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Executives

Benjamin Hulburt – President and Chief Executive Officer

Thomas Stabley - Executive Vice President and Chief Financial Officer

William Ottaviani - Chief Operating Officer

Analysts

Leo Mariani - RBC

Mark Lear - Sidoti & Co

Ron Mills - Johnson Rice

David Heikkinen - Tudor Pickering and Holt

Jeff Hayden - Rodman & Renshaw

Rex Energy Corporation (REXX) Q3 2008 Earnings Call November 7, 2008 10:00 AM ET

Operator

Good morning and welcome to Rex Energy Corporation’s Third Quarter 2008 Financial Results Call. I will be your coordinator for today. At this time, all participants are in 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 the question-and-answer session towards the end of this conference. As a reminder, this conference will be recorded for replay purposes.

Now I would like to turn the call over to Mr. Benjamin Hulburt, President and CEO of Rex Energy Corporation. Please proceed, sir.

Benjamin Hulburt – President and Chief Executive Officer

Thank you. I’d like to welcome everyone to Rex Energy’s third quarter financial results and operational update conference call. I’m here today with Tom Stabley, our Executive Vice President and Chief Financial Officer, and Bill Ottaviani, our Chief Operating Officer. By now you all should have received the third quarter earnings press release and we hope you take the time to read through it as it contains important information. Following the live call, an archive of the audio will be available on Rex Energy’s Investor Relations website at www.rexenergycorp.com.

First, I would like to begin today's call with a discussion of our liquidity and balance sheet. I am pleased to report that as of September 30, 2008, we had cash on hand of approximately $25.7 million with zero long-term debt, and a $90 million credit facility that has not been utilized to-date. Our banking indication is currently in the process of completing our regularly scheduled borrowing base review on our line of credit and initial indications are that the borrowing base is expected to remain at 90 million interrupt until our next scheduled re-determination.

On November 6, our Board of Directors approved the capital budget for 2009 of $115 million. This budget is allocated 49% towards our Marcellus Shale projects, 38% towards our Lawrence Field ASP project, and approximately 13% towards our developmental drilling projects in the Illinois Basin. Given our current cash flows, cash on hand and our unused line of credit, we believe we have ample liquidity to complete our planned 2008 and 2009 capital budget. With this budget we plan to run one rig in the Marcellus Shale horizontally throughout the year and commence chemical injection in our first operational ASP unit in the Lawrence Field.

Now I’ll focus on the operational and financial highlights for the third quarter and year-to-date, which as discussed in our release, exclude our Southwestern region operations as these properties have been reclassified as held-for-sale. Our total production for the third quarter increased to 238,000 barrels of oil equivalent or BOEs, up 6.8% from the same period in 2007.

Our revenues for the third quarter increased to $18.7 million, up 41% from the same period in 2007. Our EBITDAX for the third quarter increased to $7.7 million, up 18% from the same period in 2007. And lastly, our cash flows from operations for the third quarter grew approximately 33% from the same period in 2007 to $10 million.

In August, we announced we completed the sale of 79,000 net undeveloped acres in Indiana and certain related non-producing wells for approximately $8.4 million. The acreage divested consists all of our interests in acreage known as the Wabash and Lawrence areas of mutual interest, which were operated by Aurora Oil and Gas Corp. and all of our undeveloped acreage in Knox, Sullivan and Daviess Counties, Indiana, which we operated.

In addition, we announced in September that we are pursuing the sale of our Southwestern region assets. These assets include all of our properties in Texas and New Mexico. Our decision to divest (inaudible) undeveloped acreage and to sell our Southwest region assets was part of our strategic plan to focus our efforts and capital investments in our ASP flood project in the Illinois Basin and our Marcellus Shale exploration project in the Appalachian basin, where we believe we have better growth opportunities.

Chemical injection continues in our two ASP flood pilots in the Lawrence field. Oil cuts continue to fluctuate and rise in both pilot areas, in the Bridgeport pilot reaching an aggregate oil cut of up to 6% and in the Cypress pilot reaching an aggregate oil cut level of up to 5% during the third quarter. Additionally, each pilot area had individual wells whose oil cut exceeded 10% during the quarter. As a frame of reference, both pilots had oil cut of approximately less than 1% at the commencement of chemical injections.

