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Rex Energy Corporation (NASDAQ:REXX)

Q4 2009 Earnings Call Transcript

March 3, 2010 10:00 am ET

Executives

Benjamin Hulburt – President and CEO

Tom Stabley – EVP and CFO

Analysts

Jeff Hayden – Rodman & Renshaw

Mike Scialla – Thomas Weisel Partners

Derrick Whitfield – Canaccord Adams

Don Crist – Johnson Rice

Raymond Deacon – Pritchard Capital

Jack Aydin – KeyBanc Capital Markets

Leo Mariani – RBC Capital Markets

David Heikkinen – Tudor, Pickering, Holt

Richard Rossi – Wunderlich Securities

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Rex Energy fourth quarter and year-end 2009 conference. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time.

(Operator Instructions) As a reminder this conference is being recorded. I would now like to introduce your host for today, Mr. Benjamin Hulburt, President and CEO. Sir, please go ahead.

Benjamin Hulburt

Thank you. Good morning, and welcome to Rex Energy Corporation’s conference call to discuss the results from the fourth quarter and year end 2009. As we announced in the earnings release issued yesterday after the market closed, we are incorporating slides with the call this morning. For those of you who have dialed-in, I encourage you to access those slides now, if you can, on the Rex Energy website. If you are listening in via the webcast, you will see those slides in the webcast window.

With that I will start the presentation on slide three. Fourth quarter of 2009 was a strong finish for Rex Energy and contributed to an overall year of breakings for the company. Our proved reserves at year end nearly doubled and we were placed over 400% of our 2009 production. Year-over-year, the company’s production increased 3%, which was attributable to a 46% increase in natural gas production and offset by a 7% decline in our oil production. Our Appalachian Basin team has now successfully drilled and completed seven horizontal wells to date, which have averaged 3.1 million cubic feet of gas equivalent in the first seven days of production with an average estimated EUR of 3.2 Bcfe per well.

Our natural gas production from the Marcellus Shale continues to be the driving factor behind quarterly production growth. In the fourth quarter, natural gas and natural gas liquids production increased 91% compared to the same period in 2008 and 25% over the third quarter of 2009. We exited the fourth quarter with natural gas production up 69% and overall production up 7% when compared to 2008 active rates.

Two months into 2010, we are already off to a tremendous start. Since January, we increased our Marcellus Shale acreage 15% and now have approximately 68,700 net acres leased in the Pennsylvania fairway. With the completion of our January equity offering, we currently have approximately $50 million in cash and are full $80 million borrowing base available. Our capital budget of $100 million to $140 million depending on additional Marcellus acreage and our 2010, drilling program should increase company production 50% to 80% year-over-year in 2010.

Moving to slide four, our proved reserves, which are summarized on slide four were evaluated by Netherland, Sewell & Associates as of December 31, 2009. We saw an increase of 90% to 125.2 bcfe, of which 55% were oil and NGLs. As mentioned earlier, we replaced over 400% of our production in 2009. Our all-in F&D cost excluding acreage average to $1.32 per mcfe and $1.60 per Mcfe including acreage cost.

In addition, to our proven reserves calculated using SEC pricing, we had Netherland prepare our reserves using two alternative pricing scenarios. First, a flat case using last year’s rule of December 31 pricing, and secondly a NYMEX case using forward strip prices as of December 31. As shown on the slide, our proven reserves under these scenarios would rise to approximately 138 and to 142 bcfe respectively. We did not book any proved undeveloped locations outside of the SEC’s five-year limitation in any of the scenarios.

Slide five presents a breakdown of our 2010 capital budget allocation, and outlines the major projects planned for the year. The majority of our capital budget is directed towards Marcellus Shale drilling, leasing and infrastructure development in 2010.

By far the largest line item of our capital budget is for our Marcellus Shale drilling to run two rigs across our three project areas, and to drill 19 gross horizontal Marcellus Shale wells. As briefly mentioned earlier, our initial capital budget is $100 million, however, we are continuing to aggressively lease additional Marcellus Shale acreage in select areas, and will adjust our capital budget upto $140 million if we are able to continue to lease at terms we consider to be reasonable in our main project areas.

Our second largest planned use of capital in 2010 is for the continued Marcellus Shale midstream development. The $20 million allocation will cover both the shared gathering system expense with Williams in Westmoreland in Central PA as well as our contribution to Keystone Midstream, our joint venture in Butler County, PA, covering the construction of a cryogenic gas processing plant and associated gathering lines.

