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Executives

Benjamin Hulburt -- President and CEO

Tom Stabely -- EVP and CFO

Analysts

Leo Mariani -- RBC Capital

Phil Dodge -- Tuohy Brothers Investment Research

Marshall Carver -- Capital One Southcoast

Brian Lively -- Tudor, Pickering and Holt

Don Chris [ph] -- Johnson Rice

Rex Energy Corporation (REXX) Q2 2009 Earnings Call Transcript July 31, 2009 10:00 AM ET

Operator

Good morning and welcome to the Rex Energy Corporation Second Quarter of 2009 conference call. I will 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 towards the end of the conference call. As a reminder, this conference is being recorded for replay purposes.

Now, I would now 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 for the second quarter of 2009.

I encourage you to visit the Rex Energy website for the second quarter earnings announcement issued yesterday, which includes important information on forward-looking statements, as well as financial statements and non-GAAP reconciliations. Please note that we routinely post important information about the company under the Investor Relations section of our website.

As I'm sure comes as no surprise to any of you, commodity prices this quarter were much lower than during the same period last year. While the decline in commodity prices from the highs of 2008 certainly had a negative impact on our financial results, I am very encouraged by several key accomplishments we completed during the second quarter of 2009.

First, our production in the second quarter grew to approximately 236,000 barrels of oil equivalent. At first glance, this may appear to be a modest increase in our company's production. However, a closer look shows that our natural gas production grew by 17% over the same period last year as a result of our continued focus on our Marcellus Shale projects. In addition to this growth in our natural gas production, we are able to decrease our production and lease operating expenses by 21%.

Secondly, I am extremely pleased with the exploration and participation agreement we executed with Williams, creating a joint venture that covers our Marcellus Shale acreage in Westmoreland, Clearfield and Centre counties in Pennsylvania. First and foremost, this joint venture shows our continued commitment to maintaining a fiscally-responsible balance sheet by allowing us to share with Williams a very significant percentage of our planned capital expenditures in three of our Marcellus Shale operating areas, especially at a time when natural gas is below $4 an Mcf.

Additionally, given Williams’ significant capability as one of the largest natural gas producers and midstream companies in the country, we believe we will be able to expedite the development of our Marcellus Shale acreage and take advantage of the economies of scale a more robust drilling program can create.

Finally, with Williams taking over as operator of three of our project areas in 2010, the Marcellus Shale team we have assembled can focus their energy on our Butler County project area, which we are continuing to expand. We now have 100% interest in the Butler County project area, after acquiring our 50% partner's interest in that area during the second quarter of 2009, and we are continuing to aggressively lease at this new acreage.

Finally, I am pleased to report our Marcellus Shale horizontal drilling program remains on schedule and we believe the program is beginning to show some very promising results. We completed and put our first horizontal well in Butler County into line during June. Over the last 30 days, the well has produced an average rate of approximately 2. 4 million cubic feet of gas equivalent per day; so far, without any measurable decline.

On July 20, we fracture stimulated our second horizontal Marcellus well. This well is located in Westmoreland County, where we are currently drilling our third horizontal well. The well is currently undergoing flow testing and is expected to be into line August.

At this point, I will turn the call over to Tom Stabely, our Chief Financial Officer, to discuss our financial results, before I go into more detail on our operations.

Tom Stabley

Thanks, Ben. Before I get started, I would like to remind you that the earnings release issued yesterday, which has been posted on Rex Energy's website, contains financial statements, supplemental tables, and non-GAAP reconciliations, which I encourage you to review, if you haven't already.

First, I want to point out that we made a slight change in the presentation of our financials this quarter, dealing with our oil and gas derivatives. In the past, we have included cash settled derivatives under the revenues section of our income statement and non-settled non-cash mark to market income or loss on future period derivatives under the other income or loss section. We have implemented a new policy of recording both settled and non-settled derivatives under other income and have provided a supplemental table to show the cash settle portion in each period.

Revenue the second quarter of 2009 was $11.5 million and cash settled derivatives income was $1.5 million, bringing the total to $13 million. This represented a decrease of 28% from the prior-year quarter, which is predominantly due to lower oil and gas prices during the quarter.