Performance of our Bridgeport pilot is generally inline with the earlier radial coreflood done in laboratory, although we're seeing some scale build up in our production wells. We believe this is due to the relatively small size of our pilots and the high concentration of alkali, which is soda ash used in the chemical blend. When we go to full project development with greater spacing between the injection and production wells, scaling tendency should be sharply reduced. In the meantime, we have added a scale mitigation treatment to our pilot production wells.

Production of our Cypress pilot had somewhat lagged behind pre-trial expectations due to what we believe is a high conductivity zone causing unfavorable aerial and vertical sweep efficiency. As a result, we have seen premature chemical breakthrough at some of our production wells and suspect off pattern migration of ASP chemicals. To mitigate this effect, we have performed a number of injection profile, control workovers on our injection wells. [Tracer] surveys conducted after this work indicate that we have had success in approving injection controlled a day. Today we have not seen any migration chemical outside of the pilot area and continue to monitor wells on a daily basis.

Results from our pilots are being incorporated into a detailed reservoir characterization model that will be used in both estimating alternate reserves and in optimizing our pattern design and size when we move to the start of our full field development. This technical assessment work is expected to continue through the end of the year, following which we will begin the first phase of our planned full field development. Anticipating this first phase of development, expansion of the existing chemical injection plan continues as new equipment foundations are built and we begin to take possession of long lead time components of the plan reported several months ago. Operationally, the plant itself continues to perform at a high level with operational efficiency averaging 96% for the third quarter.

In our Marcellus Shale projects, we drilled three additional vertical test wells in Westmoreland County, Pennsylvania during the quarter. Two of these wells have been fracture stimulated and are currently flowing back and undergoing initial testing. The third is expected to be fracture stimulated during November. Additionally, we're participating for 50% with our partner in two additional vertical wells in Butler County, Pennsylvania and we anticipate drilling an additional two vertical wells in Clearfield County, Pennsylvania during the fourth quarter.

Capital expenditures for drilling and development in the third quarter were approximately $18.9 million, which funded the drilling of 24 gross and 24 net wells and related improvements to infrastructure. Of the wells drilled, 14 were completed and are producing and 10 are expected to be productive but are awaiting completion. Additionally, $6.7 million was invested in acquisitions, leasing, leasehold improvements, and technology equipment during the quarter.

Finally, I would like take a moment to say how excited we are to have added two highly qualified and experienced individuals to our technical team, Mr. Tim Beattie and Mr. Mike Rinch during the third quarter. Tim comes to us for Woodside Energy where he served as Engineering and Operations Manager. He has over 24 years of experience in reservoir engineering and operations management with extensive knowledge of reservoir modeling and project management. As Senior Vice President of our Appalachian Region and Appalachian Region Manager, Tim is responsible for all of our activities in the Appalachian Basin.

Mike Rinch joined the company as Vice President of Reservoir Engineering. He brings over 25 years experience in petroleum engineering ranging from exploratory prospects to mature fields rejuvenation. Most recently, Mike has spent the last eight years as an Independent Consultant reviewing well proposals, developing new drilling prospects and preparing financial models in the Appalachian Basin. They both bring an extensive amount of experience and technical skills in managing various exploration and production operations through out the United States. We look forward to their many contributions to our organization in the years ahead.

With that, I would like to turn the call over to Tom Stabley, our Chief Financial Officer.

Thomas Stabley - Executive Vice President and Chief Financial Officer

Thanks Ben. As Ben mentioned at the beginning of the call, we announced our plans to divest our properties in Texas and New Mexico, which we’ve referred to as our Southwestern region. In accordance with the accounting rules for the disposal of long lived assets, we have reclassified the assets and associated liabilities relating to our Southwestern region as held-for-sale on our balance sheet for all periods presented, and have reported the results of our Southwest region operations under discontinued operations on our consolidated statement of operations for all periods presented. Therefore, the financial and operation figures presented in our financial statements and earnings release exclude these discontinued operations and assets held-for-sale except where noted.

