Rex Energy Corporation Q2 2010 Earnings Call Transcript

| About: Rex Energy (REXX)

Rex Energy Corporation (NASDAQ:REXX)

Q2 2010 Earnings Call

August 4, 2010 10:00 am ET

Executives

Benjamin Hulburt - President and CEO

Tom Stabley - EVP and CFO

Pat McKinney - EVP and COO

Analysts

Brian Lively - Tudor, Pickering, Holt

Jeff Hayden - Rodman and Renshaw

Ron Mills - Johnson Rice

Marshall Carver - Capital One Southcoast

Derrick Whitfield - Canaccord Genuity

Ray Deacon - Pritchard Capital

Mike Scialla - Stifel Nicolaus

Leo Mariani - RBC Capital

Operator

Good day, ladies and gentlemen, and welcome to the Rex Energy second quarter 2010 conference call. (Operator Instructions) I would now like to introduce to your host for today's conference, Benjamin Hulburt, President and CEO of Rex Energy Corporation.

Benjamin Hulburt

Good morning. Thank for joining us on our call to discuss financial and operational results for the second quarter and first six months of 2010. As a reminder, we issued our earnings press release last evening and posted the conference call slides on rexenergy.com.

I'll start the call this morning on Slide 3, with some key takeaways from the quarter. First, our production in the second quarter was in line with our guidance and represented an increase of 21% over the same period in 2009. Our production in the first half of 2010 was also up 22% over the first half of 2009. This is predominantly a result of our teams successful Marcellus Shale drilling operations and it is a trend we fully intend on continuing.

Taking a look at our total revenue, we were up 23% in the second quarter over the same period in 2009 and up 27% in the first half of the year over the first half of 2009. At the same time our lease operating expenses were up only 11% and 13% respectively, which demonstrates our continued commitment to improving our per unit operating expenses, as we continue to grow our production and revenue.

As a result our EBITDAX in the second quarter grew 42% over the same period in 2009, and 52% over the first half of 2009. Operationally this has been a very active first half of the year for the company, which we continue to believe will result in significant production and cash flow growth in the second half of this year and beyond.

Most recently, our newest jointly owned well in Westmoreland County, Pennsylvania has been flow tested and a peak rate of 4.9 million cubic feet of natural gas per day over a 24 hour of period. And our two most recent wells in Butler County, Pennsylvania have flow tested at a combined rate of 6.7 million cubic feet of natural gas equivalent over a 24 hour of period. All three of these new wells exceed our current Marcellus type curves.

Our drilling operations in Butler County remain ahead of schedule and we continue to expect our cryogenic gas processing plant to commence start-up operations during October of this year. Lastly, we recently closed on our previously announced 18,000 net acre acquisition in the DJ Basin, which is part of our new Niobrara Shale project.

This brings our current net acreage position in the DJ Basin to approximately 40,000 net acres. I'm also pleased to report that we have begun drilling our first Niobrara horizontal well in Laramie County, Wyoming.

I'll now turn the call over to Tom Stabley, Executive Vice President and Chief Financial Officer, to review a few of the financial results.

Tom Stabley

Thank you, Ben. The comparison on Slide 4, provide a little more detail on our changes in production mix and realized prices. While we've experienced modest oil product declines, our realized pricing per barrel has offset the loss production. Therefore, our oil revenue including the effects of cash settled derivatives increased 7% in the second quarter of 2010 from the second quarter of 2009, and 10% in the first half of 2010 from the first half of 2009.

On the natural gas side, while we continue to realize lower natural gas prices, the increases in production far exceed the slight decreases in the realized pricing. As you can see, our natural gas production has grown 113% over the second quarter of 2009, and 115% over the first half of 2010, as a result of our Marcellus Shale drilling operations.

As a result, natural gas revenue and including the effects of cash settled derivatives increased 95% quarter-over-quarter and 99% six months over the six month period.

Continuing on Slide 5, the companywide impact of these revenue increases in the second quarter and the first half of 2010 was 23% and 27% respectively, compared to the prior year period as Ben mentioned. Looking at our expenses our leased operating expenses in the second quarter of 2010 were approximately $5.8 million, up 11% from the same period in 2009, but slightly below our guidance for the quarter.