When compared to the second quarter of 2008, our average price for oil, including the effects of cash settled derivatives decreased approximately 35% and our average sale price for natural gas, including the effects of cash settled derivatives, decreased approximately 26%. These operating expenses decreased approximately 21% to $5.2 million in the second quarter of 2009, down from $6.6 million in the second quarter of 2008. These expenses have decreased year-over-year due to cost reduction measures we implemented as part of our continuing plan to reduce our per-unit expenses. These improvements have led to a decrease in lift costs of over $6 per barrel.

General and administrative expenses increased approximately $475,000 to $4.4 million for the second quarter of 2009. This increase is predominantly due to an increase in legal expense accruals.

DD&A expenses for the second quarter of 2009 increased approximately $1.7 million or 35% from $4.9 million in the second quarter 2008. This increase is predominantly due to the downward revision in our proved reserves at December 31, 2008. We calculate our depletion on units of production basis, which accelerated in relation to the reduced projected economic life of our proved reserves using year-end pricing, thus resulting in higher DD&A expenses in 2009.

Exploration expenses during the second quarter of 2009 decreased to approximately $1.2 million from expense of $982,000 for the same period in 2008. This decrease was due to reimbursements from Williams for seismic acquisitions and processing costs associated with our Marcellus Shale joint venture acreage in the Appalachian Basin. We did not incur any dry hole costs during the second quarter of 2009.

Interest expense, net of interest income, during the second quarter of 2009 was approximately $378,000, which is an increase over the $123,000 of net expense recorded in the second quarter of 2008. The increase in net interest expense is primarily due to a decrease in interest income received during the quarter.

We recognized a loss on derivatives of approximately $10.5 million for the second quarter of 2009, as compared to a loss of $73.6 million for the same period in 2008. During the period, we recognized a $1.5 million cash gain -- gain on cash settled derivatives at a $12 million loss on non-cash mark to market adjustments. Our derivatives activities effectively increased our realized prices by $3.93 per barrel on oil, and $2.62 per Mcf of natural gas during the quarter.

Our EBITDAX from continuing operations for the second quarter of 2009 was approximately $4.1 million, as compared to $8.3 million for the second quarter of 2008, representing a 51% decrease.

Since last quarter, we have continued to maintain our strong hedging position by protecting a portion of our cash flow from oil and gas price volatility. Before reviewing our hedging positions with you, it is important to note that all of the estimated hedge production is based on our second quarter exit rate of 2,667 BOEs per day, including estimated average yearly declines, and is not based on our internal projection for future production.

For the second half of 2009, our current oil production is approximately 84% hedged, with an average floor price of $63 per barrel and an average ceiling price of $76 per barrel. Into 2010, we have approximately 85% of our current production hedged, with an average floor of $62 per barrel, and an average ceiling of $79 per barrel. We have now added approximately 24% of our current oil production hedged into 2011, with an average floor price of $65 floor and $100 ceiling per barrel.

On the natural gas side, approximately 90% of our current production is hedged for the second half of the year at an average floor price of $6.70 per Mcf and an average ceiling of $8.40 per Mcf.

In 2010, our current natural gas production is approximately 100% hedged, with an average floor price of $7.10 per Mcf and an average ceiling of $9.60 per Mcf. Due to anticipated production for our first Marcellus Shale horizontal well, we significantly increased our volumes hedged in 2011 to 91% of our current production, at an average floor of $7.30 per Mcf and a ceiling of $12.20.

We also have additional natural gas derivatives contracts in place to cover approximately 34% of our current production in 2012, at an average floor price of six dollars per Mcf and a ceiling of $7.30 per Mcf.

Now, Ben will provide an operational update for the second quarter.

Benjamin Hulburt

Thanks, Tom. Overall, production in the second quarter of 2009 was up 2% from last quarter and 1% over the second quarter of 2008. The increase in production is attributable to a 17% increase in natural gas production, and a 3% decline in our oil production. While we suspended our drilling activity on our oil properties in the first half of the year, which has resulted in the 3% decline in oil production, our Marcellus Shale activities have now produced two quarters in a row of double digit increases, 26% last quarter and 17% this quarter. This is a trend that we hope to continue as our horizontal drilling program continues to pick up speed.

As we mentioned previously, lease operating expenses decreased 21% to $5.2 million when compared to the second quarter last year. This decrease is a result of the continued emphasis we are putting on cost control and reduction with savings mainly being generated from our Illinois Basin. However, we have now begun a period of seasonal maintenance and repair work required to operate our large, mature water flood in the Illinois Basin. The additional work will cause a temporary increase in these operating expenses, but we expect costs to peak well below the high expenses we experienced last year.

