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Rex Energy Corp. (NASDAQ:REXX)

Q3 2009 Earnings Call

November 6, 2009 10:00 am ET

Executives

Benjamin Hulburt - CEO

Tom Stabley - CFO

Analysts

Leo Mariani - RBC Investments

Jeff Hayden - Rodman & Renshaw

Mike Scialla - Thomas Weisel Partners

Derrick Whitfield - Canaccord Adams

Richard Rossi - Wunderlich Securities

Don Crist - Johnson Rice

Raymond Deacon - Pritchard Capital

Brian Lively - Tudor, Pickering, Holt

Marshall Carver - Capital One Southcoast

Jack Aydin - KeyBanc

Operator

Good morning and welcome to Rex Energy Corporation's Third Quarter of 2009 Conference Call. I would be your coordinator for today. At this time, all participants are in a listen-only mode.

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. We will conduct a question-and-answer session toward the end of this conference call. As a reminder, this conference is being recorded for replay purposes.

Now, I would like to turn the call over to Mr. Benjamin Hulburt, President and Chief Executive Officer of Rex Energy Corporation. Please go ahead sir.

Benjamin Hulburt

Thank you. Good morning, and welcome to Rex Energy Corporation's conference call to discuss results from the third quarter of 2009. I'm here with Tom Stabley, our Chief Financial Officer. We'll be using a different format today than we've done in the past. We are incorporating slides with the call this morning, and both Tom and I are here to answer questions following the presentation.

For those of you who have dialed-in I encourage you to access those slides now, if you can, on the Rex Energy website in the Events and Presentation section, under the Investor Relations tab. If you are listening in via the webcast, you will see those slides in the webcast window.

We issued our third quarter earnings announcement after the market closed yesterday. Please do take some time to review it, as it contains important information on forward-looking statements, as well as financial statements in non-GAAP reconciliations.

I will be starting the presentation this morning on slide three. This was a solid quarter for the company on the financial and production side. Our production was up. Our expenses were down and our debt level remained flat at very modest amounts.

Our natural gas production, where we invested the majority of our capital during the first half of the year, was up 29%, quarter-over-quarter and 62% from the same period in 2008, as a result of our continued Marcellus Shale drilling.

Our operating expenses were up slightly from the previous quarter, remained well below levels seen in the same period last year. Our G&A expenses declined from both the last quarter and the same quarter last year.

Operationally, in the Marcellus, after testing different drilling and completion methods on our first two wells, our third horizontal well in West Westmoreland County, Pennsylvania, tested at an average rate of 4.2 million cubic feet per day of natural gas, over a 30-day period.

On the oil side, we drilled 19 new wells during the quarter, which we expect to continue to bring online during the fourth quarter.

Looking forward into 2010, we believe that our strong balance sheet with only 5% debt to market cap, and our $26 million carry balance on two of our Marcellus Shale operating areas, and our aggressive hedging positions, will allow us to double the pace of both our Marcellus Shale and conventional oil well drilling projects.

Turning to slide four, to take a closer look at our production trends, during 2008, due predominantly to higher oil prices and the earlier nature of the Marcellus Shale projects at the time, we focused on growing our oil production through developmental drilling in Illinois basin, which caused our oil production to rise steadily each quarter during 2008. Beginning in late 2008 and early 2009, with a precipitous drop in oil prices, we shifted gears, ceased our developmental oil well drilling and focused on cutting costs, reducing debt and commencing horizontal Marcellus Shale drilling. We are now beginning to see the significant growth in our natural gas production as evidenced by the 62% increase in gas production over the same period last year and the 29% increase over the last quarter.

Unfortunately, for the last two quarters, much of our conventional gas production has been shut in due to third party line maintenance. Had this production been online, our natural gas production would have been approximately 17% higher this quarter, and our overall production would have been approximately 5% higher.

I am pleased to report that the third party line has been repaired and our shut-in production was brought back online last week. We are currently running three rigs in the Marcellus Shale operations, one vertical rig and two horizontal rigs. So the trend in significant increases in our natural gas production each quarter is one we expect to continue.

Now that we're seeing much higher oil prices, we have restarted our oil developmental drilling projects and are moving as fast as prudently possible on our tertiary recovery projects in the Illinois basin. We've recently drilled 19 new conventional wells, nine of which have been activated so far. We expect to continue activating the remainder of the wells in the fourth quarter as we continue drilling additional wells through the end of the year. We expect that these efforts will soon begin to show a return to the trend of increasing oil production.

