to be able to report.

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

Thank you, John. Our first quarter financial results were again the best quarterly results in our Company's history. The key drivers were similar to prior quarters. The continued success of our drilling program, driving up the year-over-year production by 12%, and the rolling off of the lower fixed price gas lots at the end of 2005, which increased our realized price per Mcfe year-over-year by 46%.

Looking at topline growth, quarterly revenues were a record $189 million, 75% higher than last year. Now to place this performance in perspective, net income for the first quarter of 55.4 million was more than double the $22 million figure from last year and exceeded the annual net income for any single year prior to 2005.

As John mentioned, the first quarter of 2006 brought our 13th consecutive quarter of production growth, a testament to the quality of the drilling inventory and the professionals that transformed the inventory into production volume. Our realized price per Mcfe after hedging for the first quarter was $7.62, a 46% increase from the $5.22 per Mcfe figure last year and an increase of $0.81 or 12% from just the fourth quarter.

As was discussed last quarter, due to wider than normal basis differentials during the third and fourth quarters of last year, certain of our natural gas hedges are required to be mark-to-market at quarter end, contributing to a non-cash pre-tax hedging gain of 12.7 million in the first quarter of 2006. Now, no changes were made to the underlying hedges. The income is solely attributable to the change in accounting treatment that's prompted by events essentially outside of our control.

Turning to the cost side of the income statement for a moment. Direct operating cost per Mcfe increased 17% year-over-year from $0.72 last year to $0.84 in the first quarter this year. Work over expenses that are included in this quarterly figures totaled $0.05 per Mcfe for both 2005 and 2006. Production taxes driven by higher oil and gas prices increased 50% from $0.28 per Mcfe to $0.42. However, production taxes are down slightly from the $0.45 figure in the fourth quarter of last year.

G&A expense per Mcfe was $0.41 in the first quarter of '06, $0.09 higher than the first quarter of last year but about the same as the fourth quarter of last year. The G&A expense increase is primarily attributable to 1.5 million in higher employee costs as we increased our headcount from the first quarter of last year to this year by 58 new hires. Higher legal and public company expense also contributed to the G&A increase.

The non-cash stock compensation line now contains two components, $2.8 million in equity award expense associated with the newly effective accounting pronouncement, FAS 123(R), and the previously present non-cash deferred compensation plan mark-to-market expense, which was 4.5 million for the first quarter.

Exploration expense was higher in the first quarter, increasing from 3.2 million last year to 9.5 million this year. Included in the exploration expense this quarter was 4.6 million in seismic expense and 2.7 million in dry hole costs. Exploration expense will vary going forward with seismic expenditures and dry holes, however, we would expect at least 10 million per quarter in exploration expense for the rest of the year.

Higher interest expense reflects both higher interest rates on our short-term floating rate bank debt and also the refinancing of a portion of that bank debt to higher priced long-term fixed rate debt during the first quarter of last year. Now the silver lining to the first quarter cost increase was a modest $0.04 per Mcfe increase in DD&A expense. DD&A expense of course is the most significant expense item on both a unit cost and an absolute cost basis for us.

A cost increases are never a welcome sight, but even as industry wide cost pressure pushed our costs higher, as John mentioned, our cash margins improved 58% from 350 in Mcfe in the first quarter of last year up to $5.51 per Mcfe this year. The modest 578,000 cash income tax expense in the first quarter due to state income taxes. No Federal income taxes were paid or expected as we continue to carry a $207 million Federal NOL carry forward.

Net income for the first quarter of '06 totaled 55.4 million or $0.41 per diluted share. Even after eliminating the hedging gain, net income more than doubled from the first quarter of '05 to '06. Now net income per share for the quarter calculated comparably to analyst's estimates was $0.39 per diluted share, $0.02 over consensus. EBITDAX for the first quarter totaled $138.2 million, a record high, representing a 71% increase over the first quarter of last year, while cash flow increased 76% from 72.6 million in the first quarter of last year to 127.6 million this year. Cash flow per share for the quarter was $0.95, and that compares to analysts' consensus estimate of 92. And as Rodney mentioned earlier in the call full reconciliation of these non-GAAP financial measures are always available on the Range Resources website.

Turning over to the balance sheet, our debt continues to decline while our book equity bills resulting in a reduction in our debt to cap ratio from 47% at year-end '05 to 42% at the end of the first quarter of this year. Total debt declined $23 million from application of cash flow in excess of our capital spending program to debt reduction. Now we're excited to be nearing our goal of achieving a 40% debt to cap ratio. However, we will not place this goal ahead of making economically attractive expenditures as such opportunities may arise.

Earlier this month, we extended the maturity on our bank credit facility by two years to 2011. And we held our borrowing base comps in that 600 million to minimize commitment fees. Now our bankers are telling us that our existing assets base would support a borrowing base of about $1 billion should the company desire to increase the size of the facility. However, we ended the quarter with over 350 million in available committed borrowing capacity under the existing 600 million facility.

Our hedging activity was limited during the first quarter, as a few collars were layered in for '05 and '06 and we now have 98.5 million Mmbtu per day of '07 gas collared at an average floor price of $7.13 and average ceiling price of 999. We've got 55 main Mmbtu of '08 gas volume hedged with an average floor price of 793 and a ceiling price of 11.39.