In Illinois, we will be drilling 10 to 15 conventional oil wells to offset the natural decline of our field as well as spending approximately $6.7 million for field and well maintenance. Finally, we have allocated $7.9 million for Illinois tertiary recovery projects, of which the majority is for the Middagh Unit, our first field unit that will target the Bridgeport Sandstone using ASP chemicals.

On slide six, we have presented our daily production in commodity pricing quarter-by-quarter for 2009. During the fourth quarter, we realized a net oil price of $72.37 per barrel before the effects of cash settled derivatives. The net oil price after cash settled oil derivatives was slightly decreased by the effect of our derivatives resulting in a net exact – effective price per barrel of $66.44. This represents an increase of approximately 5% of the previous quarter and 6% higher than the same period in 2008.

For the fourth quarter natural gas prices, we realized a price of $4.55 per Mcf before the effects of derivatives. The natural gas price after cash settled natural gas derivatives was increased by the effects of these derivatives by $1.64 per Mcf resulting in an effective price of $6.19 per Mcf. This represented a slight decrease of 2% from the previous quarter and a decrease of 21% from the same period in 2008.

As you can see on slide seven, our operating revenue grew by 18% over the previous quarter to $15.3 million. We record the effects of our derivatives on their other income – under the other income section of our income statement as gain over the loss on derivatives, net. This includes both the cash settled derivatives as well as the non-cash mark-to-market on the remaining positions. When taking into account, the cash settled portion of these derivatives for a loss of approximately $300,000, our revenue would have been approximately $15 million for the quarter.

Lease operating expenses in the fourth quarter grew over the previous quarter, due predominantly to regular field maintenance in our Illinois Basin operations. G&A expenses increased 75% from the previous quarter; this is largely due to $925,000 accrual made in conjunction with the expected settlement of a hydrogen sulfide related lawsuit in the Illinois Basin.

Fourth quarter 2009, G&A was 14% higher when compared to the fourth quarter of 2008. DD&A in accretion in the fourth quarter was approximately 11% higher than the previous quarter at approximately $4.30 per Mcfe. Going forward, we project our DD&A in the first quarter of 2010 to be approximately $3.00 per Mcfe. Excluding the $925,000 legal accrual, our EBITDAX increased by 4% over the previous quarter due to our increased production, but were 6% below the same period in 2008 due predominantly to the lower commodity prices.

Finally, our cash flow from operating activities in the fourth quarter increased to its highest level of the year to $8 million, a 25% increase over the previous quarter.

During the fourth quarter, we layered on additional hedges for both oil and natural gas, as you will see outlined on slide seven. The percentage of production hedged is shown as a percentage of our annualized December 2009 production. On the oil side, we continue to add hedges in 2010 and 2012. While our natural gas production continues to grow, as of the fourth quarter 86% of our revenue is still derived from oil sales. So we feel it is important to protect that cash flow as much as possible.

On slide nine, we have shown our 2009 liquidity by quarter. When comparing the fourth quarter 2009 to the previous quarter, you can see that we continue to maintain a conservative balance sheet through the end of the year with an $8 million increase in debt and a 19% increase in cash. Our $80 million borrowing base is currently being re-determined, and we should be able to announce that reaffirmation in any increase in the next few weeks. We anticipate our borrowing base increase to approximately $100 million at that time. The balance on the Williams carry in our Marcellus Shale joint venture was $18.4 million at the end of 2009.

Again in the Williams joint venture areas, we are paying only 10% of the cost to drill and complete the wells until the carry balances net. However, we own 50% of the wells. At the end of January 2010, the Williams carry balance was down to approximately $16.6 million, which is just under half of the $33 million beginning balance. We anticipate that the carry balance will be met during 2010. In January, we completed a $6.9 million share equity offering, which resulted in net proceeds of approximately $80.2 million. After paying out various operating expenses and the $23 million, we had drawn on our borrowing base at the time; we have approximately $50 million of cash and no long-term debt.

On slide ten, we’ve laid out a range on production guidance for 2010. The assumptions are based on the 2010 capital budget plan with the cryogenic gas processing plant in Butler County, Pennsylvania, becoming operational in October of 2010. The only difference between the low case and the high case is the assumed 30 day average rate for our Marcellus Shale wells. The low case assumes 1.8 million cubic feet of gas per day and the high case assumes 3 million cubic feet of gas per day.