On slide five, we have presented our daily production and commodity pricing, quarter-by-quarter, through 2009. During the third quarter, we realized a net oil price of $64.77 per barrel before the effects of cash settled derivatives, which slightly decreased our net effective price per barrel to $63.06, representing an increase of approximately 5% over the previous quarter, but still 24% below the same period in 2008.

For the third quarter, we realized natural gas prices of $3.64 per Mcf, before the effects of cash settled derivatives, which increased our effective price by $2.69 per Mcf, or 74% to $6.33 per Mcf. This represented a slight decrease of 2% from the previous quarter, and a decrease of 31% from the same period in 2008.

Turning to slide six, which represents our current oil and gas hedging instruments, as you can see, we continue to maintain an aggressive hedging position, especially on the natural gas side for the next 24 to 36 months. Since the last quarter we have continued to add, to our positions, on both oil and gas.

On the natural gas side, we have added additional volumes in each of 2010, 2011 and 2012, which at first blush, appears to significantly exceed our current production. However, I would point out that the percentages of production, you see shown here, are a percentage of our September production and do not reflect the recent wells we've completed and put into line.

We are very happy with our current natural gas positions, which looking into 2010, provide us with a floor of $6.38 per Mcf on our current production, while not capping our upside until the prices rise above $9.15 per Mcf. Looking into 2011, our floor is a bit higher at $6.62 per Mcf, and we've been able to improve our upside potential by setting a ceiling at $11.03 per Mcf.

Given the high stores levels for natural gas, we plan on continuing to maintain an aggressive hedging position for the near-term, as we continue to bring on more Marcellus wells.

On the oil side, we've begun to layer in additional hedges in 2011 and 2012, which helps to secure our borrowing base, as well as provide downside protection on our base production. Again, our hedging strategy is designed to try and provide downside protection against significant reductions, like we saw earlier this year, while trying to ensure we aren't taken out of the upside potential in those years. So we are being patient and methodical in layering in hedges in these out years to ensure our ceiling is well above $100 per barrel.

As you could see on slide seven, out operating revenue grew by 13% over the previous quarter to $13 million. We record the effects of derivates under the other income section of our income statement as gain or losses on derivatives net. This includes both the cash settled derivatives associated with the current quarter as well as the non-cash, mark-to-market on the remaining outstanding positions.

When taking into account, the cash settled portion of these derivatives of approximately $800,000, our revenue would have been approximately $13.8 million or 6% above the previous quarter.

Lease operating expenses in the third quarter grew slightly over the previous quarter, due predominantly to increased activity in both of our basins, as Marcellus drilling ramped up and oil prices rebounded, allowing us to accelerate some of our work over activities on our oil properties. However, lease operating expenses still remained about 26% below those levels experienced during the same period in 2008.

G&A expenses fell by 36% during the quarter, from the previous quarter and were 26% below the same period in 2008. A portion of this decline was caused by a reduction in legal expenses during the quarter, as well as a non-cash adjustment to long-term equity compensation.

Our EBITDAX increased 27% over the previous quarter, but was still 31% below the same period in 2008, due to the lower commodity prices experienced this year.

Turning to slide eight, our balance sheet and liquidity remained in a very strong position during the third quarter, with a debt to equity ratio of just 6.8%. The amount drawn on our senior line of credit remained at only $15 million. And as we recently announced, we've already completed our fourth quarter borrowing base review, which resulted in our borrowing base remaining at $80 million.

Our cash position increased approximately $2.3 million during the quarter. The carry balance from our Marcellus Shale joint venture with Williams was at $26.9 million as of the end of the third quarter, which decreased approximately $4.1 million from the second quarter due to the drilling and completion activities in the joint venture areas during the period.

Again, in the Williams joint venture areas, until the carry balance is worked off, we are paying for only 10% of the cost to drill and complete the wells, but we own a 50% interest in the wells.

We'll start on slide nine, covering the first of our three major Marcellus project areas, Butler County, Pennsylvania. In Butler County, an area where we own and operate a very high percentage of our acreage, our main focus during the third quarter was in continuing to expand our acreage position, permit additional horizontal wells in anticipation of our 2010 drilling program, and work on expansion plans for our natural gas processing plant.