We added slightly to our hedged oil volumes in '07 in those sales, '08 as well. But again, the big news on the hedging front as John mentioned earlier and that is a significant positive impact of the rolling off of our lower price gas swaps at year-end. For those seeking additional detail, Rodney always keeps a detailed summary of the hedge positions posted out on the website. With moderating commodity prices, cash flow is likely to be less in the second quarter, but still significantly higher on a year-over-year basis. And we believe expenses will continue at their current levels on an Mcfe basis and production will increase throughout the year.

In summary, we were off to a great start in '06 with the first quarter beginning to demonstrate the true financial performance capability of the Company. First quarter results show yet again the power of higher production volumes from the drilling program, combined with higher realized prices. EBITDAX increased 71%, cash flow increased 76% and net income increased 152% over last year. Our expanded and motivated technical teams are working hard to prudently deploy the excess cash flow and to bring online our drilling inventory and prove up our emerging plays.

So John, now I'll turn the call back to you.

Thanks Roger. I'll now turn the call over to Jeff Ventura our Chief Operating Officer to review the exploration, development activities and the status of our capital program.

Thanks John. I'll begin by reviewing production. For the first quarter, production averaged 257 million per day, a 12.4% increase over the first quarter of 2005 and a 2.7% increase over the fourth quarter of 2005. This represents the highest quarterly production rate in the company's history and the 13th consecutive quarter of sequential production growth.

The 257 million per day is comprised of 135 million per day or 52% from the Southwest division, 99 million per day or 39% from the Appalachian division and 23 million per day or 9% from the Gulf Coast division. This increase was mainly due to the success of our drilling program. Approximately 73% of the Company's production was natural gas. I applaud our operating teams for a great job.

I'll now review some of the highlights of each of our divisions. I'll start with the Appalachian division and begin with our properties in Virginia, which are Nora and Haysi. These properties came from our acquisition of Pine Mountain in 2004. The acquisition has turned out extremely well. Production at the time of the acquisition was 14.8 million per day, and today it's currently 23.2 million per day and growing. Specifically, for wells drilled in Nora today the average expected ultimately recovery is about 400 million per well from a depth of about 2,500 feet. Costs on drilling complete is about $310,000.

For the bulk of our wells, our average working interest is 50% our and average net revenue interest is 56.25. Therefore our finding and development costs are less than $0.77 per Mcf and our rate of return is excellent. Haysi wells appear to be similar to Nora expect our working interest there 70% and our revenue interest there 73.75%.

Drilling at Nora and Haysi continue to ramp up with 97 wells drilled in '04, 175 in '05 and 260 planned for '06. Currently, there are about 1,000 producing coalbed methane wells on our acreage. Between Nora and Haysi we believe that we have about 2,700 locations to drill, assuming 60 acres spacing. Of the 2,700 locations, only 624 booked, as proved undeveloped, which lease over 2,100 locations yet to be booked. Given our knowledge of the area, we feel the probability of drilling these wells is very high. Given the quality of the production, and because we own the minerals in the field our finding costs are excellent, and our rates of return are outstanding as well. Our acreage position in this area consists of 287,000 acres.

I'll also given update of our [widen] property in West Virginia. This area contains a 77,000 acre block in which Range has a 100% working interest and a 100% revenue interest and 74,000 of the acres. I mentioned during a previous conference call that a coalbed methane study of the properties has been completed and the analysis was encouraging. We are on track to drill the five well coalbed methane pilot here this summer.

Based on the data we have today, a typical CBM well here could potentially recover about 200 million cubic feet of gas per well from a depth of 1,800 feet. Cost on drilling complete is currently expected to be about 270,000 per well. This equates to about $1.35 per Mcf. Potentially, there could be as many as 1,000 wells to drill, which gives an upside of about 200 Bcf net. I caution that it's still early and we need to drill our pilot project to confirm this analysis.

Our coalbed methane projects in Pennsylvania are also moving forward. We drill 12 wells on our Unity acreage last year and are planning on drilling up to 15 additional wells this year. We're also planning on drilling 15 more wells on our other products in Pennsylvania, which are our Chest Springs, Wilpen and Salem projects. Combined we have 30,400 acres of coalbed methane potential in Pennsylvania.

Moving on to our shallow tight gas sand drilling in Ohio and Pennsylvania, we drilled 445 wells in 2005 versus our original target of 380. This compares to 270 wells that we drilled in 2004. Ramping up the drilling, increases the present value, as well as speeds the conversion of non-producing reserves to producing and unproven reserves to proven. Plans are to drill 479 wells in 2006. So far in 2006, we've drilled 121 wells and are ahead of schedule for the year. We have an inventory of more than 3,300 tight gas sand wells to drill here.

Next, I'll give an update of our shale gas project in Pennsylvania. Our first well, which was a vertical well, came on-line at a peak rate of 800 Mcf per day and it's currently producing about 160 Mcf per day. Although it's still early, reserves for this well appear to be in the 600 million to 900 million cubic foot range base on reservoir stimulation by [Holdage], which is now Schlumberger.