Our G&A expenses were $4.6 million in the second quarter of 2010, up 5% from the period in 2009, but again slightly below our guidance for the quarter. Of the second quarter 2010 G&A, approximately $520,000 were for non-cash compensation expenses.

One item to point out was our exploration expenses for the quarter was higher than usual at approximately $2.3 million. Predominantly due to our share of the 42 square mile 3-D seismic shoot we participated in with our partners in Westmoreland County, Pennsylvania. Because we used successful efforts accounting methods, these costs are expenses rather than capitalized.

Going forward, we expect this line item to fall back to historical norms of approximately $1 million per quarter. Earnings comparable to analyst estimates represented a loss of $1.7 million or $0.04 per share. As Ben mentioned, our EBITDAX, a non-GAAP measure, grew 41% over the second quarter of 2009 to $5.8 million or $0.13 per share in the second quarter of 2010.

As you can see on Slide 6, we have continued to aggressively hedge our production to protect our cash flows in this volatile commodity pricing environment, especially on the natural gas side. In the second quarter we took advantage of a particularly low dip in natural gas prices and bought back the price ceilings on several of our 2010 and 2011 natural gas derivative contracts at a minimal cost.

The average natural gas prices rebounded a bit, with again layering in fixed price, swap contracts that replace these. As you can see, this allowed us to put floor protection on 94% of our current natural gas production at an average price of $6.04 per Mcf in 2010, and 106% of our current natural gas production at an average price of $5.88 per Mcf in 2011.

We're having only 59% and 82% respectively, subject to ceiling prices during those same years.

Moving on to Slide 7, we continue to maintain a low-levered balance sheet, which we've outlined on Slide 7, which we ended the second quarter of 2010 with approximately $13.4 million in cash and cash equivalents, and $15 million drawn on our $100 million borrowing base.

The balance on the Williams drill to earn carry in two of our Marcellus project areas was $9.3 million at the end of the second quarter of 2010. We forecast William will expend the remainder of the carry balance mid-fourth quarter of 2010.

We are currently undergoing a mid-year borrowing base review. With our production growth and improved commodity prices, we expect to complete this review with an increase of our available borrowing capacity by early September.

Pat McKinney, our Executive Vice President and Chief Operating Officer will now give a brief update on operations.

Pat McKinney

Thanks, Tom. On Slide 8, first a quick update on our wholly owned and operated Marcellus shale project area in Butler County, Pennsylvania. As a reminder, this area of the Marcellus Shale fairway is liquid rich, resulting in a higher profit margin than the dry gas areas of the play.

Additionally, due to the shallower depth and relatively consistent geology in the area, we believe this will ultimately be one of the lower cost areas to drill wells. For the year-to-date, we've completed four new horizontal Marcellus Shale wells in Butler County. In addition, there are five wells drilled and awaiting completion in two wells currently being drilled.

Due to significant improvement in our drilling efficiencies, we expect to have all of the ten wells of our previously announced plan of drilling to be completed by the time the cryogenic plant commences operations early in the fourth quarter.

As Ben mentioned, during July we fraced two wells on the R. Knauff pad. While these wells are still flowing back water with only approximately 8% of the load returned so far, I'm pleased to announce that the average 24-hour peak rate to-date for the two wells has been approximately 3.4 million cubic feet per day per well.

Lastly, we've experienced a slight delay in receiving our air permit from the Commonwealth of Pennsylvania for the construction of our cryogenic gas processing plant in the area. However, due to the continued superb efforts of our team and our Midstream partners, we continue to believe the plant will commence operations during the month of October 2010. Then in the completion of the public comment period, we expect to receive our permit during the month of August. To-date, we're not aware of any comments issued to the state concerning our plant. On Slide 9, Williams is now operation in our Westmoreland County Joint Venture project area. With each company owning 50% working interest.

During the quarter, Williams completed the Slavek Trust number 1H, which is the first of three wells in the Slavek Trust Unit. We're very pleased to report that the well tested a peak rate of production 4.9 million cubic feet per day over a 24-hour period. The well was put into line at the beginning of the third quarter 2010. There are currently three wells drilled awaiting completion in this project area.

We anticipate Williams will complete the two additional Slavek Trust wells late in the third quarter 2010. Our partner's rig has now moved to a five well pad called the Uschak Unit and is currently drilling the second of five planned wells.