I'm pleased to report that our first horizontal well has now been in line in excess of four months and continues to produce at 2.4 million cubic feet of gas equivalent per day. Although it is still difficult to determine ultimate recoverable reserves on this well, preliminarily, we expect it to be approximately three Bcfe. We are continuing to aggressively add acreage in this project area, and have increased our position in the County by approximately 84,000 acres year-to-date.

We expect to have increased our acreage in this project area by at least another 5,000 to 10,000 acres by year end. We currently have several horizontal wells permits on file for this project area, and are working to permit additional wells here in anticipation of kicking off our 2010 drilling program. We expect to run at least one horizontal rig in the area continuously during 2010.

Concerning our gas plant in the area, we are continuing the planning process for the installation of a 40 million cubic feet per day cryogenic plant to process our gas in the area. Our expectation is that the facility can be up and running by the fourth quarter of 2010.

In Westmoreland County, we have and continue to be very active in our Marcellus drilling, which you can see outlined on slide 10. During the quarter, we completed and put into line three horizontal Marcellus wells. We tested several different drilling and completion methods to try and determine the best way to drill and complete wells in this project area, which is deeper and geologically more complex than some of our other areas.

Each of these first three wells was drilled to a different depth and completed with a different number of stages, perforation clusters, perforation orientations, et cetera. I'm pleased to report that by the third well, we believe we have come up with a repeatable plan for the area, which has resulted in a 30-day average rate of approximately 4.2 million cubic feet of gas per day.

We've now drilled the fourth horizontal well. We anticipate completing it, along with the fifth and sixth, which we are currently drilling, during the fourth quarter. On the midstream side, we are in the process of installing additional compression to accommodate the new Marcellus wells into our existing tap, which we expect to complete this week.

Additionally, we anticipate commencing the construction of our pipeline and tap for the Equitrans line during the fourth quarter of this year.

Moving into Central Pennsylvania on slide 11, we have commenced drilling our first horizontal test well and anticipate completing the drilling of the well this week. We expect to frac and test the well during the fourth quarter. Additionally, we plan to drill one additional horizontal well in this project area by yearend and complete that well during the first quarter of 2010.

We are also working diligently with Williams, our partner in this area, to complete the tap on the Columbia line in the first stage of our gathering in the area, which we expect to be operational early in the first quarter of 2010.

Last, but certainly not least, turning to our oil production in the Illinois basin on slide 12. We've restarted our developmental drilling and work over activities and are continuing to work more, to move forward with our ASP flood as quickly as prudently possible.

During the third quarter, we drilled 19 new oil wells in the basin, nine of which have been completed and put into production to-date, with an average initial production rate of approximately 30 barrels per day. We expect to continue our developmental drilling projects through the end of the year and plan to drill an additional 20 to 40 wells during 2010.

On our tertiary recovery projects we remain on track to being injection in our first ASP unit in the Bridgeport Sandstone during the second quarter of 2010. We are currently continuing to work with the University of Texas to complete our core studies, recipe refinement and reservoir stimulation – simulations for the design of our first ASP unit, which we call the Middagh Unit.

This first unit totals approximately 140 acres and we plan to start by flooding the center of 30 acres of the Bridgeport Sandstone in the Unit and expanding outward from there. We anticipate it would take 10 to 12 months to see a first response to the process after we begin injecting.

Additionally, we plan to commence injection in our conformance gel pilot during the fourth quarter of 2009.

Turning to slide 13, we are now in the process of completing our2010 capital budget plans, which we expect to announce in mid-December. We anticipate 2010 to be another year of very significant growth in our natural gas production from our Marcellus Shale operations.

During 2010, our preliminary plans envision the drilling and completion of 20 to 24 gross Marcellus wells, which would equate to about 15 to 18 net wells. This would essentially double the number of wells we expect to complete in 2009. We plan to run one rig continuously in Butler County, Pennsylvania throughout the year, where we own a 100% working interest.

However, given the need to expand our gas plant for these wells -- given our need to expand our gas plant, these wells are not forecasted to be put into production until the fourth quarter when we expect the 40 million cubic feet per day cryogenic plant to be operational.