Given the results of this well, we just plugged back one of the wells that we drilled last summer and fracked it with large Barnett Shale fracked as well. Although it is still early in its life, this well also appears to have reserves of 600 million to 900 million cubic feet of gas. After that we also plugged back another well, which was completed deeper last summer and fraced the shale. Although very early in its life, this well looks to be in the same range.

We also just finish fracking our first horizontal shale well and are flowing it back now. We currently have one horizontal rig and one vertical rig drilling. Early in the fourth quarter we'll have the initial production results from 10 vertical and 3 horizontal wells. Given our knowledge of the play, we believe that we currently have 248,000 acres under lease that are perspective for this play. We are continuing to increase our land holdings. And the key part to remember there is for that particular play, one, we get a great gas prices in the area - we're looking at about 35% premium to NYMEX versus lots of other places in the country that are $0.50 to $1 or more deduct.

Second, we have excellent royalties that are typically [eighth] royalty - a lots of the other plays you might be looking at a quarter potentially a third royalty in the hottest of plays. Our land costs are low, on the order of $50 or less per acre for a lot of it. Again versus some of the hottest plays where it's literally $10,000 and up. Plus, we don't have a need for 3D on that particular project. So the project's really in advance state in relative to lot of the other plays when you look at it from that perspective. Also, it's very early, and I mentioned reserves per well were 600 million to 900 million per well. But at this point, of anything it looks like they'll be on the high end of that range. So it's early, but we'll continue to drill and we'll update you as we go throughout the year.

Moving on to the Trenton Black River play, we are planning on [splitting] our first well in Southwest Pennsylvania within two months. Talisman will operate the well, and we'll be 50/50 partners. I'm excited about partnering with Talisman who is the industry leader in the play. And we'll follow up that with Bradford County drilling and completions later this year.

In the Southwest division, Range is continuing its infield drilling and refrac program in the west Fuhrman-Mascho unit in Andrews County, Texas, with continued success. As a result of this redevelopment work, Range has increased production over sevenfold since acquiring the property.

We still have over 100 locations to drill as well as several wells to refrac. Even after all this redevelopment, we estimate that we'll be covering only 10% of the oil in place, which is estimated to be 213 million barrels. We'll be testing down space into 5 acres per well. If successful, we have the potential to double the recovery from this field through a combination of infield drilling and water flooding. We just picked up a second rig for the area.

One county to the west of Fuhrman, our new Eunice properties in southeast New Mexico are also performing well. We originally projected that we could double production on these properties by the end of 2006. We've done that and have increased production from about 7 million per day to over 16 million per day currently. So the team there has just done a great job with that property. We're also actively drilling and having good success on our Conger and Val Verde properties, specifically in Conger we've had good success extending the limits of the field, as well as, re-completing some of the wells at the shallower Wolfcamp formation.

We just recently did a look-back of the acquisition that we did in this area in December of 2003. As a result of the field expansion and re-completion work, the reserves in this acquisition are 42% greater than what we assumed back then. In addition, the cost synergies were there and of course, prices moved in our favor, so outstanding acquisition. And we do look backs like that on all of our deals. And to date, the teams have just done a great job. Moving onto Conger here, there is still a lot of drilling in this year. In particular, we'll drill 25 wells out there.

In East Texas, Range has 15,000 acres of lease holdings with working interest varying from 25% to 50%. And Range also has approximately 30,000 acres of leasehold options. Although, originally started as a Woodbine play, it's evolved into an Austin Chalk play. So far, we have two producing wells from the Chalk at a combined rate of about 11 million per day gross or 3.6 net. The first well reached payout in less than six months, and it's an excellent well. And the third well is only being drilled for the Chalk, and it should come on line this quarter.

In the Texas Panhandle, in the Watonga/Chickasha area of Oklahoma, we've continued our successful drilling. As a result of this success, our net production from the mid-continent for the first quarter was 42 million per day versus 29 million per day last year. We continue to run three rigs in these areas. In addition, we have one rig in Northern Oklahoma and one in Southern Oklahoma.

In Northern Oklahoma, we have a shallow drilling project that appears to have significant running room. So far we've drilled 34 wells and are pleased with the results. Typical wells are about 2,700 feet deep and cost about $350,000 gross to develop about 250 million cubic feet equivalent gross of reserves. We've identified about 200 potential drilling locations on our acreage with additional upside beyond that. We operate and have a 65% working interest in most of the wells there.

In Southern Oklahoma, our deep 23,000 foot exploratory well has reached total depth and was logged. This well logged over 150 feet of pay in Mississippi and in Pennsylvanian age rocks, primarily in the Springer and Morrow sands. We have a 16% working interest in the first well. We have 12,000 acres in the play. Our working interest in this position averages about 37%. We'll start our first company-operated well this week, and our interest will be 72% in this 20,500 foot development well.

I'm also excited about the shale projects that we've initiated in this division, in particularly the Barnett Shale play that we have in the Fort Worth basin. We current have about 16,000 acres under lease and are actively negotiating on other significant acreage positions. We believe the gas in place and recoverable gas will be similar to the core area in the Barnett. Our plans are to shoot 3-D seismic this summer and to begin drilling late in the third quarter.