Our production for the third quarter grew approximately 7% over the same period in 2007 to approximately 239,000 BOEs or 224,000 BOEs, of which approximately 83% was attributed to oil. Our revenues for the third quarter of 2008 increased approximately 41% to $18.6 million compared to $13.3 million for the third quarter of 2007. This increase was primarily due to higher production with higher average sales prices per BOE partially offset by the increased realized losses on derivate activities. The average realized oil price in the third quarter of 2008 before the effect of derivates was $115.32 per barrel, up 63% from $70.79 per barrel in the third quarter of 2007.

The company’s average realized natural gas price in the third quarter of 2008 before the effects of hedges was $10.30 per thousand cubic feet of natural gas, an increase of approximately 60% from $6.45 per mcf natural gas in the third quarter of 2007.

Our operating expenses for the third quarter of 2008 increased 5.1 million or approximately 42% for the third quarter of 2008 as compared to the same period in 2007. Production and lease operating expenses increased approximately 2.3 million or approximately 44% in the third quarter of 2008 from the same period in 2007. These expenses have increased year-over-year primarily due to the greater number of wells in service as compared to the third quarter of 2007 and the increasing cost of goods and services used to operate our oil and gas deals. Also, contributing to the increase in expenses were higher production taxes which can be directly attributable to our increased production, sales price and subsequent revenues.

Our general and administration expenses for the third quarter of 2008 increased approximately 2.2 million or 142% to $3.8 million from the same period in 2007. The increase in G&A expenses were primarily due to increased costs associated with consulting fees relating to Sarbanes-Oxley compliance and additional staffing in each of our operating offices as well as our corporate headquarters. Non-cash compensation expenses of $464,000 in the third quarter of 2008 also contributed to the increase in G&A expenses from the third quarter of 2007. We do not have any non-cash compensation expense during the same period in 2007.

Exploration expenses for the third quarter of 2008 were 1.1 million. The company did not incur any exploration expenses for the same period in 2007. The increase in exploration expense was primarily due to expenses associated with our reservoir characterization and geological modeling in both our Lawrence Field ASP project and Marcellus Shale.

Depreciation, depletion, amortization and accretion expenses for the third quarter of 2008 increased approximately $735,000 or 14% -- decreased approximately $735,000 or 14% from 5.2 million for the same period in 2007. This decrease is primarily due to the amortization of loan cost during the third quarter of 2007.

EBITDAX increased approximately 1.2 million to 7.7 million during the third quarter of 2008 as compared to the same period in 2007. This increase in EBITDAX can be primarily attributed to the higher production and higher average commodity prices during the third quarter of 2008, which was partially offset by higher operating expenses in each of our areas. Cash flows from operations for the third quarter of 2008 grew 33% from the same period in 2007 to $10 million.

We reported net income from continuing operations before minority interests and income taxes of $61.7 million in the third quarter of 2008 as compared to a net loss of $2.1 million for the same period in 2007, an increase of approximately 63.8 million. The increase was primarily due to our unrealized gains on derivatives of approximately 66.7 million. These non-cash gains are associated with the mark-to-market adjustments on our outstanding derivatives which grew as a result of the significant decrease in oil and natural gas prices this quarter. The unrealized gain on oil and gas derivatives was partially offset by a provision for income tax expense of approximately 24.9 million.

Net income comparable to analyst estimates was $1.7 million or $0.05 per basic share, in the third quarter of 2008 down from $2 million for the third quarter of 2007.

Net income comparable to analyst estimates is on-GAAP financial measure of net income which excludes deferred tax benefits, dry hole and impairment expenses, gain or loss on the sale of assets, unrealized gains or losses from financial derivatives and non-cash compensation expenses.

As Ben discussed as of September 30, 2008, we have continued to maintain a conservative balance sheet with cash on hand of $25.7 million, zero long-term debt and a $90 million credit facility that has not been utilized to date.