In our joint venture areas with Williams, Williams will be taking over as the operator. We anticipate one rig running throughout the year. Given the expected cost per well, current carry balance, and expected pace of drilling, we should be carried for most of the wells drilled in the Williams JV areas throughout 2010.

As a reminder, in these areas, until the carry is expended, we pay for 10% of the cost to drill and complete the wells, but own 50%. Since those areas are in dry gas regions of the Marcellus, we expect the wells in these areas to be put into sales throughout the year as they are completed.

On the oil side, we plan to continue our shallow drilling projects, given the current high oil prices, to grow our conventional production in the basin. But more importantly, we're very excited to be in position to commence injection on our first ASP unit during the second quarter.

Before I open the call up for questions, I want to highlight several upcoming events. We will be presenting at the Thomas Weisel Partners' Alternative Energy & Natural Resources Conference in New York on November 10, and at Pritchard Capital Partners Appalachia Energy Forum on November 16, in Boston. Then on December 9, we will be presenting at Capital One Southcoast's 2009 Energy Conference, in New Orleans.

Thank you again, everyone for joining us on the third quarter 2009 conference this morning. Operator, at this time, we would like to open the call up for questions.

Question-and-Answer Session

Operator

(Operator Instructions)

And we'll take our first question from Leo Mariani with RBC Investments.

Leo Mariani - RBC Investments

Looking for a little bit more color on your first two well results in Westmoreland, are those wells starting the production, are you getting some at least reasonable production. Clearly, it sounds like they want us to go to the third when you change technique, can you give me any more color on that?

Benjamin Hulburt

Sure. All three wells are currently tied into production, but we did require a bit more compression for all three to be on the floor, at the full amount. So all three are currently curtailed, that additional compression should be completed today so that all three will be on the on the flow at their current amount. So, right now, they are all curtailed by probably about half, but by the end of the day that should change.

Leo Mariani - RBC Investments

Okay. And can you remind us what your current take away capacity is right now prior to getting that compression online in Westmoreland?

Benjamin Hulburt

Before the compression was online, we were probably tapped out at about three million a day or so. Now, by adding this additional compression, we should be able to put about 15 to 18 million a day into that tap site. So the remainder of the wells that we'll drill in that County this year will all be able to go unrestricted into that tap.

Leo Mariani - RBC Investments

Looking into fourth quarter here, can you guys give an estimated of CapEx?

Benjamin Hulburt

Yes. Tom, can you handle that?

Tom Stabley

Yes. The estimate number would be about 12.8 million, Leo.

Leo Mariani - RBC Investments

What are those wells in Illinois basin costing you guys?

Tom Stabley

They average about 250,000 a piece.

Benjamin Hulburt

In Butler County, sounds like you are getting ready to move a rig out there, pretty early in 2010. What do you guys think those well costs would be?

Benjamin Hulburt

Our next round of wells, we're forecasting to be about 3.9 million. It's our hope that Butler County will ultimately be the cheapest area, both in our terms of our drilling. So the next round, we forecasted about 3.9 and we think we'll continue to make progress from there.

Operator

And we will take our next question from Jeff Hayden with Rodman & Renshaw.

Jeff Hayden - Rodman & Renshaw

Ben, just wondering if you can give us some more color on exactly what you guys kind of did and did differently with those first three wells in Westmoreland County in terms of – any color on lateral, link, number of frac stages – whatever you are going to provide?

Benjamin Hulburt

Sure. And obviously, I don't want to educate all of our competitors directly on how we think we've cracked the nut in that area. We varied the frac stages from six stages to 12 over the course of the three wells. We varied the depth of the lateral well bore over the course in the three wells, and the perforation clusters. And those are probably the biggest three variables that we changed, but I think I'd rather hold off on telling what we think the optimum recipe in terms of those three things. All three of the wells are somewhere around 2,000 foot laterals.

Jeff Hayden - Rodman & Renshaw

I mean with the 2,000 foot lateral, was that kind of what you're going to stick with going forward, or you're going to try to push that a little longer?

Benjamin Hulburt

No, I think the objective in every area will be to continue to push the envelope in terms of the length of laterals.

Jeff Hayden - Rodman & Renshaw

Then I know really early, but you're talking 30.9 million for the next round on the Butler well. What would kind of a guesstimate be as far as the AFEs on the Westmoreland wells?