We also have 20,000 acres in Reeves and Culbertson Counties in West Texas. We believe this acreage is prospective for the Barnett Shale, Woodford Shale, Fusselman and Wolfcamp formations. We plan on shooting 3-D here in the second quarter and drilling late this year or early next quarter.

Gulf Coast division will spud its high potential Norphlet well in June and will have a 25% working interest in the well. And again, it's an exciting project, a lot of repeatability if it works and potentially could be net 250 bcf or more. And on a project like that, 250 Bs, the net rate stuff could be 150 to 200 million per day. So it's an exciting project. Should be drilled throughout this year and we should have results early next year.

In summary, we're in great shape to achieve double-digit production growth for 2006. 2006 will be an excellent year for Range. And I'm excited and focused on the future. Range now has a proved reserve base of 1.4 Tcf of solid long-life properties. Our reserve life is 15 years. And in addition to that, our drilling inventory consists of over 7,700 locations that equate to 1.9 Tcf of net unrisk reserves, of which 74% or 1.4 Tcf is unbooked. This is a large multi-year inventory of projects that consists mostly of low-risk, highly-repeatable development projects, complimented with several higher risk, high-potential explorations projects.

In addition to that, Range also has more than 2 Tcf of net unrisk reserve potential in its emerging plays. These are primarily technically driven resource plays involving shale gas and coal bed methane opportunities within our existing core areas. So in total, we have 1.4 Tcf of proved reserves, 1.4 Tcf of net unrisk reserves in our drilling inventory and more than 2 Tcf of net unrisk reserves in emerging plays. Importantly, we're not depending on one or two projects for our future growth. Having a large high-quality drilling inventory is a real key in my mind.

One of the key strengths of Range is its portfolio. The other is its people. This is led by a technical team that now consists of a total of 96 geologists, geophysicists, engineers and land men. It's a talented group, who is now responsible for all the projects that I have just mentioned and are continuing to generate attractive new opportunities.

The company today is significantly different than it was a year ago. With our 20% reserve growth last year, we now have over 1.4 Tcf of proved reserves. Importantly, the reserves that we've added are long-life, low-decline rate and very predictable reserves. As a result, we now have a larger, more stable proved reserve base. We also have more upside with greater than 3.4 Tcf of net unrisk reserve potential.

As I've said before, it's a fairly simple business. The key is to grow production in reserves with good [finding] and lift costs and to build and high-grade our inventory. We'll stay focused on that. I feel confident that with our technical staff, large drilling inventory and 3 million acre leasehold position, we're well-positioned to continue to add significant value. Back to you, John.

Thanks, Jeff. Terrific report. Looking to the remainder of '06, we still -- let's take a look, we still continue to see strong operating and financial results. We're looking for second quarter production to come in at approximately 259 to 262 million a day, representing a 12% to 13% increase year-over-year. Assuming current futures prices and the hedge is in place, we anticipate second quarter realizations after hedging to be in the $6 to $6.20 per Mcfe range. This is $0.40 to $0.60 higher than the $5.60 per Mcf that we realized in the second quarter of '05.

We again anticipate production revenues, cash flow and earnings will be substantially higher than the prior year period. In our view, the second quarter of '06, on a year-over-year basis, like that of the first quarter, will be important and that those results will continue to demonstrate solid quarter-over-quarter execution of our business plan.

It starts with production, which as I previously mentioned, is anticipated to rise 12% to 13% through the drill bit. Second, realized prices with the rolling off of the lower price swaps at year-end '05 are estimated to increase 7% to 11%. As a result, revenues are projected to increase roughly 25% over the prior-year period. On the other hand, expenses are anticipated to rise at less than half the rate of revenues on a year-over-year basis.

On a per unit of production, second quarter '06 expenses are anticipated to be in line with first quarter '06 results. The interesting thing when you look beyond the second quarter - we're really excited. We anticipate production to continue to increase in the third and fourth quarters. And it really centers around our drilling program where we've got 1,065 wells budgeted for the year. And if I were a betting man, I would guess that we'd probably drill a few more than that.

Based on first quarter results, we're well on our way to achieving solid double-digit production growth for yet another year. For the year, cash flow from operations and earnings per share are anticipated to increase by over 30% to 35% versus '05. So you can see '06 shapes up to be just a tremendous year for the Company and our shareholders.

In summary, we think one of the key aspects to the quarter or to our business is the quarter-over-quarter execution of business plan. As we've mentioned, we've had 13 consecutive quarters of sequential production growth and that's from really the drilling inventory that Jeff mentioned and some of these lower-risk projects. Obviously, we're hopeful that exploration discoveries occur and that attractive acquisitions will be completed, but we do not need either of these elements to achieve our '06 goals. Executing the plan, just drilling up our drilling program will add significant shareholder value in its own right. if we look at the exploration successes our acquisitions kind of to be the -- like the icing on the cake so to speak.

We're focused on getting our wells drilled and hitting our quarter production targets, as Jeff mentioned, we also continue to expand our drilling inventory. We made really solid progress with some of our emerging plays, which are very exciting. I'll double what Jeff said in terms of our technical teams - they're doing a terrific job and they're adding a number of really high-quality projects.