With the execution of the exploration agreement with Williams, we have reduced our total capital budget for 2009 from $49 million to $41 million, and with oil prices now back in the $60 range, increased the capital allocated to the Illinois Basin, in order to restart our shallow oil drilling program. Late in the second quarter we began reactivating a number of idle production interjection wells. And in the third quarter, we will start the development of 10 to 15 conventional shallow oil wells. These conventional wells typically have additional production rates between 15 and 30 barrels a day, with average reserves of 12,000 net barrels and average drilling and completion costs of 250,000. So while these aren’t huge wells, the IRR is in excess of 50% at $60 oil. Dry holes are rare, and by drilling a handful of wells, we believe we can keep our overall production for that Basin relatively flat.

Regarding our ASP project work, we have begun a new collaborative effort with the Center for Petroleum and Geosystems Engineering Research at the University of Texas in Austin. To assist us in the technical design work for our planned ASP units, we're very excited about working with the University staff, given their expertise with enhanced oil recovery projects. Going forward, we anticipate completing the technical analysis and design work for our first ASP development unit this year and plan to begin chemical injection in this unit in the first half of 2010. Our initial unit is expected to consist of approximately 140 acres and will target the Bridgeport sandstone.

Additionally, we plan to commence a pilot project during the fourth quarter of this year to test the potential for the use of conformance gels in conjunction with water flooding in the Cypress sandstone. This relatively inexpensive test is designed to demonstrate that we can achieve increased ultimate recoveries in the Cypress sandstone by improving the sweep efficiency of water flooding in this prolific reservoir in the Lawrence field.

Concurrent with this effort, we are working with the University and other consultants to address some of the injection conformance issues we encountered with the Cypress sandstone ASP pilot. Following this technical assessment, we expect to conduct further field testing of ASP flooding in the Cypress reservoir during 2010. Although our tertiary recovered projects in the Illinois Basin are longer term in nature than our Marcellus Shale drilling, we continue to believe very strongly that we hold very significant potential for a substantial increase in our production and reserves in the years to come.

In the Appalachian Basin, natural gas production is at an all-time high, averaging 3.5 million cubic feet per day, annexing the second quarter at 4.1 million cubic feet per day. Our production was limited this quarter due to two factors; in Westmoreland County, ongoing pipeline maintenance on the third party alliance serving our largest natural gas field in the play decreased our production by 15% to 20%. While the maintenance work has temporarily subsided, we expect work to resume. And as a result, we will experience some curtailment, mainly from our shallow gas wells, again in the third quarter.

In Butler County, we currently have four vertical Marcellus Shale wells shut in, pending the activation of our natural gas processing plant. I'm very pleased to report that on Wednesday of this week, we received the air permit for our gas processing plant in Butler County, and we are now in the process of commissioning the plant for start up during August. The plant is initially designed to treat approximately 5 million cubic feet per day. So once startup operations are completed, we expect to be able to flow our horizontal well and the four vertical wells unrestricted. The facility is designed to scale up to approximately 25 million cubic feet per day, which we plan to do in stages over the next couple of years, as we continue to drill horizontal wells in that project area.

We have now completed our first two horizontal Marcellus Shale wells, the first in Butler County and the second in Westmoreland County. We have also commenced drilling the third horizontal well, which is also in Westmoreland County. As a policy going forward, when announcing wells, we plan to issue 30 day average production rates, rather than initial production rates or IP rates, as we believe this to be a more meaningful data point. In addition, as we know more and have a longer period of production, we will continue to update you on the declines we are seeing, so that a type curve can be developed. Given some of the geological differences in each of our operating areas, I would also caution that in all likelihood, it won't be accurate to apply the same type curve for different areas across the play.

The Butler County’s horizontal well was drilled to a depth of approximately 5500 feet, with a lateral extension of approximately 1800 feet. We put the well into production in early June and it has produced at an average rate of approximately 2.4 million cubic feet of gas equivalent per day over the last 30 days, with no detectable decline in production since being put into line.

We're continuing to monitor this well closely to begin to develop a decline curve for that area, but based on the first 50 days or so of production, we are very pleased with what we are seeing. However, at this point, we feel it is too early to try and estimate the reserves or generate a type curve attributable to this well. We are continuing to aggressively lease in the area and are currently in the process of laying out our 2010 drilling program for Butler County. We expect that our 2010 drilling program will focus on longer laterals with multiple well pad drilling.