Going to Slide 10, while there was no new drilling activity in the central Pennsylvania project area during the second quarter we anticipate Williams will begin drilling here again with a second Joint Venture rig in the third quarter of 2010. We now expect the gathering system to the two shut in Alder Run wells to be completed in September 2010.

Moving to our ASP project in the Illinois basin on Slide 11, we are on schedule to begin chemical injection in our Middagh Unit later this month. The Middagh Unit is a 15 acre ASP unit which is targeting the Bridgeport Sandstone. Once chemical injection begins, we estimate it will take four to six months till we see an initial response. The Middagh Unit should reach peak production 10 to 12 months from the start of chemical injection. There are several objectives at the Middagh Unit it's designed to make.

First and foremost is to test the ASP recipe developed by the University of Texas in the field. Second, we are using the Middagh Unit to optimize drilling completion procedures, well pattern and reservoir flow conformance for future ASP units; as this Unit is purposely over-engineered. We do not expect that the economics of the Middagh Unit will be representative of future ASP floods, but rather to aid us in determining economic quantity of chemicals to use in optimal well spacing in the future.

We've begun preliminary work on the Bridge and Perkins Units, which we consider to be Phase II of our ASP program. The main objective of these two Units will be to implement the long-term economic methodology developed in Middagh Unit for ASP flooding in the Bridgeport Sandstone across the field.

On Slide 12, we've outlined the Middagh, Griggs, Perkins and Delta Units. While the Griggs and Perkins Units will be larger than the Middagh Unit, the chemical mixing plant and injection facility we built does not require significant expansion in order to develop these two units. The Delta Unit is a larger unit consisting of 351 acres. We've begun preliminary design on the Delta Unit and we expect to commence injection operations after the Griggs and Perkins Units.

To-date, working with our outside engineers, Netherland, Sewell we've designed a total of 15 units, seven of these in the Bridgeport Sandstone alone.

Lastly, we're continuing to conduct testing on the site of Sandstone using both rigid and colloidal gels to improve injection performance in that formation, which we hope to be in a position to report on next quarter.

Moving to our newest area in the Rockies, as Ben mentioned, we completed the acquisition of approximately 18,000 net acres last week, bringing our total net acreage position of the DJ Basin to approximately 40,000 acres. Our acreage at this point is split with approximately 8,000 acres in Weld County, Colorado and approximately 32,000 acres in Laramie County, Wyoming.

Our leasing and acquisition efforts to-date have been based on a geologic methodology to define our initial prospective area, which is highlighted in green on Slide 13; as more Niobrara wells are drilled, and we continue to evaluate and high-grade additional areas within the DJ Basin.

As you can see on the map, a large portion of our acreage is located in close proximity to the Silo Field in Laramie County, Wyoming. The Silo Field has been producing Niobrara Field of approximately 90 horizontal wells, which were built predominantly in the 1990s. Although these wells were drilled sometime ago with short laterals and single stage openhole completions, in most cases they still average in EURs of approximately 160,000 barrels of oil.

Most recently, SM Energy formerly St. Mary's reported their Atlas 1-19H well in the southern part of the Silo Field which was drilled with a longer lateral and completed using modern techniques produced at initial rate of approximately 1,000 barrels a day, far upsetting the historically well production in the field.

In late July, we spud our first horizontal Niobrara Shale well in the Basin which is currently drilling. The well is planned to have a 4,000 foot lateral section and at this point we plan to complete it with a 10 to 12 stage frac. While it is still early in the play, we're optimistic that this project will become a significant asset for the company.

I'll now turn the call back over to Ben.

Benjamin Hulburt

Thanks, Pat. Looking forward to the third quarter of 2010 on Slide 14, we anticipate average daily production for the quarter to be between 20 million and 22 million cubic feet of gas equivalent per day. This is lower than we would have originally expected due predominantly to delays in construction of our non-operated gathering system in Clearfield County and Westmoreland County, Pennsylvania.

Our lease operating expenses in the third quarter, we estimate, will be approximately $6.5 million. We expect cash, general and administrative expenses in the third quarter to be approximately $4.4 million. We're reaffirming our 2010 year-end guidance of Average Daily Production between 25 million and 29 million cubic feet of gas equivalent per day.