As Jeff, like he always says it's a pretty simple business. But really over the long term when it might come down to it, we believe shareholder value is really determined by the degree of success that we have in generating attractive returns to the wise investment of our cashflow and capital. The efforts of the technical teams is obviously very critical to the process. Again, as Jeff mentioned, at Range, we have got a very high-quality teams that are generating very attractive opportunities.

Today, we have over 7,700 projects comprised of a very large number of lower risk development exploration projects and a diversified group of higher potential exploration projects as well. From our perspective, we think Range is unique and that for our size, we have a very large transparent drilling inventory and an even larger 3 million gross acre leasehold position. And we've worked very hard at building and maintaining our quartile top cost structure and expanding our drilling inventory really to drive a long-term growth in profitability.

The last thing I'd like to talk about is really something that we look at periodically, and that is our overall production curve. Today, Range produces as Jeff mentioned, roughly 100 million a day from the Permian division, 100 million a day from the Appalachian division, 34 million a day from mid continent and 23 million a day from the Gulf Coast division. If you look back about two years ago, the Gulf Coast division was producing roughly 25 million a day higher than that is today. With our de-focusing of the offshore, we've essentially -- what we've essentially done is replace the 25 million a day that we've lost in the shallow waters of the Gulf of Mexico with 25 million a day of CBM production. Therefore we've replaced price declines Gulf of Mexico production with very long life shallow decline CBM production. The result is that we've materially flattened our overall decline curve.

So interestingly enough as we've grown larger over the last several years, we've actually flattened our decline curve and actually slowed what we call the squirrel cage. Importantly, we've accomplished this while still achieving the 13 consecutive quarters of production growth. Given the flatter decline curve in our expanding drilling inventory, our confidence that we can continue to post double-digit production growth for many years to come has really strengthened substantially.

As we all like to say around here, it's all about growing production reserves at top quartile finding costs. Although -- and Jeff likes to say it's simple, it's obviously very hard to execute. But we have got a great team and they're doing a great job. With that operator, I think that's all for prepared remarks. Why don't we turn the call over to questions and answers?

Thank you Mr. Pinkerton. [OPERATOR INSTRUCTIONS] Your first question comes from Rehan Rashid of FBR.

Afternoon Jeff. [Last coming] months, you talked about possibly doubling the recovery rate. I'm not seeing --

Hello? Rehan, where are you?

I'm here. Can you hear me?

Operator, I think we've lost Rehan.

Your next question comes from Leo Mariani of Jefferies and Co.

Good Afternoon. A few questions about some of your plays here. I was hoping to get a little bit more information on your unity.

It appears there's a problem hooking the people asking questions to the call. We can't hear them.

Okay. Your next question comes from Larry Busnardo of Petrie Parkman.

Can you hear me?

Yes.

Okay.

Congratulations Larry.

Yes. Made it through. That's good.

One out of three.

The question I have is on the Pennsylvania shale play. You were talking you have 248,000 acres there, is that correct?

Correct.

And where do you think the spacing is going to be? I know it's early in the play, but are you thinking this is 160 going down to 80 or how do you kind of see this, is it too early to tell?

Well, I'll say a couple of things. One it's too early to tell. And you have the issue of can we get it to work and if so, will that be with vertical wells or horizontal wells? I feel pretty confident with vertical wells. You could drill that on 80 acre spacing, which would 3,100 wells.

Right.

So it has tremendous upside and if we're close to the high end of the range I mentioned you can punch those numbers out for yourself, and you're going to calculate a pretty big number. And I think in time, one thing we know about shale play is you're looking at they really low permeability with shale. So if anything, 80 may become 40 or it could be lighter. That's clearly what we're seeing in the Barnett and in that kind of tight rock or even in tight sandstone they end up developing on typically 40 acres or in some cases less.

What's your working interest in that play?

100%.

So that's 100% there. So you potentially can have a couple of Tcf of potential there?

Correct. Just from the shale play.

Just from the shale.

Just on that one shale play.

Right.

If it works that's true.

So that would be more -- given the numbers that you gave in terms of the upside?

Yes. Rodney teases me all the time. If you look on our charts, it says 2 Tcf two plus Tcf. So if we actually go through like we are now in quantify all of them, you'll see the number can be a lot bigger. But I prefer to be cautious, to invest prudently, and to relay the information to you as we learn it. But the upside is that plus is a big number when you go through and calculate it.

How many wells planned for this year?

In that particular play right there, we want to have a total -- our plan is to look at 10 vertical and three horizontal wells, look at the performance of those wells and then determine where we go from there.

Determine which course of action then heading into next year whether you go more vertical or if you go horizontal?

Yes. Or stay where we are that's correct. Okay, half of the infrastructure in the area obviously, fairly knew about me but are the pipelines or would there be any problems in getting this hooked up in getting production out of there if you go to an expanded program next year how much work would need to be done to expand that out?

The good news is you are in pretty reasonable proximity to lots of major pipelines. We have capacity in the line we have and we can grow and expand that. So that -- and again we're looking at a $0.35 premium to NYMEX as well. So it's a good place to do business, and that I don't see as a problem.

Okay. And I'll be clear we're going to delay build out the infrastructure but they were in a good area to do that.

Shifting over to South Oklahoma and deep well there. What was the formation that was being targeted?