As we announced in our press release last night, excluding two of our initial test wells, our horizontal wells to date produced an average of 3.1 million cubic feet of gas per day during the first seven days. So we feel good about our assumed range of production on our Marcellus wells and our production guidance for the year in the range of 57% to 79% over 2009 levels. Since nearly all of our production growth from our 2010 Butler County Marcellus wells will be realized in the fourth quarter when we complete the cryogenic plant, our projected 2010 exit rate is expected to be much higher and could range from 87% to 142% over our 2009 exit rate.

On slide 11, we show a four-year projection of our production. While there are many uncertainties associated with such long-term projections we believe our assumptions used in these projections are reasonable. For these projections, we took the same assumptions from 2010, but added one additional rig in the Marcellus region and five conventional oil wells a year starting in 2011.

In this scenario, Rex Energy could realize a compounded annual growth rate between 42% and 56% over the next four years. Daily production by year end 2013 will be roughly 60 million to 90 million cubic feet of gas equivalence per day, which is approximately 3.5 to 5.5 times our 2009 company daily average production. We believe there is additional upside in both basins to the projections we have laid out. In the Appalachian Basin, if we or Williams add more rigs than we have assumed or if the horizontal wells exceed 3 million a day, 30-day rates in the high case, we could realize a higher production growth rate. In the Illinois basin we have only included the production from the first 33 acre ASP unit.

On slide 12, I walk through the current status and 2010 plan for each of our three Marcellus Shale project areas. Starting in Butler County Pennsylvania, I am pleased to announce that we have increased our acreage in that project area to approximately 39,000 acres. We have finished drilling our first two horizontal wells of the 2010 program, which were drilled in less than 21 days per well, about half the time of our average in 2009. We are scheduled to simultaneously fracture these wells in March. Since we are using a vertical rig to work ahead of our horizontal rig in Butler County, we are currently drilling our third and fourth wells in the 2010 program.

The Butler County wells in 2010 are expected to have an average lateral length of 3,000 to 4,000 feet. Progress on the Sarsen plant, our joint venture cryogenic plant is currently on track to become operational in the fourth quarter of this year. We’re working through the permitting process with state and local governments, which will need to be completed before we can began installation of the plant.

Moving down into Westmoreland County, we now have six wells drilled and completed, and are currently drilling our seventh well. We are currently slow testing our six well in the project area, which has a lateral length of approximately 2,100 feet that has averaged approximately 3.3 million cubic feet of gas per day over the first 14 days of testing. We are also currently drilling one well and plan to drill one additional well before releasing our rig.

Williams, our joint venture partner in the area will be performing the fracture stimulations on these two wells and expect to have their HP4S plus flex rig in the county by the end of March. Between Williams and Rex Energy, we expect to drill and complete eight to 12 wells with lateral lengths averaging 3,000 to 4,000 feet in this project area during 2010.

Finally, in Central Pennsylvania, our acreage has increased to 17,000 net acres. Predominantly through an acquisition of a 3,000 acre tract that is held by production from shallow wells on the Center and Clinton County borders, which was outside of the Williams JV areas.

Our two other Run wells are drilled and completed and shut in awaiting a pipeline from our tap on the Columbia 1711 line, which we expect to be complete in early April. We expect those wells to produce between 5 million and 7 million cubic feet per day into line collectively.

As you can see on the table summarizing our Marcellus well to date, we have drilled wells with an average lateral length of approximately 2,200 feet, which have resulted in an average gross EUR of 3.2 Bcfe for approximately $4.6 million per well.

As we have continued to refine our process, we decreased our drilling time to less than 21 days on our first two wells in 2010, and extended our lateral lengths to in excess of 3,000 feet. As a result in 2010, we believe our wells will not only result in even higher recoveries due to the increased lateral lengths, but also at lower cost per well. In 2010, we are budgeting our wells to cost approximately $4 million per well.

To wrap up, the Marcellus Shale potential on slide 13, we put together a rough estimate to try and illustrate the future reserve potential from our current 68,700 Marcellus Shale acres. To start we have assumed that only 75% of our net acreage will be drilled on 80-acre well spacing, which is the spacing we are currently using. This gives us 644 potential net risk well locations. Next, we use a range of estimate for the ultimate recovery per well to get a low, mid and high case.

As you saw on the previous slide, our EURs are currently averaging slightly higher than the mid case. After deducting an average 15% royalty and the 54 Bcfe we already booked as proved reserves attributable to the Marcellus shale we calculate a reserve base of between 1.3 and 1.9 Bcfe. Therefore, we have the potential through the development of our Marcellus acreage to increase our reserves in the coming years by 11 to 15 times our current proven reserves dives of 125.2 Bcfe.