Our second horizontal Marcellus Shale well was drilled to a depth of approximately 8200 feet, with a lateral of extension of 2000 feet. The well was fracture stimulated two weeks ago, and is currently undergoing flow testing. We are planning to put this well into line in mid-August. This Westmoreland well is the first one to be drilled under the Williams joint venture, and therefore, we are paying for 10% of the cost to drill and complete the well, but will own a 50% interest in the well.

At the end of the quarter, we hold oil and gas lease hold interest covering approximately 80,000 gross and 70,000 net acres in the Marcellus Shale fairway. In the event Williams fulfills their drilling term commitment under the terms of the participation and exploration agreement, our net acreage will be reduced approximately 48,000 acres. We are also continuing to lease additional acreage in each of our operating areas. Although we are still in the early diagnostic stage of our horizontal Marcellus Shale exploration program, we plan to continue to drill horizontal wells in each area, take core samples, run micro-seismic surveys, and acquire new seismic data. We continue to be very encouraged by what we see as a very significant growth opportunity for the company.

Operator, at this time, we would like to open the call up for any questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) We will go first to Leo Mariani with RBC Capital.

Leo Mariani -- RBC Capital

Hi, good morning, guys. A question on the Butler Marcellus well, I guess it has been flowing at 2.4 million a day last 30 days, obviously a pretty good rate. Is that a restricted rate or is that flowing pretty freely?

Benjamin Hulburt

It is hard to tell, Leo. It may be restricted some -- we do have a cap imposed on us. Right now, we're selling gas under a waiver for the Btu level until the plant is turned on. So we have had to control what that well will produce. So it may be curtailed some, and that maybe accounting for why we are not seeing the decline. But what I would caution you, I don't think it is curtailed by half or anything of that magnitude. If it is, it is probably relatively minimal.

Leo Mariani -- RBC Capital

Okay, I guess jumping over to your second well there in Westmoreland, can you give us the drill time and costs associated with that well and kind of what you are seeing really on the flow back?

Benjamin Hulburt

In terms of the cost, that well will be upwards of $5 million, probably closer to $5.5 million. It does include core and micro-seismic work. The other thing is the geology we found in Westmoreland County; on a good note, we found several small faults and indication of a lot of natural fracturing, which could be very good things in terms of a reservoir, but it does slow down your drilling a little bit. The converse is in Butler County, where the drilling is much easier. So I think our drilling in the Westmoreland wells will be a little bit slower, but hopefully that more complex geology leads to higher rates.

In terms of the flowback results that we are seeing, it is still very early in the game; I think we have something like 14% of the water back now, so it is just much too early to really tell what we have. The frac appears to have gone well and we have no reason to believe there is a problem. It is just too early to tell anything. We do expect to get the micro-seismic analysis on that frac back this afternoon actually and then we will have a better idea of how effective was the frac.

Leo Mariani -- RBC Capital

Okay. I guess with respect -- with respect to costs on that well, you guys talked about $5.5 million; obviously, you have got some core and micro-seismic work. Can you talk about your third well in terms of drilling time, if that has been a lot faster as you guys, you got off the learning curve and you expect costs to go down there?

Benjamin Hulburt

It has definitely been faster, yes. I think on every well, we will continue to bring the costs down. I know a lot of other operators that have their costs down to $3.5 million. We aren't at that stage yet, but I see no reason that we can’t continue to make the progress to get there. With two horizontal wells down, we are still very early in that learning curve. And frankly, on your initial wells, cost was not really our focus, but we are moving into that phase and every well seems to get a little bit quicker.

Leo Mariani -- RBC Capital

Okay. Any indications of what Williams plans to do in terms of adding rigs or accelerating activity in the play as we get into the winter?

Benjamin Hulburt

Well, into the winter, we are still the operator. So we don't plan on making any changes from the plan that we have already put out for 2009. Into 2010, Williams takes over as the operator in Westmoreland, Clearfield and Centre counties, but I think they have got to speak for themselves on their plan. What we are anticipating is continuing with that one rig –

Operator

And pardon our interruption, everyone. We have lost our speakers line. If you will just remain online, I will let you know when they rejoin us.

And they will be with us in just a moment. Everyone, please stand by.

Our speakers have rejoined us at this time.