The target was it was really a stacked pay area that we were looking at multiple potential targets in [Myer], Springer, Mississippian and down to the Devonian even. And based on the press release that we put out, we believe we have on the order of 150 feet of pay, primarily in the Pennsylvanian and Mississippian aged sands. But it's an exciting area. It really has a lot of upside force and particularly those can be higher rate wells.

In the same vicinity, Marathon recently completed a well for 20 million per day at 8,600 pounds. So you're in a good area, we think. If that works out that we could have 20 or 40 potential wells out there. And our average working interest there will average 37%. Those are, if you look at the [year-on] trend with some of the Elk City kind of stuff, those wells can be on the order of 10 bcf a well with the better wells top side being potentially 20 bcf or more per well.

Okay. And then lastly just Norphlet, have you disclosed who the partner is on that well?

No.

Okay. Thanks. That's all I got.

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

Rehan, you only get one question.

I know, I know, and I thought I said great quarter to start off with, despite that I got disconnected there. But anyways, [firm in Moscow], Jeff could you talk about how do we kind of double the - I'm not sure if I heard you correctly or not, I think you were saying you could possibly double recovery rates there?

Yes, and the neat part about firm in Moscow - 460,000 foot St. Andrews field, 230 million barrels of oil in place, so you got a big with it that's the field where we've had such great growth and we've this year-on-year gas investor for best field rejuvenation in the US this year whatever the category is.

Sure,

But that's all that's with all the great work with we've done and that dramatic increase in production and that's through basically drilling and re-drilling and refracing, we're only going to get 10% of the oil in place. If we can continue to down space successfully, and if we can successfully water flood the St. Andrews there we think we could get recovery up on the order of another 10%. So if you take $213 million barrels, another 10% is a little over 21 million barrels, and then, so you got -- we're looking at potentially a big target converted to Bcf equivalent -- it's a 127 equivalent made it back it could be on the order by 100 Bcf net of outside to us if that works.

I understood but in just in terms of timing, when is the end of next year kind of down the water flood, or down the infield drilling--

We'll test the infield drilling throughout the summer, so we'll know pretty quickly, I think, what some of the initial results are like, and then engineers and technical teams always like to watch the performance on. But I think we'll have a real good handle probably by the fall or -- in that timeframe what infield drilling does and if that works, that literally, you could double the number of wells out there. And flooding, we have the water going into the ground. We're continuing to expand that, and hopefully, by the end of this year, we'll have a better feel for that as well.

By the end of this year we'll have a feel for that 100 Bcf and change

Yes. And then you -- and then you have the option of how do you want to book it and then that kind of thing and the timing of the booking.

Okay. No problem. Thank you.

But they're excellent rates of return. Of course, it's strip pricing, your rates of return are over 100% on drilling those wells pretty reasonable finding costs. And even other we pressure test all of our economics as well with the $30 flat oil price and a $5 flat gas price and they still look good even at a flat $30 oil price

Got you. The dry hole cost on that 20,000 foot well -- the one that you are gong to operate

The dry hole cost on that growth would be on the order of $9.5 million at 72% net to us it would be about $6.8 million.

Got you. And the Norphlett well what do you see and say the TD was going to be when sometime next year.

That well - yes TD should be probably or -- end of this year or early next year. So by the time we drill it and then if we're fortunate and successful and you complete it and test it, it'll be first quarter probably.

And then 3 D done and evaluated everything or?

Yes 3 D is done it's evaluated We literally see on the 3-D gross about a Tcf or more than a Tcf of what we think could be recoverable gas if it works. - again looking at our pyramid, that probably is the highest risk thing we're doing, but it has the lot of potential and if the works also we think that, that trend will continue offset 3 d, and really had a lot of running room to it.

Any well control in the area, or --

Very little. It is basically untested. That analogy is Mobile bay off shore that field will ultimately make five or seven Tcf of gas. And the average wells there are on the order of 50 Bcf per well. So they're very prolific big wells. But it is just that, on shore just hadn't been tested. Interestingly up the guy that generated the project worked for one of the big majors, the majors that developed their offshore stuff for Amoco, Shell Mobil, he worked for one of those majors, so it's a guy who knows the play and who knows the area and has a track record in it.

Got you. I'll yield the floor for now and come back later. Thanks.

Your next question is from Leo Mariani of Jefferies & Company.

Good afternoon. Just a few questions on your CBM wells here in the Unity area. Do you guys have any of those wells on stream at this point of time or --?

There is a number of wells on stream, on the order of 15 or so. They're shallow wells, they're -- 1,500 to 1,800 feet deep. They are - reserves we think will be on the order of 170 million cubic foot per well. They're low rate, long life very low decline rate CBM wells.

Okay. What -- do you have any approximate well costs on those wells?

Yes. Those wells are going to cost, on the order of, for a 1,700 foot well out there drilling complete you're going to be looking out probably $200,000 to $225,000 per well something like that.

Okay. Just jumping back over to your vertical shale wells there in Appalachia. When did you first bring the first well on stream over here? Just trying to get a sense of how long it's been online?

It's been online like 100 a little over 140 days -- 144 days something like that. Again yet, technical guys are, you like long term history we like to see, by the end of the year, we'll have little over a year's production on the first well. And obviously what we're doing is comparing the production of these wells versus simulations based on all the data that we have, and then we're comparing actual production back to the simulation.