In the Illinois Basin, we have staring the field work for our Middagh Unit which will be our first field size alkali-surfactant-polymer flood unit in the Bridgeport Sandstone. The unit will be comprised of 12 chemical injection wells, 6 producing wells, ranged as six contiguous five spot [ph] patterns with two peripheral water injection wells. The wells are currently being drilled and we are on schedule to commence chemical injection late in the first half of this year.

We expect to see an initial production response from the Middagh Unit four to eight months after we commence injection and expect to hit peak response from the unit 10 to 12 months after we commenced injection. The University of Texas has completed their laboratory core flood test for chemical recipe optimization. The Laboratory ASP flood test using the final recipe was able to recover 90% of the residual oil in place after water flooding. This recovery rate is extremely encouraging as we move closer to beginning injection in the Middagh Unit. However, I would like to caution you that this is the recovery in laboratory testing and we do not expect to receive or to achieve recoveries as high as that in the field.

Before I open the call for questions, there are a couple of upcoming events Rex Energy will be participating in that I would like to point out. We will be at the IPAA Oil and Gas Investment Symposium in New York with a company presentation on April 14th. Then, on April 20 we will be on a panel at Hart Energy’s Marcellus midstream conference in Pittsburgh, Pennsylvania to discuss our Keystone Midstream joint venture.

Thank you again everyone for joining us on this conference call this morning. We’ll now open the call up for questions.

Question-and-Answer-Session

Operator

(Operator Instructions) Our first question is from the line of Jeff Hayden of Rodman & Renshaw. Sir, your line is now open.

Benjamin Hulburt

Good morning, Jeff.

Jeff Hayden – Rodman & Renshaw

Hi, Ben, I’m wondering if you can give us a little more color on the well cost side of things. Looking at the wells you’ve drilled thus far in 2010, on those two Butler wells, and then the recent Westmoreland well, what kind of AFEs and lateral links did you do on those?

Benjamin Hulburt

The AFEs that we have for all of the 2010 wells are right around 4 million, I think in Butler we are bated about 3.9. And the difference in the cost savings is mostly the increase or the shorter drilling time. In 2009 we averaged 40 to 50 days per well, we now got that down to about 20 days. We are also using in Butler, in fact a different rig than we had in Westmoreland during 2009, that has a rig rate associated with it. It’s about 20% below what our previous rig was in 2009.

Jeff Hayden – Rodman & Renshaw

Okay, great. I appreciate that. And then looking at the CapEx, talking about possibly taking it up another 40 million for land acquisitions, so that would leave about 55 give or take for the year. If you were to spend that much, where do you think your net acreage would end around yearend or what would kind of be your target number for that kind of spending and, where would the focus area would be, would be more Butler or kind of spread throughout your three core areas?

Benjamin Hulburt

Sure. Well, with that kind of capital, we would expect to be adding as much as 20,000 more acres during the year. And again, we are only going to do that if it’s at a dollar per acre that we think is reasonable, and for competitive reasons we don’t like to release what that is. If the acreage cost grows too high, it’s our feeling that it would be better for us to just stop put some more capital into drilling.

As far as what our focus areas are – it’s really all three of our current project areas. Williams is predominantly managing the leasing in those two joint venture areas and they are active releasing in both. So, a portion of the capital, we would expect to be spent there, and then we are continuing to aggressively add acreage in our popular project area.

Jeff Hayden – Rodman & Renshaw

Okay, and then one last one and I’ll jump off. Looking at the second – where you guys drilled in Clearfield, it looks like that one had a much shorter lateral than the first well, any color on why that one was drilled into shorter lateral?

Benjamin Hulburt

It was really just leased line limitations as opposed to any technical reason. That second well looks like a pretty decent well, it’s not as strong as the first one, but it’s about 500 to 600 foot shorter which basically means we lose about two stages because of the shorter lateral.

Jeff Hayden – Rodman & Renshaw

All right, I appreciate it.

Operator

Thank you. Our next question is from the line of Mike Scialla of Thomas Weisel Partners.

Mike Scialla – Thomas Weisel Partners

Good morning, Ben.

Benjamin Hulburt

Good morning, Mike.

Mike Scialla – Thomas Weisel Partners

Wondering if you could help us with the decline curve that you are seeing projecting for that 3.2 Bcf average, maybe will tell a final decline that assumes in the reserve life of those wells?