For the fourth quarter 76% of our current oil production is hedged at floor price of $65.50 per barrel and 75% of our current natural gas production since hedged at a floor price of $7 per mcf.

Looking forward to 2009 77% of our current oil production is hedged at floor price of approximately $64.11 per barrel and 66% of our current natural gas production is hedged approximately a floor price of $7.14 per mcf.

With that, I would like to turn the call back over to Ben.

Benjamin Hulburt – President and Chief Executive Officer

Thanks Tom. With that we’d like to open the call up for questions, operator.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Leo Mariani with RBC. Please proceed.

Leo Mariani

Hi, good morning guys.

Benjamin Hulburt

Good morning Leo.

Leo Mariani

Two question on your production guidance here. Just looking at your press release here, you guys had your fourth quarter guidance for '09 kind of guiding production down a little bit here from the fourth quarter. Just trying to get a sense that you guys have factored in, any impact in the Marcellus Shale that you guys have recently drilled here in, I know you did a couple as well completed?

Thomas Stabley

Well there is some impact in there, Leo. We have tried to be pretty conservative with it. We've also given the flooding that happened in the Illinois Basin in the first quarter of last year, we've tried to account for that you know, in the event that that can say happen again in that first quarter guidance. So we have tried to be conservative than factor those things in.

Leo Mariani

Okay, got you. I guess [an ablation] just curious if you guys have a test rigs on those first couple Marcellus wells?

Benjamin Hulburt

We are continuing to test both of them, Leo. And we do have some flow rates, but just don’t have enough sustained data yet that we are comfortable out. I think we could look to do that within about a week or so.

Leo Mariani

Okay. Would you guys anticipate coming out with the press release at that time with some low rates or…?

Benjamin Hulburt

I think we will hold off doing the press release until we get the third one fract and get the flow rate on that as well. At this point that fract is scheduled to take place on the 17th.

Leo Mariani

So, we reasonably assume that you come out maybe at some point at the end of November, early December?

Benjamin Hulburt

Yes.

Leo Mariani

Okay. In terms of your Bridgeport pilot, are you guys still kind of confidence that working according to your preliminary engineering estimates and do you think (inaudible) quick response in December?

Benjamin Hulburt

Bill, do you want to address that?

William Ottaviani

Yes, this is Bill Ottaviani talking. The Bridgeport pilot is responding within the parameters that we had expected from the earlier laboratory trial. So at this point we really have no reason to expect any deviation from the future expectations. So as the oil cut continues to rise, model suggests that we should be peeking sometimes late this year.

Leo Mariani

Okay. Thanks guys.

Benjamin Hulburt

Thanks Leo.

Operator

Your next question comes from the line of Mark Lear with Sidoti & Co. Please proceed.

Mark Lear

Good morning. Just looking -- in fact you are looking at ramp up spending on the drilling side in Marcellus, I was wondering what you have budgeted for horizontal wells next year, and when we can get those?

Benjamin Hulburt

On an individual well basis?

Mark Lear

Right.

Benjamin Hulburt

Well, what we have put in our budget is probably a very conservative number I think we are using about $4.5 million per horizontal well. That number is based on I think historical cost for casing and steel. So it probably would have come down some, that’s why we got it in our budget.

Mark Lear

And how many wells in total?

Benjamin Hulburt

What we are anticipating is getting 10 horizontal wells online completed by the end of the year.

Mark Lear

And when do you –your first plant?

William Ottaviani

You mean treatment plant for the gas?

Mark Lear

No, your first horizontal.

William Ottaviani

Plant, I am sorry. We have our first one scheduled to commence in February.

Benjamin Hulburt

Well, the starting of the drilling, I don’t think the production we will see…

William Ottaviani

Right. The production, we don’t really have forecasted to come online until early second quarter.

Mark Lear

Got you. And just looking at the capital spending plan for the fourth quarter, I assume a lot of that's with the going for the full scale on the first full scale in chemical flooding, I was just wondering when you do plan to commence that flood?