Benjamin Hulburt

Slightly higher, probably about four million to maybe 4.1.

Operator

And we'll take our next question Mike Scialla with Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

On those Westmoreland locations, if I remember right, Williams was acquiring some 3D in that area. Any thoughts on how important that's going to be; do you want to wait for or – do you need 3D at this point or are you comfortable drilling without it?

Benjamin Hulburt

Where we are drilling the wells in 2009, we comfortable without it. We have enough seismic data and understanding of the geology where these wells are. The 3D shoot that we are permitting with Williams is really needed to continue to step out into some of the areas that we think there is a greater likelihood of faulting, but the five or six wells that we do in Westmoreland this year, we think we are okay with.

Michael Scialla - Thomas Weisel Partners

Those next three wells that you are drilling this year, where are those in relation to where the first three were drilled?

Benjamin Hulburt

They are all in the same general area that you can see on the map in the slides, so they are all within a few thousand feet of each other in that area.

Michael Scialla - Thomas Weisel Partners

So, are those Eaglehouse wells, the ones that are to the south, is that...

Benjamin Hulburt

The Eaglehouse ones are ones that are slight more to the north.

Michael Scialla - Thomas Weisel Partners

To the North. Okay.

Benjamin Hulburt

I can say over the three wells, our – one of the Eaglehouse wells did cross a small fault, which probably caused you to lose some frac energy in it. Other than that, the geology over the three wells is relatively similar.

Michael Scialla - Thomas Weisel Partners

Okay. That helps. On your cryogenic plant, is that going to be done with a partner or are you planning on funding that yourself there?

Benjamin Hulburt

We're looking at both scenarios right now. I think, there's a decent chance that we do bring in a joint venture partner on that plant, but we're also moving down an alternative path, which (inaudible) us doing it ourselves. But at this point, I think it's probably more likely that we do it in some form of a partnership with a midstream company that has a bit more expertise in that area.

Michael Scialla - Thomas Weisel Partners

Do you have any kind of contract for the liquids at this point and is that still an issue for that area?

Benjamin Hulburt

We do have a contract for our liquid sales currently ethane continues to be somewhat of a problem in the basin, but we do currently have a contract for our liquid and we are selling our liquid currently. Because of the higher ethane content, we end up with a lower effective price, because we have to transport it all the way down to the Gulf Coast. With the newer cryogenic plant that we will put in next year, the plan is actually designed to reject a portion of that ethane so that we can either use the ethane to run the compressors or inject it back into the gas stream and as long as that doesn't cause the BTU level of our gas to rise above pipeline specs, which we don't think it will, then we can get rid of the ethane that way and what we would be left with is the propanes and butanes, which we then would get a higher price for. So the newer cryogenic plant will actually help alleviate some of that backlog.

Michael Scialla - Thomas Weisel Partners

Then just one last one from me. If you look at what you want to do with this play and you mention you are looking at adding acreage in Butler County before the end of the year. Any thought on – have you seen enough in Butler County to want to try and get more aggressive there and is there an opportunity to get more aggressive there with acreage next year? And is there any thought on – should I going to be able to ramp up the (inaudible) this cryogenic plant in place to scale back on the drilling and maybe do a couple of wells early and then add more in terms of acreage (inaudible) in that area?

Benjamin Hulburt

Well, in terms of the acreage, when we estimate another five to 10,000 acres this year, I think that is an extremely doable target. Next year, I would be happy to add twice that amount. We do have at least 15 land men on the ground in there and are adding acreage in there literally every day. It is a slower place to lease, in Pennsylvania, because the tracks tend to be relatively small, but we do want to expand our holdings there very significantly.

In terms of continuing to drill throughout the year, the reason we have to do that is for a 40 million a day gas plant, the turndown ratio on that plant is 12 to 15 million a day. So when you activate the plant, you have to have 12 to 15 million a day of gas ready to go into it. So we do have to continue to drill some wells so that we're ready to activate the plant early in the fourth quarter.

Michael Scialla - Thomas Weisel Partners

I guess I'd like to do one more. Any thoughts on adding acreage in Westmoreland at this point?

Benjamin Hulburt

We are actively looking at additional acreage in that area. Williams is beginning to take the lead on managing the leasing in that area, as we continue to transfer over operations in anticipation of 2010. So, Williams is handling more of that area than we are, but both of us agree that we want to continue to add acreage there.