Benjamin Hulburt

Sure. The decline curve that we are using right now assumes about a 70% to 75% decline in year one and then goes from there down to about a 6% terminal decline. I don’t think that the wells that we have to date are declining quite there rapidly but it’s too soon for us to change our assumed decline rate but at this point it’s still 30 [ph] feet.

Mike Scialla – Thomas Weisel Partners

And how is the north well doing now, what’s the curve rate on that, can you say?

Benjamin Hulburt

It’s an online for – I believe about 280 days and at this point it’s probably declined 10% to 15%.

Mike Scialla – Thomas Weisel Partners

Great. Okay and can you give some rates on those other Westmoreland wells, idea the 2H, 3H and the Eaglehouse 5H well?

Benjamin Hulburt

Sure, well again, we are trying to get out of the habit of releasing every single well we drill, the two Pennsy wells were slightly below the 3.1 million average and the Eaglehouse 5 well, like I said in the call, it’s slightly above the average.

Mike Scialla – Thomas Weisel Partners

Got you. Okay. And one on just housekeeping, that $8 million cash flow from operations in the press release, so was that before working capital or after working capital changes?

Benjamin Hulburt

That is the four working capital changes.

Mike Scialla – Thomas Weisel Partners

And do you have some of those changes>

Benjamin Hulburt

I don’t right now. If you call Tom after the call we’d be happy to get to that.

Mike Scialla – Thomas Weisel Partners

Well then thank you.

Benjamin Hulburt

Thank you.

Operator

(Operator Instructions) Thank you, sir. Our next question is from the line of Derrick Whitfield of Canaccord Adams.

Derrick Whitfield – Canaccord Adams

Good morning guys.

Benjamin Hulburt

Good morning.

Derrick Whitfield – Canaccord Adams

Just maybe taking a step back on the Westmoreland area, could you maybe talk about or shed some more color on what you've learned with some more recent wells? What it's telling you about the geology that you did, maybe have before?

Benjamin Hulburt

Sure. I think on the drilling side, other than continuing to push to go longer and longer on the lateral – we feel we have nailed down where to land that lateral and a good drilling procedure, so that the only change we think we need going forward on the drilling side is to continue to go longer.

On the completion side, I think with only six wells to do – but only have done six wells, there is obviously more work to go. I think we are going to continue to experiment with more stages with different perforation clusters, and also with a different pumping rate. There is still more experimentation to be done as to whether a lower pumping rate would result in the fractures propagating out further rather than going more vertical, which seems to the case for the higher pumping rate. And I think that’s just going to take more wells to continue to optimize.

Derrick Whitfield – Canaccord Adams

Thanks. That's great. And then changing gears on the ASP project. That test that you guys mentioned with UT, that was a radio test, wasn’t it?

Benjamin Hulburt

That was a core flood test; yes, a radio core flood test.

Derrick Whitfield – Canaccord Adams

Terrific. And then any color on maybe why you guys are going with the five spot here versus the line drive?

Benjamin Hulburt

It really is just a result of the reservoir simulation. As you know, we’ve built an extremely expensive three dimensional model of that field, using about 5,000 well logs. And after running the simulation with the finalized chemical recipe, this is the pattern that our engineers and I think Netherland’s engineers and UT felt would give us the best recovery.

Derrick Whitfield – Canaccord Adams

Terrific. That sounds like that’s progressing nicely. And then on the conformity – the tests that you guys were conducting during the fourth quarter, any updates on that?

Benjamin Hulburt

Not yet. The project is continuing. We’ve completed tracer surveys and are beginning the process injecting the gel. So, I think it will be several months that we can really tell how that project is working. And that one is, I think, admittedly more experimental than ASP flooding but it could have some very nice implications for us.

Derrick Whitfield – Canaccord Adams

Thanks, Ben.

Benjamin Hulburt

Welcome.

Operator

Thank you. Our next question is from the line of Don Crist of Johnson Rice.

Don Crist – Johnson Rice

Good morning, guys.

Benjamin Hulburt

Good morning.

Don Crist – Johnson Rice

As you move rigs around the play, can you just talk about how far you think you’ve advanced in the actual signs of having longer laterals and etc and track busters and how far do you think you still have to go or do you think you are pretty close to get into an abdominal [ph] recipe?

Benjamin Hulburt

I think we’ve advanced tremendously far to be kind of hitting our mid case 3 bcf reserves on a consistent basis. However, I think we’re probably only still 25% of the way there. There are several of our peers that are drilling in areas that are close to us that have well reserves that exceed ours, in most cases there are 100 wells or more into their program. So at this point, we are only nine wells into the Marcellus Shale horizontal program, which obviously is not a very big statistical base. So, we believe that our 3 bcf well to date is really just the beginning.