Benjamin Hulburt

The actual chemical flooding in the first full unit is scheduled to begin June 1 in our plan.

Mark Lear

Okay. So not till mid year?

Benjamin Hulburt

Yes. The drilling of the wells and designing the actual unit will be happening in the first part of the year. And I think the drilling consist of somewhere between 50 and 100 wells. So that will be happening in the first half of the year so that you can begin injection again at the beginning of June.

Mark Lear

Then I guess where is the big capital expense coming in the fourth quarter, I guess sequentially?

Benjamin Hulburt

Fourth quarter capital expenses we have in the guidance that’s essentially made of about $20 million in drilling and completions in our Marcellus Shale wells as well as development drilling in the Illinois Basin. About $15 million of that is in the ASP pilots in the expansion of the pilot plant to get it ready for full field expansion. And then about $20 million of that is finalizing our leasing program in the Marcellus Shale for leases that we really have already signed up and committed to in July and August, so it’s really just paying for those final leases.

Mark Lear

Got you. Thanks a lot.

Benjamin Hulburt

Thanks.

Operator

Your next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

Ron Mills

Good morning.

Benjamin Hulburt

Good morning.

Ron Mills

Question on the first quarter production guidance I guess following Leo’s question and then particularly as you drill up to 10 horizontal wells next year, obviously that first quarter should not be used as a run rate for the whole year, but have you all taken a preliminary look in terms of what your production profile looks like for the years as you build in the horizontal wells because I am assuming the oil side isn’t going to see much of a change at least until the ASPs starts to contribute in 2010 or ‘11 but the gas side should start to show some nice increases as the horizontal wells come online?

Benjamin Hulburt

Yeah, I think that's completely correct, Ron. We certainly do have models and forecasts of what we think production year-over-year could be. We are putting out year-end guidance. This is a difficult year for us to give guidance because the Marcellus Shale wells, potential production rates are a very large percent of our total company production so they can have a pretty major impact in growth throughout the year. So definitely though the production ramp up would happen in beginning in the second quarter and then continue to ramp up in the third and fourth. So I agree with your statement that the first quarter should not be seen as indicative of the second half of the year.

Ron Mills

And depending on what the full rates are, whether the 2 or 3 million a day variety or the 5 or 6 million a day variety, but if you look at when the run rate program I assume you would have a fairly consistent well addition I guess for lack of a better term, program where kind of every 30 to 45 days you should be able to add another well next year, is that the way it kind of works?

Benjamin Hulburt

That's right, exactly right.

Ron Mills

Okay. And just -- the Southwest region, what were the proved reserves and what are the proved reserves associated with that area?

Benjamin Hulburt

About 10.7 Bcfe, those reserves are weighted about 60% natural gas.

Ron Mills

Okay. And where are you all in that process? Has it been out into auction or is there a data room, just where are you along the steps?

Benjamin Hulburt

There was a data room, we are in active negotiations. I feel very good at this point of closing a potential transaction during the fourth quarter.

Ron Mills

Okay. And just on the Bridgeport and the Cypress, particularly the Bridgeport is that when really -- is tracking the pre-injection curve. As long as you – to the extent you’re still at peak production by the end of the year and the work you’ve been doing with reserve engineers, is it still hopeful and/or likely that you may be able to book at least a small portion of those ASP reserves?

Benjamin Hulburt

Yes.

Ron Mills

Okay. Alright, thanks.

Benjamin Hulburt

Thanks Ron.

Operator

Your next question comes from the line of David Heikkinen with Tudor Pickering and Holt. Please proceed.

David Heikkinen

Good morning. Just kind of following on those lines, Ben, can you talk about individual well oil cuts and kind of how that fluctuates over time and where the whole pilot would be both for the Bridgeport and the Cypress?