Okay. Has the decline rate flattened out there on that first well?

It looks at this point it looks reasonably flat. That's why I'll say, we threw out a range, but where we are today, it looks like its towrds the high side of the rage. But by the end of the year, obviously instead of 144 days, we'll have little, 370 or 380 days worth of production. And the longer more time you have, the more confidence you're going to have in that prediction.

Sure. Okay. And I think you have two other wells that are also onstream in that play, just want to get a sense of when those came on if you saw sort of a similar performance in terms of type curve thus far?

Yes. They're all right in the slot, they're all in the same slot.

Yes, those two -- this is John -- those two wells have been on for roughly half the time of the first well. So there is less data, but again just, three wells don't make a statistical analysis. So that's why we're as fast as we can prudently can growing these, these 10 well and the 13, I mean 3, horizontal well so we can gain, we're trying to gain data as fast as we can, so we can make decisions because we're buying acreage out there each and everyday and expanding the play. So we're really working hard.

It's one of the things that we're most focused terms of getting after it in terms of, just focused within the organization, because it's as Larry figured out it has huge upside, like all the shale plays, it just going to take a lot, our caution people, that to be cautious here. I think Jeff mentioned that in his comments in terms of what we put on the slides is that -- it's going to take us a while. It took 13 years to figure out the Barnett. We're hopefully going to figure this out in two or three years. But -- and we're more than -- we're right long. But it's encouraging, but just -- I caution everybody, just be a little cautious here and let's see what happens. But that being said, we're -- it's obviously, extraordinarily material to us.

And I don't want to lose track either. I'm really excited. That's a great opportunity. The good news is we have a big portfolio of lots of good things. And another one not to lose track of an emerging plays is that of Barnett play in the Fort Worth Basin. There we're just trying to expand really the existing plays. You're in a proven play, you're trying to push the boundaries a little bit. For the people that showed up at our analyst day presentation, we gave the justification on why we feel pretty good about being able to do that.

With the acreage we currently have in hand, you're looking at potentially big reserves on the order of 600 Bcf or so just from our Fort Worth Basin play. And we're actively leasing as we speak. So we're 16,000 acres, but that number is going to continue to grow. So that's a proven play. I'm excited about that. We'll be drilling a well in the third quarter. By the end of the year there, we'll have some -- we should have some pretty interesting result, quite frankly. And I'm really excited about the play. Again, we've got a strong technical team. That particular team is led by Mark Whitley, who knows as much or more about the Shale -- Barnett Shale than anyone. So -- and Mark's excited about it as well.

And -- just to hit on them, because they're important, the deep play that we have in Oklahoma is pretty exciting as well. We should have our first well online within about six weeks. We'll have our first company-operated wells by this week, and we should have our -- probably, we have a second rig out there literally about 30 days after that. And I know I'm taking up a lot of time, but talking about big upside to our company, but it's an extremely low risk is Nora field.

There -- and we've talked about in our presentation several time, you got on the order of what we said is 450 Bcf met us at finding cost under $1 that I think has an extremely high probability of occurring. And then, beyond that, if we end up down spacing or end up doing a lot of other things that we can do up there, get a little bit better recovery factor, et cetera, et cetera, that number could double. So there's lots of ways to win within Range.

Okay. What is your working interest in your 16,000 acres on the Fort Worth Basin, Barnett play that?

100%.

Okay. Just one last question totally unrelated here. I guess you guys mentioned your NOL position of about $2 million. Am I correct in assuming that you guys will probably be a cash tax payer sometime, probably, early to mid second quarter here?

No. But we may have a little bit of cash taxes in one of the states we operate in where we're relatively new to the states, don't have any carry forward. But we will not be a federal taxpayer this year.

Okay. I was talking about 2007.

If you look at the drilling program, Leo, and you look at the IDC deduction because of our organic growth that has a tremendous impact on reducing your taxability of your program. A lot of the companies that are paying a lot of cash taxes didn't start out with a NOL and are more acquisition driven. But the IDC alone extends that out for four or five years.

Okay.

Yes, Leo. It's going to be -- this is John -- it is going to be several years before we're going to have start paying cash federal taxes.

Okay. Well, that's certainly good news.

Yes.

I appreciate all the answers to my questions here. Thanks a lot, guys.

You're welcome.

Thank you.

Your next question comes from Marshall Carver of Pickering Energy.

Yes. Most of my questions have been answered. But did have a couple more questions. Do you have any rates that you can talk about for that first horizontal well in Appalachia or and if not, when could we expect some rates there?

Yes. We're still flowing that well back and again, once we get, just like we have with the other vertical wells, when we're at a point to talk about it, and we'll talk about it. But right now, it's a little too early.

And on the realized prices, you mentioned $6 to $6.20, I think that was realized prices after hedging for the second quarter. What NYMEX assumption was that based on?

That's looking at a NYMEX assumption that will be somewhere around 680 to 720 NYMEX.

Okay. That's it for me. Thank you very much. Good quarter.

Thank you.

Thank you.

Your next question is from [Sai Cummings] of Johnson Rice.