Don Crist – Johnson Rice

Okay, great. And just a couple of housekeeping items, as three-year LOE jumped up in the fourth quarter little bit, is that weather related at all or was that actually something else attributed into that?

Benjamin Hulburt

I think it’s less weather related and more related to – barring 2009, the early part of 2009 when the economy was suffering drastically, we cut back on every discretionary field maintenance project and restricted [ph] our cash flow. So as commodity prices rose, we’ve released some of that capital back to the basins as they go back and catch up on some of that work.

Don Crist – Johnson Rice

Okay, so going forward we can bring that down quite substantially from the fourth quarter number?

Benjamin Hulburt

That work is probably still going on in the first quarter. So, we are internally projecting first quarter – these operating expenses to be generally in line with where our fourth quarter was. After that, I think, we should have caught up on most of that work and we will hope to see them return back down their lower levels.

Don Crist – Johnson Rice

Okay, that’s but all I got. Thanks a lot, Ben.

Benjamin Hulburt

Thank you.

Operator

Thank you, sir. Our next question is from the line of Ray Deacon of Pritchard Capital.

Raymond Deacon – Pritchard Capital

Yeah. Hey, Ben, I was wondering if you could just go over what the drivers were between the reductions and drilling days from 40 to 50 to 20, is it rotary steerable tools or just more experience or…?

Benjamin Hulburt

I think it's a combination of more experience different mud programs, different bits, as well as the last two wells in Butler County, as we’ve kind of consistently said, the geology there is much less complex than some of the other areas that we have. So we’ve always believed that we’d be able to drill quicker and cheaper there, and that showing to be true. We have new rotary steerable tools on only one well and didn’t really find it to be much of a difference for us.

Raymond Deacon – Pritchard Capital

Okay. Got it. And is, I mean, has Williams fully taken over operatorship in Centre, Clearfield and Westmoreland, and do you get any sense that they would be looking to expand their activity or the pace, and what could you financially handle internally I guess as far as, I was thinking you could go to two rigs with them but beyond that you might need some external financing, is that – is that fair?

Benjamin Hulburt

Well, the answer to your first question is they have not taken over as operator yet. There is a constant communication line between the two of us, and their first operating activity will really be to fracture stimulate the two wells that we’re drilling in Westmoreland County currently.

Raymond Deacon – Pritchard Capital

Right.

Benjamin Hulburt

And then after that we will release our rig there because it will have fulfilled this commitment, and they are brining in the flex rig.

Raymond Deacon – Pritchard Capital

Got it.

Benjamin Hulburt

So the next two wells we’ll drill and they’ll frac, and then after that they should have assumed operations in both areas.

Raymond Deacon – Pritchard Capital

Okay.

Benjamin Hulburt

And to the activity level, in talking to them at least I think with the current – the current plans are to continue to run that flex rig with maybe a possibility of a second rig in the fourth quarter.

Raymond Deacon – Pritchard Capital

All right.

Benjamin Hulburt

And it looks like our assumption in 2011 is most likely two rigs, one in Westmoreland and one’s our Central PA with some possibility of a second rig in the Central PA.

Raymond Deacon – Pritchard Capital

Okay.

Benjamin Hulburt

As to our ability to fund and keep up, I think that’s a very big part of why we thought it was important to complete the equity raise that we did. With the amount of cash that we have on hand now and zero debt, with an availability of a borrowing base that we expect to continue to grow, as we continue to drill wells, and combined with that what we expect our cash flow to grow to in 2011 should allow us to access more favorable long-term debt than we have been able to in the past. So we are speaking internally any way is that as we continue to grow our cash flows at some point we will to be able to access the bond market that previously wasn’t available to us.

Raymond Deacon – Pritchard Capital

Got it, great. And just one more I think I have written down your average Marcellus horizontal you were able to book 3.6 BUs [ph] in your yearend reserve, is that about rate?

Tom Stabley

The average was about 3.2.

Raymond Deacon – Pritchard Capital

3.2, okay.

Benjamin Hulburt

Other county well was closer to 3.6.

Raymond Deacon – Pritchard Capital

Okay. Got it. So, I mean it seems a little conservative given that you drilled two 2100 foot laterals and you booked 3.2 and if you go to 3 to 4, I would think you would be hoping to do better than 4 BUs, net but on a –

Benjamin Hulburt

Obviously we had hoped to but the pro (inaudible) so until we do that I think we will hold off make changing our assessment.