Operator

And we'll take our next question from Derrick Whitfield, Canaccord Adams.

Derrick Whitfield - Canaccord Adams

Most of my questions have already been answered, but maybe digging into Westmoreland a bit there. Based on your earlier vertical test results, do you feel the geology is fairly consistent across your acreage, and is it fairly easy to take your recipe and repeat that sort of cross sites as you think about the fourth, fifth, and sixth well?

Benjamin Hulburt

The geology I think is fairly consistent in terms of the thickness in the section of the Marcellus that have the higher organic contents. We do see quite a bit of change in the depth of the beds in the Marcellus in Westmoreland County, which is one of the things that makes the drilling a little bit more expensive and more challenging. But the answer is, yes, we think we now have a repeatable recipe for success in that county.

Derrick Whitfield - Canaccord Adams

Then thinking about sort of Central PA are there any similarities based on what you've seen from your seismic that would suggest that you can take some of the learning's from Westmoreland and then apply them there?

Benjamin Hulburt

Yes, and no. The Marcellus in Central Pennsylvania is very different from the Marcellus in Westmoreland County or Butler County for that matter. So unfortunately, and unless it is just blind luck, your first well there is a test well and you will go through a learning curve in that area. The portions of the Marcellus that we believe the majority of the gas will come from in Westmoreland County is completely different than what we see in Central Pennsylvania. So there is going to be a learning curve in each new area for the first few wells.

Operator

And we'll take our next question from Richard Rossi with Wunderlich Securities.

Richard Rossi - Wunderlich Securities

We'll you've certainly covered most of what I was going to ask, but looking at that last Westmoreland well, the third one, was that around $4 million?

Benjamin Hulburt

No, I think that one was probably a bit higher, probably between 4.5 to five million. The initial wells will always be a bit more expensive. We do think Westmoreland County, because of the higher pressure and the fact that you're often drilling through a coal area which often requires two strings of casing, it will be one of the more expensive areas that we have. But again, the next round of wells we think will be down closer to four million.

Richard Rossi - Wunderlich Securities

Then is that extending the lateral above the 2,000 foot?

Benjamin Hulburt

We will continue to extend the lateral as far as we can in that area. Again because the dip of the beds tends to change more frequently there, it is an area that's harder to continue to push the length of your lateral, but it is our objective to continue to get longer and longer lateral.

Richard Rossi - Wunderlich Securities

Just in general, what are the service core trends that you are seeing in the Marcellus right now?

Benjamin Hulburt

Generally, we've seen rigs rates come down fairly considerably from what they were at the highest last year. In terms of the completion costs, they decline some, but not drastically.

Richard Rossi - Wunderlich Securities

I have heard in other areas, you are beginning to see a little extension in scheduling fracs versus a few months ago. Is that the case up here as well?

Benjamin Hulburt

Yes. We are starting to pickup activity on the completion side.

Richard Rossi - Wunderlich Securities

Then finally, anything new on the Pennsylvania tax issues?

Benjamin Hulburt

No, nothing, to my knowledge. It was withdrawn from the budget this year and I haven't heard anything further since then.

Operator

We will take our next question from Don Crist with Johnson Rice.

Don Crist - Johnson Rice

All of my questions on the Marcellus have been answered. Can you give us a little color on the Illinois basin and how do we model the wells that are coming on. Can you remind us what IP rates of those wells are and the costs, et cetera?

Benjamin Hulburt

Well, in our reserves, generally the tight curved, shallow well out there has an initial production rate of about 15 barrels a day, and within two months or so that would have fallen to about eight barrels a day. And then, it would go at about a 6% decline after that. It is what we receive.

Don Crist - Johnson Rice

I guess just from running through the production in my model, we should just keep the gas coming out of the Marcellus basically flat until the fourth quarter and then have a large jump there with exceptionally in Butler County, but then have a ramp in Illinois going forward, right, in the oil side? So I'm guessing your percentages are probably going to add some?

Benjamin Hulburt

Yes, on the oil side, drilling 20 traditional shallow wells a year essentially helps just keep out production in that basin flat. So, if we get 40 done, we could grow the production there three to five percent or so. On the natural gas side looking into 2010, it is true that there will not be a big ramp up in production in Butler County because of the need for the gas plant, but in the joint venture areas with Williams, that's not true that we would expect the wells there to be brought on each month as they are drilled and completed.