Benjamin Hulburt

Sorry about that, we are experiencing some heavy thunderstorms today and our phone system seems to have gone down. Leo, did you get the end of my answer?

Operator

(Operator instructions).

Leo Mariani -- RBC Capital

When you negotiated with these guys, have they just kind of talked about really trying to ramp this up at some point or not?

Benjamin Hulburt

The intent is that there is a significant ramp up starting in 2011 and I think obviously some of that is spent on our gas prices, but 2010, I think we ramp up hopefully the two rigs in those project areas and then in 2011, that is probably where the more significant move is.

Leo Mariani -- RBC Capital

Okay. And I guess you kind of commented on acreage acquisitions in the Marcellus, terms and kind of where you guys are active, what counties and have you seen prices kind of come down a lot as a result of the weak gas market?

Benjamin Hulburt

We are actively seeing, in each of our operating areas, prices are quite a bit lower than they were last summer. For competitive reasons, I don't like to put out what we are offering, but they are quite a bit lower than the highs that we saw last summer.

Leo Mariani -- RBC Capital

Okay. Thanks, guys.

Benjamin Hulburt

Thanks, Leo.

Operator

(Operator instructions) We will go next to Phil Dodge with Tuohy Brothers Investment Research.

Phil Dodge -- Tuohy Brothers Investment Research

Yes, good morning, thanks. Could you -- two things, discuss in the future how you see capital allocation between the Marcellus and the large project in the Illinois Basin; and actually related to that, is there a maximum that you would be obliged to put into the venture with Williams so that you can control that going forward?

Benjamin Hulburt

Well, two things. Certainly, our major capital focus right now is the Marcellus Shale. One of the advantages I think we have in the ASP project now is the big capital outlay, which was the plant and facility work, is now a (inaudible). So as we continue to add units there, which hopefully get us to the stage where we are proving significant reserves, the capital outlay to do that is now not a very substantial number. So that is the good sense, that we can still be moving that project forward without spending a lot of capital on it. Our intent is that the Marcellus Shale, certainly in 2010, again is a much higher percentage of our total capital outlay. But again, we do think that the ASP can become a very significant asset at this point, without spending a lot more capital on it.

In terms of our intent with Williams, is that after the carry is over, which probably will happen around the end of 2010, that we intend to fund our 50% interest in those project areas.

Phil Dodge -- Tuohy Brothers Investment Research

Could you be in a position where they would want to go faster than you would or vice versa or what provision is there with that in the venture agreement?

Benjamin Hulburt

There are some provisions that allow us to reduce our interest in individual units, with the intent being, you wouldn't get wiped out of the whole play, you could do that in the short term. I think anytime you are a company our size and you partner with a company the size of Williams, your risk is they can go quicker than you, and we recognize that. There certainly is the potential that, we get into the second half of 2010 and they propose 60 wells in 2011, and we have to look at what our capital needs are. I think our attitude is that if that should happen, it is because things have gone very well and it will be a good problem to have.

Phil Dodge -- Tuohy Brothers Investment Research

Okay. Thanks very much.

Benjamin Hulburt

Sure.

Operator

(Operator instructions) We will go next to Marshall Carver with Capital One Southcoast.

Marshall Carver -- Capital One Southcoast

Yes, just a couple of questions from me. Could you give us a feel for the timing of drilling between now and year end, I know you are planning on doing a series of Westmoreland wells. When would you expect those to go online, and when would you be drilling them, between now and year end?

Benjamin Hulburt

Sure, Marshall. Well, the first one, I expect to go online within the next two to three weeks. Basically, our plan is to drill one a month. We have three more to go; we're about halfway through that third one. One a month, and then at this point, we would plan to move the rig to Central Pennsylvania in probably October and begin spudding our first horizontal well there. In terms of modeling, I think the easiest thing is to assume that one well per month comes online.

Marshall Carver -- Capital One Southcoast

Okay, that's helpful. And do you have the -- what was the drill cost on the Butler County well and what would you expect it to be after you not doing as much (inaudible) there?

Benjamin Hulburt

Sure. The Butler County well on this initial one was about $5.5 million. Again, it is the initial well, so it is more expensive, but Butler County, in my opinion, is an area that we should have our lowest drilling costs of anywhere we drill. It is shallower, the geology is much simpler, that is an area that I would anticipate making significant improvements in per well costs if we go forward.

Marshall Carver -- Capital One Southcoast

Okay, that is helpful. Thank you. And could you give us any preliminary guidance on Q3 or are you holding off on that?