Raymond Deacon – Pritchard Capital

Okay. Got it. Thank you, very much.

Benjamin Hulburt

Thank you.

Operator

Thank you, sir. Our next question is queue is from the line of Jack Aydin of KeyBanc Capital Markets.

Jack Aydin – KeyBanc Capital Markets

Hi, Ben.

Benjamin Hulburt

Good morning, Jack.

Jack Aydin – KeyBanc Capital Markets

Did I hear you right that in Westmoreland the six-well – progressive 3.1 million?

Benjamin Hulburt

Actually it’s – so far I think it has been tested for about 14 days and it has averaged about 3.3 million.

Jack Aydin – KeyBanc Capital Markets

Okay.

Benjamin Hulburt

And the well had pressure on, it looks pretty good. So it looks like a pretty strong well.

Jack Aydin – KeyBanc Capital Markets

Okay. Do you care to comment on what you paid for that 3000 acre in Central PA?

Benjamin Hulburt

I don’t but it’s far less than what acreage sales in that area have gone for recently.

Jack Aydin – KeyBanc Capital Markets

Okay. DD&A, you mentioned that first quarter should be around 3 down from 4.30. Could you explain to me why it’s down so much or why fourth quarter up so much? And also, what do you think the DD&A rate for the balance of the year should be?

Tom Stabley

Hey, Jack, it’s Tom. The reason the DD&A rate goes down in the first quarter is other successful efforts we re-input the new reserve amounts, with oil coming back on the books for most of the Illinois field that extends the life of those that brings down the DD&A rate. So, the expectation is that would be rate for most of 2010 until you do the next reset which is in the fourth quarter of 2010.

Jack Aydin – KeyBanc Capital Markets

Okay. And final question on G&A excluding that 925 it was little bit on – I thought it was on the high side, did you hire a new and more people or what caused that?

Benjamin Hulburt

We have continued to higher – I think field level staff. We haven’t made any significant hires more on the executive level side.

Jack Aydin – KeyBanc Capital Markets

Okay. Thanks a lot.

Benjamin Hulburt

Thank you.

Operator

Thank you. Our next question is from the line of Leo Mariani of RBC Capital Markets.

Leo Mariani – RBC Capital Markets

Good morning guys.

Benjamin Hulburt

Good morning.

Leo Mariani – RBC Capital Markets

Sorry if may have missed it, but you talked about drilling the last couple of Butler wells in 20 days, what’s your sense of the impact on cost as a result of lower drilling times there?

Benjamin Hulburt

I think one of the better answer to that as the bills come in on these two wells, I’d think we got a good shot of being below that $4 million number, drilling the wells at the pace we did, because that’s less than the assumption we used when we prepared the AFEs, but the majority of the cost still remains is the frac itself. So until those are done, we won’t be able to see really how we’ve come in. But if anything I think we’d probably be a little ahead of our budget at this point.

Leo Mariani – RBC Capital Markets

Okay. And with respect to your budget in ’10, you guys were talking about the 10 wells, now you’re drilling them faster, if you continue with that rate, 20 days a well here, how many wells do you think you can possibly drill here in ‘010?

Benjamin Hulburt

If we continue at that rate, we could maybe get 15 done rather than 10, and we will do that. At some point we are going to hit the limiting capacity of the Sarsen cryogenic plant, which is 40 million a day. But I think that would be a high class problem to have. We are starting to do a preliminary work in analyzing when and where we’d need a second plant, but for 2010 our objective is to drill as many horizontal wells as we can, and if we need to adjust the capital budget upwards when we get to that point we would do so.

Leo Mariani – RBC Capital Markets

Okay. And I guess your cryo plant there is still on track for roughly October startup?

Benjamin Hulburt

It is, we’ve had several meetings with state and local governments, at this point all are going very well. So we are very pleased with the progress to-date, and at this point don’t see any reason that we won’t be on schedule.

Leo Mariani – RBC Capital Markets

Okay, thanks guys.

Benjamin Hulburt

Thank you.

Operator

Thank you. (Operator Instructions) Our next question is from the line of David Heikkinen of Tudor, Pickering and Holt.

David Heikkinen – Tudor, Pickering, Holt

Good morning guys.