Don Crist - Johnson Rice

Can you just, on the plant that you all are building, can you just remind us the cost of that and if you bring in a partner, how much of that could be deferred?

Benjamin Hulburt

I think because we are having some discussions with varying groups on that, we'll hold off on giving the details on the gas plant. I do think we'll be able to update the market further if we do a potential joint venture there in the next 30 days or so. But I think until then, we'll hold off getting the details.

Operator

We'll go next to Ray Deacon with Pritchard Capital.

Raymond Deacon - Pritchard Capital

I was just wondering, can you remind me what your taps and your takeaway capacity in Westmoreland and Clearfield are and will that change in 2010?

Benjamin Hulburt

Well, in Westmoreland county as I said, in the existing tap that we have for the Marcellus, which sells into Dominion Peoples, we think we can put about another 15 to 18 million a day into that, which, if the remainder of the wells are what we expect for the rest of year, will fill up that. So, we're already starting the process of building from our field to the Equitrans line and which is only about four miles and we have all the rights of way to do that. On the Equitrans line, we'll be putting a tap in place early in the first quarter of 2010 to handle additional wells for next year. And the size of that tap and capacity there is still being determined, but it should be substantially larger than what we can sell into Dominion Peoples currently.

Raymond Deacon - Pritchard Capital

Got it.

Benjamin Hulburt

Then the third outlet that we plan is to go from our field to the Texas Eastern line, which runs about eight miles from our field, and again we already have the rights of way to do that. And the Texas Eastern line is a line that we would anticipate being able to put in a much larger capacity.

In Central Pennsylvania, the tap we are putting in there on the Colombia 1711 line, is still begin negotiated, but it's our anticipation that 50 million a day of capacity would be available there.

Raymond Deacon - Pritchard Capital

I guess just on the oil side, just a timing question on the colloidal water flood, how long of a response time would you expect and kind of the same, I was thinking about 10 months on the ASP, is that about right?

Benjamin Hulburt

I think the colloidal gel test would be a bit quicker than that, I think probably six months. That said, that is truly a small pilot, and the wells are tighter spaced, so the response time should be quicker.

Operator

We'll take a follow-up from Leo Mariani with RBC Investment.

Leo Mariani - RBC Investments

With respect to your comments on the pipeline taps, you guys are working in the capacity there, do you guys have firm capacity on those pipeline contracted?

Benjamin Hulburt

We do not currently have any firm capacity contracted. We've also kind of handed over the midstream side of Westmoreland County and Clearfield County to the Williams guys, because it's obviously something they are very good at. So all of those firm capacity discussions are ongoing now.

Leo Mariani - RBC Investments

Can you remind us what your current net Marcellus acreage position is?

Benjamin Hulburt

The current net is still somewhere just south of 50,000 acres, 49.5 or so. As I said, we are adding acreage every day, the only reason we haven't updated our acreage tables is we are still completing title on some of the more recent leases that have been signed. So currently its 49.5 and we expect that to continue to rise for the rest of the year.

Leo Mariani - RBC Investments

You guys have captured additional acreage. You just happened to closed some the [inaudible] title work?

Benjamin Hulburt

Yes. We haven't completed the title work so we don't like to put it into the box and call it ours until all the title work is done and we know it's clean.

Operator

We will go next to Brian Lively with Tudor, Pickering, Holt

Brian Lively - Tudor, Pickering, Holt

Just a few book keeping questions. In the Butler County area, you talk about BTU content, I think around 1,250 gas. What types of gas shrinkage and NGO yields are you seeing and are you seeing NGO yields declining with time?

Benjamin Hulburt

In terms of the NGO yield currently from the refrigeration plant that we are running now, which only takes the temperature down to about negative 30 degrees, right now we are yielding about 1.7 gallons per MCS of mixed Y grade natural gas liquid.

With the cryogenic plant that will be installed next year, I would anticipate a shrink of about five to 6%. We would be getting higher yield, we think on the natural gas, because the cryogenic plant will go down to about negative 170 degrees. So the liquid (inaudible) should be a little higher than two gallons per Mcf. And again, it would then knock out most of the ethane, so it would be a more valuable liquid.