Benjamin Hulburt

We still have a hard time issuing guidance, Marshall, because we still don't have type curves for each of these areas. We don't even have one horizontal well in Westmoreland County yet. So it is very difficult for us to issue guidance. I think we are going to have to hold off issuing production guidance until we get at least a horizontal well in each project area, and start to develop an expected type curve and production rate.

Marshall Carver -- Capital One Southcoast

Okay, and the last question. In terms of putting out results on wells, at this point, do you expect to provide rates on the wells that you have forward like the Westmoreland well, we should expect an update on that when you release Q3 results?

Benjamin Hulburt

Yes. Our goal is to put out 30 day average rates and then to continually update the market on the decline curves, so that everyone can generate a type curve for each project area. What we want to avoid is putting out 24-hour initial production rates, because we think they are somewhat meaningless, they can be manipulated, but it is kind of hard to manipulate a 30 day rate. So that is our intent, as we think it is a more conservative and more meaningful data point to give out.

Marshall Carver -- Capital One Southcoast

All right. Well, thank you very much.

Benjamin Hulburt

Sure.

Operator

(Operator instructions) We will go next to Brian Lively with Tudor, Pickering and Holt.

Brian Lively -- Tudor, Pickering and Holt

Good morning, guys. How are things with you all today? Going back to the first horizontal well in Westmoreland, how many frac stages did you put on that well and then, kind of how much propane did you pump away?

Benjamin Hulburt

We did seven stages on the initial Westmoreland well. As far as how much propane is in the water and all that, I don't know that we want to put that out yet, but I will tell you it was a seven-stage frac. Again, we should get the micro-seismic analysis, at least the initial analysis, back this afternoon and be able to analyze how effective we think the frac was.

Brian Lively -- Tudor, Pickering and Holt

And just to remind us, you put the lateral in the Cherry Valley, right, and you frac up and down in the lower and upper Marcellus, is that correct, or –

Benjamin Hulburt

For the most part, we had some steeper dip in this first well than we anticipated. The intent was to keep the well bore in the Cherry Valley. In this part of Westmoreland County, the Cherry Valley is not terribly steep. So parts of it are in the Cherry Valley and then parts went slightly above it. But yes, we intend once to frac up and down.

Brian Lively -- Tudor, Pickering and Holt

Okay, and the 2000 foot, was that your going in planned lateral link, or were you looking to get a longer link than -- kind of how does that play your next well?

Benjamin Hulburt

In this first well in Westmoreland County, the goal was to keep it shorter, because it is the initial well. The well going forward, this is continually have longer and longer laterals move out towards 3000 feet and then see where we are at, but on the first well in the area, we were trying to take a more conservative approach.

Brian Lively -- Tudor, Pickering and Holt

Okay. That is helpful. And on the flowback, I know that it is still kind of early and you said you had only 14% of the water back, but any ideas on say, tubing pressures on that well? Are they pretty strong or is it just too early to tell.

Benjamin Hulburt

They are fairly strong. At this point, we're not seeing anything that is causing us alarm or worry. Obviously, it is very early and we don't know much, but we have no reason to believe, at least from the initial flowback that the frac wasn't fairly effective.

Brian Lively -- Tudor, Pickering and Holt

That is helpful. And finally, just switching gears to Illinois, you mentioned well costs of $250,000 per well. Just give me a sense of how that compares to the same well if drilled back in 2008.

Benjamin Hulburt

Actually, that is the 2008 estimate. To compare back to 2007, both wells would've been about $180,000 apiece. So if we did it today, we may be a bit cheaper than $250,000.

Brian Lively -- Tudor, Pickering and Holt

Okay, that is where I was going. That is all I got. Appreciate all the comments today. Thank you.

Benjamin Hulburt

Thank you.

Operator

(Operator instructions) We will go next to Don Chris [ph] with Johnson Rice.

Don Chris -- Johnson Rice

Good morning, guys. Most of my questions have been answered, but on the Illinois Basin, can you discuss the Bridgeport cuts that -- how they are progressing currently and how pleased are you with the results of that pilot?