Benjamin Hulburt

Well, we didn’t put out individual oil cut rates because they do fluctuate and it’s a one-day data point. We did put it in the release that there are (inaudible) over 10% of the oil cut on an individual well basis – on a fairly regular basis. When you look at individual wells and look at the pilot as a whole, it really is the center well in each of the pilots that we look at the most because the only one of the five that’s confined inside the pilot, the way the majority of your wells will be in a larger unit. And there are days when the oil cut is well above 10%, up as high as even 17%, I think it’s the highest I have ever seen. So there are days that it exceeds the averages that we put out in the third quarter. I think the most important piece of information right now is the analysis on the Bridgeport by us and by [Certec] that it is generally inline with what the original modeling set it should be at this point, so we are very happy with it. The Cypress pilot, we think, we’re a little bit behind schedule because some initial operational issues in the high permeability on that we saw that made cause us to lag in terms of time but not necessarily in terms of ultimate recoveries. Does that answer your question, Dave?

David Heikkinen

I guess I was trying to reconcile to the last quarter call, we talked about three of the five wells and the Cypress were in a 5 to 10% now. Where are those wells now? Are they still at 5 to 10%, and just try to see the Cypress pilot and then get the same type of look at the Bridgeport pilot?

Benjamin Hulburt

Well, that’s still completely true in the Cypress. Three of the five have had peaks, actually well above 10%. But we have been doing a lot of workover work in both of the pilots. In the Cypress pilot, we have been doing a lot of workovers to overcome that high permeability channel that we saw. And then the Bridgeport pilot, we have been doing a lot of workovers to account for the scale build-up that we have seen in the wells that because of larger spacing in a larger unit we don’t think we even see that as an operational unit. For each of the two pilots have been going, undergoing really daily workovers and refinements so that’s why we are not putting out those individual peak rates that only happen for a day.

David Heikkinen

So when you think about the scale build-up and kind of just putting scale inhibitors into the producing wells, what does that do to your operating expenses and like you said maybe explained us why you wouldn’t see scale breakthrough, are you just not expecting to see any of the – in a full scale development or scale dropout?

William Ottaviani

Dave, this is Bill, and I can address that question. With regards to the scale formation that we are seeing in the pilot, the spacing in the pilot is much reduced compared to what we anticipate with the full field development. And we did that consciously so that we can accelerate the process and verify that it’s working in book reserves. As we go to a full field development, our spacing will go from essentially 1 acre spacing to 5 to 10 acre spacing. And in that type of spacing configuration, the chemical concentration will have more time to react on the rock. And by the time that the chemical formula gets to the producing wells it would have already spent. So we would not anticipate seeing that type of scale formation or any scale formation at the producers. So the additional LOE that we are incurring at the pilot, which is fairly nominal on the grand scheme of things, we don’t anticipate seeing at all as we go to a full field development.

David Heikkinen

Okay. And kind of going back to now the wells in the productivity and the Marcellus, talked about kind of 675 Mcf per day, are all rigs about that rate, I know you didn’t want gave rates but just trying to get idea where things are?

Benjamin Hulburt

The wells that we have drilled and completed (inaudible) Westmoreland County are quite a bit deeper than the Butler County wells and those are the ones that had initial rates of 675. The wells in Westmoreland County are still throwing water out of the wells from the fracs, so we don’t yet know what a peak rate is going to be, they are still rising.

David Heikkinen

Okay.

Benjamin Hulburt

So we don’t know whether we are going to pull out yet.

David Heikkinen

But do you expect it higher, I mean deeper, more pressure is what you saw, so you would expect higher rates from the Butler County well?

Benjamin Hulburt

I don’t know if we know enough to answer that yet. I guess logically deeper, you’d hope for a higher pressure and therefore higher rates. But until we unload these further, I think one well and both of them I think it’s still under the 50% of the fluid back.

David Heikkinen

Yeah, okay.

Operator

Your next question comes from the line of Jeff Hayden with Rodman & Renshaw. Please proceed.

Jeff Hayden

Hi guys. Just quickly on some of the other questions that have been asked, starting with the Marcellus, you talked about expenditure in Q4 to kind of close up on some acreage acquisition. Would you give more color on how much you are looking forward, is that kind of 12,000 net acre that you have talked about beforehand and do you know kind of what counties is that in? And then also kind of curious of the wells, the 10 wells you plan to drill next year they are going to be concentrated in any one specific area, kind of spread across all your acreage, how are you thinking about that right now?