Brian Lively - Tudor, Pickering, Holt

Then staying on Butler, the four vertical wells that you have drilled, how do their performance compare with the horizontal well? Are they declining like typical hyperbolic wells or are they flattish?

Benjamin Hulburt

The vertical wells declined as typical hyperbolic wells. We do have some additional core analysis in Butler, and have some working theories now on why that well is not declining and why we think so highly of a potential in that area.

Brian Lively - Tudor, Pickering, Holt

Do you care to share that thought with us right now?

Benjamin Hulburt

I really don't. It is our number one leasing area and we continue to be very enthused about it.

Brian Lively - Tudor, Pickering, Holt

Changing gears over to Westmoreland for a second, just a follow-up question, you mentioned encountering a fault in potential losing some energy in the fault. What is your thoughts on potentially actually having gas that charges the fault and gives you more production, and how has that changed with the wells that you've drilled?

Benjamin Hulburt

Sure. We have seen instances, especially in our vertical wells, where a fault did give us some free gas that was trapped in the fault system. And again, the fault that we crossed in one of the Eaglehouse wells was not a major trough fault. It had a displacement of I think three feet or so. So it's probably something that 3D seismic wouldn't even pick up. I think if you did get any free gas from the fault, it wasn't beneficial enough to overcome the fact that probably two to three of your stages on either side of the fault were not very effective.

Operator

We'll go next to Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast

Yes, I had to hop out of the call for – I did miss – didn't catch all the call but I had a question on the second well in Westmoreland. You talked about the first well potentially hitting a fault, was there anything strange about the second well? Did it have any mechanical problems or did you think it was a sub-par well that you've learned some things that won't happen again. Just wondering, was there any sort of clear problems with that second well?

Benjamin Hulburt

No, there were no clear problems with that second well other than some of the perimeters obviously we changed for the third well.

Brian Lively - Tudor, Pickering, Holt

Do you have a feel for the EUR that you would expect on the Butler, that initial Butler County well or is it just some possible to say given that its still...

Benjamin Hulburt

In Butler, it is still very difficult to say. When we take our tight curve and essentially just keep moving it out as the well stays flat, you get somewhere around a three Bcfe well. But again, until we start to see a recognizable decline, it's somewhat of a guess.

Operator

We'll go next to Jack Aydin with KeyBanc.

Jack Aydin - KeyBanc

Most of my question was answered, but I've got three follow-up. First of all I apologize if you issue a guidance for the fourth quarter, did you issue any guidance in terms of production for the fourth quarter?

Benjamin Hulburt

We didn't Jack.

Jack Aydin - KeyBanc

Second, in terms of reserve, last year, you did loose about five million barrels for the prize. What do you think you'll be able to recover and book this year in terms of reserves from that loss?

Benjamin Hulburt

Well, I would expect a portion of those to come back, because the oil prices are higher now. And remember this year we'll be using a backwards looking average. So unfortunately we still won't be doing the reserves at $80 oil. It will be higher than it was last year and we would anticipate at least a portion of the oil reserves we lost last year, because of the oil prices to come back, but at this point, (inaudible) is still working actively on completing our reserves. So I don't want to throw any hard numbers on it.

Jack Aydin - KeyBanc

The last question, are you testing the upper Marcellus and the Purcell in any of your wells, or do you see any contribution from those areas in some of the wells that you are drilling?

Benjamin Hulburt

I think it depends on the area. And again, I don't want to go exactly into which areas we are completing of the Marcellus, but it does depend on which part of the state and really which county you are in. There are certain parts where the upper Marcellus and the Purcell do appear to contribute more gas, even then what the lower does and it's the opposite in different parts of the state.

Jack Aydin - KeyBanc

The test you are going to do in Central PA, are you going to test those concepts or no it's pure Marcellus?

Benjamin Hulburt

At this point, in Central PA, we are testing the Marcellus. Central PA is an area where the zones above the Marcellus look like they may contribute some of the gas, but the first horizontal that we are doing there is our best guess of how to test the Marcellus, but again, I am sure there will be somewhat of a learning curve in that area as well.

Operator

(Operator Instructions) With no further questions in the queue, that does conclude today's conference call. We thank you for your participation, and you may now disconnect.

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