Hey guys. Jeff, quick question about the Pennsylvania shale. I was looking at your reserve output chart they are in the 4.8 [TEs ]of total potential, of which 2 TEs is coming from as emerging plays. Obviously, just doing the math on that 80 acres, exceed that level from that standpoint. Can you break out, what you guys were estimating the Pennsylvania shale's reserve outlook to be?

When we were saying two Ts, it was a Tcf of that it would have, and we did that a long time ago, and we just have an updated again, just to put the air on the conservative to be prudent. And you can calculate some pretty big numbers, and we're excited and that upside certainly exists.

And then moving to southern Oklahoma the [Depontin] well, have you had a prior reserve estimate?

We had talked about, I think in one of the calls that reserves could be in the 250 Bcf range, plus or minus. And I think it's still in that slot. It's very early, but it's so far it's encouraging, and we'll just need more wells to continue to develop. But it has reserve, I think in that 250-300 Bcf range potential further - those are gross by the way.

Okay. Great. And then...

And again, the other thing to remember with that is, unlike CBM or unlike a shale play, when you net all that back to us, it could be on the order of 100 Bcf net, but the rate it could go with 100 Bcf net, maybe on the order of 80 million a day net or sort to us. So it could be real nice great growth over the next two or three years.

And then lastly, in the Norphlet, have you guys identified the number of potential locations that you could drill in that area?

Yes. And - we've only quantified it in terms of a reserved number, but it's greater than Tcf growth, and that does about 250 Bcf. And to punch into, we are saying an average well could be 50 Bcf per well. So you can divide it out.

Okay. Great.

But if it works, it has around -- it's not going to -- the play doesn't stop on our 3-D. It will expand beyond that, if it works.

Great. Thank guys.

Good. Just to make sure everyone is aware, of all the things we're doing, that has the highest risk, in terms of probability of success, in terms of drilling. But again, I think the key, like all the projects that we focus on, we try to do things that, if they work, they're repeatable. So I think, although it's high risk, if it works, it should be repeatable. But I'd caution everybody there. It is high risk.

We are nearing the end of today's conference. We will go to John White of Natexis Bleichroeder for our last question.

Congratulations on your results, and good afternoon. Back to the Devonian shale, a couple of more items -- completed well costs on the vertical, and horizontal wells and, how long does it take to drill each type of well?

We really haven't released that, and probably not going to, at this point we still got science in there, but the good news is I will let you back into it, again a little bit by throwing some parameters around. I think if we end up toward the high range, of -- on the order of 800 or 900 Mcf per well, once we get into a development mode, I think that you could be in the development cost, on order of $1.60 or something like that, and with the reasonable flat gas price they're generate us a pretty good rate of return.

But it's early, like John said, we've got three vertical wells, you'd like to have all 13 wells, and be looking at them, and grow and expand from there, but the numbers can work and again just quickly talk about F&D cost but importantly $0.35 premium to NYMEX and by not having 3-D with land costs, and filling and everything, you can generate some pretty reasonable F&D cost and reasonable rates of return.

One other point on that is that is that's out of the shell, we are also in areas we operate a lot, and we have found other pays in those areas, so there's some facts pay potential on that acreage beyond the shell both from the south east wells to blow the shells, so it's some good upside on some of the horizon.

It looks very encouraging right now, and let's say you are happy with the 13 wells in December. How many rigs do you think you could muster, and how many wells would you plan on drilling in 2007?

The real key to that is, whether we believe it's a horizontal play or vertical play, which is really one of the things that when the process of doing, as Jeff mentioned we drilled. Three vertical wells so far they are on production, we got our first horizontal well drilled caged and completed. I am distracted, now we are flowing back.

We actually got another horizontal well that we drilled and the pipes in the whole, and then we got another third horizontal well in the process of starting. So we are moving along pretty quickly there, but until we know that, what kind of play it is, that will tell us what we do. If it is a vertical play, we can go pretty quickly as if not that deep when it is vertical, it's relatively easy. It's a horizontal play then that will be little bit more difficult, after this there are not that many top drive rigs in the basin, and we will have to get a few, Again that's a high-grade problem, and we will worry about that, at the end of the year.

We typically work on our budgets, in the August, September, October timeframe, so that the good news is the results if they come out will help us like that come up with a by the end of the year with pretty good plan, but it's early now.

Do it all this real exciting. Thank you.

Thank you, John.

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

Thank you all, obviously we are glad to put the first quarter on the board, where to go from 150 to 167 million a day, from fourth quarter to first quarter. I mean 257 versus 250 at the end of the year sequential. It's terrific Jeff and the team have done to continues to do this marvelous job, they amaze me it seems like every quarter. But I think it just shows the depth and talent of the team.

As Jeff mentioned we've got a number of new things that we're working on. The little [Tank well] play that Jeff mentioned in Oklahoma. The Southern Oklahoma deeper play. So we've got some really exciting things, and they continue to do things that -- the greatest thing is from -- being a Chief Executive of this company you actually get to turn a number of projects down. So we are not drilling everything, we are actually turning quite a few things down. And we get to pick and choose, which is a great environment to be in. But again, thank you all for being on the call today. And we look forward to great results in the second quarter as well. Thank you very much.

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