Benjamin Hulburt

Sure. Well, on the acreage number, I anticipate ending this year at about 70,000 net acres, so really right where we had forecasted to be. In terms of where that acreage is, what I anticipate is in Clearfield than Centre Counties that project area for us being somewhere around 29,000 net acres there and about 18,000 net acres in Westmoreland County. In Butler, really staying about where it is right now, I think the net there is still about 13,000 acres or so. So that’s where that capital is going. We have essentially ceased leasing about a month ago. We still have some land men out working on rights away and things like that but our leasing program has really winded down. In terms of where we are drilling next year, our plans are to begin in Westmoreland County where we have enough market capacity to immediately put wells in the line as we drill them. We don’t anticipate having any liquids issue there. I think even with the flow rates from our two wells, we can verify that. So that’s where our horizontal program will start in the first half of the year then in the second half of the year we will move the rig to Clearfield and Centre areas.

Jeff Hayden

Okay, great. And jumping back to ASP project, can you just refresh my memory out of the (inaudible) potentially you see there, how much of that was expected to come from Bridgeport and how much was from Cypress?

Benjamin Hulburt

If I recall, it’s about 60% Bridgeport and 40% Cypress.

Jeff Hayden

Thanks a lot guys.

Benjamin Hulburt

Thank you.

Operator

We have a follow-up question from the line of Leo Mariani. Please proceed.

Leo Mariani

Yeah, hi guys. I was hoping again a little bit of an update on the progress of some of the infrastructure you guys are putting into the Marcellus, that’s on track for the end of the year?

Benjamin Hulburt

Yes. What we were looking was bring in a skid mounted plant in Butler County to treat with the liquids. We have had some challenges there. The gas in Butler County has much higher ethane content than usual. So it had to find a plant and design a plant that can handle that ethane. But at this point, it looks like we will have that in by the end of this year. In Westmoreland County, we recently put in a second tap. We will be tapping a third line in that area next year, but that’s the area where we probably have the least amount of infrastructure to place in Clearfield and Centre Counties we planned to tap a Columbia line that runs through our acreage. We've had discussion with them it would appear that they have the capacity to take gas that we are going to need there. But probably it won't have that place till mid next year which is the reason we won't be drilling horizontally there, until the later half of '09.

Leo Mariani

Okay. Could you guys put any sort of members around those three areas in terms of kind of near-term capacity expecting there?

Benjamin Hulburt

Well in Butler County, this initial plant will start at being ahead, we are able to handle about a million cubic feet at day. The tap in the area I believe is sized for 10 million a day. So we have the tap capacity there, but the plant is going to be sized and scale up as we continue to drill there. In Westmoreland County, we have immediate capacity right now about another 5 million a day, which is what these vertical wells are going into. And then we've taken out a nice way to both the Aqua Transline and the Texas Eastern Line. So we have plan to actually tap both of those, which would give us ample capacity for the next several years. In Clearfield and Centre Counties, with the tap on the Columbia line our belief is we could put 15 to 25 million today into that. If we should exceed that in the coming years and the Columbia has they plan on expanding their capacity there. There is also a [Dimini Line] that’s about 11 miles away that they have told us they could put much greater volumes into that as well.

Leo Mariani

Okay, great. Thank you, guys.

Benjamin Hulburt

Thank you.

Operator

At this time, there are no further questions. I would like to turn this presentation back over to Mr. Benjamin Hulburt.

Benjamin Hulburt

Thank you and I would like to thank you all for participating in the call. Before leaving, I'd just like to wrap up by saying that we believe our company continues to be in a very strong financial position, just like the uncertainties in the financial markets. Our solid balance sheet and liquidity will provide us with the ability to move through this difficult industry and economic conditions and this is the clear advantage that I firmly believe, we have over other energy companies of our size.

With that I would like to thank everybody for participating in today's call. Thank you.

Operator

Thank you for your participation. You may now disconnect. Good day.

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