Benjamin Hulburt

Good morning

David Heikkinen – Tudor, Pickering, Holt

As you think about each of the areas, Butler, Central and Westmoreland, and thinking about acreage configuration, I mean, what is your ability to drill the longer laterals, are there really any areas that have more blocky acreage where it's easier to do or areas where you need to continue to block up acreage so you drill the longer lateral?

Benjamin Hulburt

Sure. If I had to rank them, David, Central PA is the easiest for us. We have some very large five and 6,000 acre tracks that are actually contiguous to each other. So that would be the easiest. After that I’d probably say Westmoreland, and third would be Butler. Butler, the nature of the tracks there tends to be smaller, and that’s the reason that we continue to infill lease heavily in that area.

David Heikkinen – Tudor, Pickering, Holt

Okay. So as you think about each area then, and kind of thinking this reserve per well question and number of frac stages, targeting three or 4,000 for laterals, should we think about the Williams joint venture rig drilling closer to 4,000 and maybe in Butler you are probably going to be more than 3,000, so you should see a bit of divergence in at least higher EUR heading forward in Central and Western?

Benjamin Hulburt

No, the wells that we have permitted in 2010 average between 3,500 feet and 4,000 feet.

David Heikkinen – Tudor, Pickering, Holt

Okay.

Benjamin Hulburt

So we are pushing the envelop there. Geologically and from a technical perspective pushing the laterals longer and Butler is the easiest of the three areas. It’s shallower and the geology is less complex. In terms of the EUR, we have a limited data set in Butler County, but I think especially because of the liquid sales we feel that, that has the potential to be the highest EUR in three projects which the first well we did there certainly bears that out. By our estimation becomes of the liquid sales the IRR in the Butler County wells potentially to be about 10 percentage points higher than the dry gas areas. But we expect to receive about 1.8 gallons of liquid propane and butane per Mcf gap that pass the EUR pretty considerably.

David Heikkinen – Tudor, Pickering, Holt

That’s perfect. As you then, just going to the ASP project and thinking about the meta unit and then the response time, assuming you see a response in four to eight months and then 10 to 12 months and you look forward to 2011 didn’t see another ASP pilot or a plan and it looks market is drilling more conventional wells, am I reading that right in kind of five year – plus four-year plan?

Benjamin Hulburt

That’s right. And as we start to see the results from the first unit then we will go back and adjust that five-year plan but currently it includes only the first unit.

David Heikkinen – Tudor, Pickering, Holt

And thinking about each unit being about the same type of investment $4 million or so for a $300 barrel for oil a day, big production is that, that’s a kind of fairway to think of bolting those together depending upon results that would be additive to your multi-year plan?

Benjamin Hulburt

Yes, in the future though, we would expect units to be larger.

David Heikkinen – Tudor, Pickering, Holt

Obviously.

Benjamin Hulburt

But the capital you can scale.

David Heikkinen – Tudor, Pickering, Holt

Yeah, the ratios, exactly, just thinking about ratios of EUR as reserve recovery dollar spent and then productivity.

Benjamin Hulburt

Yes.

David Heikkinen – Tudor, Pickering, Holt

All right, that's all I have. Thanks.

Benjamin Hulburt

Thank you, David.

Operator

Thank you, sir. (Operator Instructions) Our next question is from the line of Richard Rossi of Wunderlich Securities.

Richard Rossi – Wunderlich Securities

Good morning everybody. Most of my question were answered, but I was curious, you mentioned that you were spending less on this acreage purchase in the Marcellus that you did in the fourth quarter than the acreage around you and other than being good horse traders, is there be a difference in, of what you are proposing in the lease, why we seem those costs down versus everything around you? And what are you comparing it to in terms of the price you see?

Benjamin Hulburt

That particular tract is sandwiched in, kind of in the middle of, some of these big purchases that we heard but we had it contract for a little while, and before these large dollar amounts came out. So we were fortunate to have identified it and have been working on it before some of these big acreage sales happen.

Richard Rossi – Wunderlich Securities

Then what you are looking at now, are you seeing the proposed cost per acreage rising versus what you did pay?

Benjamin Hulburt

Yes, in all three locations. We are continuing to see acreage cost escalate. As natural gas prices have settled out, as well as additional well results come out, we are continuing to see in every area acreage cost get more and more expensive.

Richard Rossi – Wunderlich Securities

All right. That's it for me. Thanks.

Benjamin Hulburt

Thank you.

Operator

Thank you, sir. We have no further question in queue at this time.

Benjamin Hulburt

Thank you, operator. And we’d like to thank you all for participating in today's call.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may now disconnect. Everyone have a good day. Thank you.

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