Benjamin Hulburt

Sure. Well generally, we learned a lot in the Bridgeport pilot and we are certainly pleased enough to move forward with operational units. What we suspected throughout the pilot was that not all of the oil was breaking out of the fluid that we were getting back. So after we shut down the Bridgeport pilot, we did do some work with some chemical contractors, had gone back in and with an emulsion breaker to try and separate out a greater amount of the oil. And turn the pilot back on. And have seen some very promising results with that additional chemical. That drove the production back up in the pilot fairly significantly, close to what its original peak was, with the intent being that if you went forward, you would use that chemical throughout the process. So that is a very encouraging step and I think an example of how we continue to learn and refine and improve that process. But the long and short of it is, we are comfortable enough with what we have seen that we think it a very good idea to move forward with a larger economical unit and that is what we are working actively on designing now with the University of Texas.

Don Chris -- Johnson Rice

Okay, and just one other modeling question, just to mop up. Can you discuss the G&A expenses going forward? I know you had some extra legal expenses. Was that related to the joint venture with Williams, and should that go away in the third and fourth quarters of this year?

Benjamin Hulburt

The legal expenses in the quarter were the reasons for the G&A jump. It was actually an accrual of what we estimate our legal expenses would be going forward. So the answer is, there should be a one-time event and a decent portion of it was in relation to the Williams deal and then some of it is an accrual associated with some litigation expenses that we have ongoing. So really, it is an accrual estimate and we don't anticipate it being at both levels going forward.

Don Chris -- Johnson Rice

Okay, thanks a lot, guys. Great quarter.

Benjamin Hulburt

Thank you.

Operator

(Operator instructions) We will go next to Phil Dodge with Tuohy Brothers Investment Research.

Phil Dodge -- Tuohy Brothers Investment Research

Yes, good morning again, circling back. Just wondering whether you are at the point on the first well in Centre Pennsylvania, where you know the depth and how long a lateral should be.

Benjamin Hulburt

Well, we haven't drilled a horizontal well in Central Pennsylvania yet.

Phil Dodge -- Tuohy Brothers Investment Research

Yes, but when you move there for the first well later this year.

Benjamin Hulburt

Sure, again, I think the initial well will probably be around 2000 to 2500 feet deep, because the dam is a new area and we think we ought to start by walking before you run. We do know the depth. We have done a fairly extensive seismic shoot throughout that acreage. One of the challenges in Central Pennsylvania is there are some large across faults, that can get you into trouble. So we wanted to shoot it all seismically, before drilling horizontally and all of that work is done. So we --

Phil Dodge -- Tuohy Brothers Investment Research

Am I right that the Marcellus is generally thicker on your acreage there than in Westmoreland County?

Benjamin Hulburt

Yes. Our stuff in Central Pennsylvania should be almost twice as thick as what we see in Westmoreland County. It is a little bit deeper and certainly much cheaper. I think the properties in Central Pennsylvania are lower than what you would see in southwest Pennsylvania. So that is kind of the trade off, it is thicker, but it is slightly lower (inaudible).

Phil Dodge -- Tuohy Brothers Investment Research

Okay, and then finally, I was hoping somebody else would answer this, but I guess I will have to -- how are you gaining the chances of a severance tax passing the Pennsylvania legislature at this point?

Benjamin Hulburt

You know, I think I will hold off on answering that publicly. There are a lot of politicians that are talking about that and the industry has their opinions. So I think that is one I will decline answering on.

Phil Dodge -- Tuohy Brothers Investment Research

I think I know your opinion. Just wondering how it looks in terms of the outcome.

Benjamin Hulburt

Again, I think I will hold off on giving my prediction on that.

Phil Dodge -- Tuohy Brothers Investment Research

Okay, thanks very much.

Benjamin Hulburt

Thank you.

Operator

At this time, there are no further questions. I would like to turn the conference back over to Mr. Benjamin Hulburt for closing remarks.

Benjamin Hulburt

Thank you, everyone for participating in Rex Energy’s second quarter conference call.

We have several upcoming events I would like to make you aware of. We will be presenting at Enercon’s 2009 Oil & Gas Conference in Denver on August 10, the Rodman & Renshaw Annual Global Investment Conference in New York City on September 9 through September 11, the IHF Herald Pacesetters Energy Conference September 22 through September 24, IPAA’s West Coast Oil & Gas Symposium in San Francisco at the end of September, and Johnson Rice's Conference in New Orleans on October 6.

Thank you again for participating.

Operator

Thanks, everyone. That does conclude today's conference. We thank you for your participation.

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Source: Rex Energy Corporation Q2 2009 Earnings Call Transcript
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