However, at this point due to the delays in getting the wells in Westmoreland and Clearfield County online, we expect to be at the low end of this range. We continue to estimate our total lease operating expenses in 2010 to be approximately $26 million and cash G&A to be approximately $16.7 million.

Moving to Slide 15, before we get into Q&A I want to highlight several conferences at which we will be presenting. In a couple of weeks we will be at EnerCom's2010 Oil & Gas Conference in Denver, Colorado.

While the conference runs from August 22 through to 26, we will be hosting a breakfast table and presenting on Wednesday August 25. In September, we'll be at the Rodman & Renshaw Annual Global Investment Conference which is September 13 through the 15 in New York City.

During October, we will be presenting at two conferences. First we'll be at Johnson Rice Energy Conference in New Orleans October 5 through October 7 and then October 12 through the 14 at IPAAs Oil Gas Investment Symposium in San Francisco.

Operator at this time I'd like to open the line up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt

Starting on the Illinois Basin, how are you going to monitor conformance in ASP flood and then what adjustments are you able to make real time in order to improve sweep efficiency?

Pat McKinney

This is Pat, Brian. We use a number of techniques to monitor the conformance; typically injection surveys to see where the injected fluid is going. They could be radioactive tracers or they could just be (spinners), but we monitor all of the initial characteristics of the injection wells and then once we start ASP injection we're able to monitor the conformance. So we're able to see that pretty much real time.

Brian Lively - Tudor, Pickering, Holt

And can you make any adjustments then, thinking squeezing off these zones or maybe other adjustments to help the sweep?

Pat McKinney

Well we pretty much already done those to-date. So we in wells that did have slight conformance issues, we're able to isolate certain areas. But for the most part we think the table is set to start the project.

Brian Lively - Tudor, Pickering, Holt

Okay, And you've discussed an oil cut ramp over a 12 month period, just wondering and considering that the first flood is going to be still somewhat in learning. How much contingency time have you baked into your production in oil cut estimates?

Pat McKinney

Well we've done a pretty substantial amount of simulation modeling on this area as well as extensive core flood work. So we feel we've got a pretty good range of outcome. Again, remember this is a very small pattern, size of 1.5 acres, so really it's a very small contained area. So we should be able to see the results in the timeframe that we forecast out there.

Brian Lively - Tudor, Pickering, Holt

Okay. And then thinking forward to 2011, do you have any update at CapEx guidance, and then as you add the additional units, what magnitude of an uptick can we expect as you add each unit?

Benjamin Hulburt

The most likely plan at this point is that we would commence either the Perkins or the Griggs Unit in 2011. We probably wouldn't want to commence injection in those until we're well in to the Middagh Units. So I think the most likely is we start one of those two units in mid 2011 and I think each of them have a capital investment of about $15 million total. So you'd expect somewhere around half of that capital to be incurred in 2011. So on the $8 to $10 million range I think is realistic.

Brian Lively - Tudor, Pickering, Holt

As you add each unit, something like 50% is front load in the first year that you add?

Benjamin Hulburt

Yes, it may be even more in the first year. I probably say closer to 75% because you've got all the well drilling, the flow lines and then by far 75% of your capital is the chemicals themselves which are injected over the first 12 to 18 months.

Brian Lively - Tudor, Pickering, Holt

Okay. Switching over to the Niobrara, how many acres do you actually have in the Silo area? And I'm also wondering within your various positions how does the geology change across that play?

Benjamin Hulburt

I can give you an estimate around the Silo Field. We have about 32,000 acres in Laramie County, Wyoming. Of that, I would estimate that probably 25,000 acres of it is within a township or two of the Silo Field.

Brian Lively - Tudor, Pickering, Holt

And then as you kind of go from east to west, what are the significant variations that you guys are seeing across the entire basin? I'm talking about all three or four of your asset positions.

Benjamin Hulburt

The variation geologically, I don't think we see a huge variation in terms of thickness, some variation in depth, but not significant. Well, we do see change if the resistivity logs indicating the presence of hydrocarbon in that shale, which is one of the key indicators that we've keyed off of to identify where we think the Fairway is.

You notice on the map we gave, that's what we think the Fairway is in the area we focused on to where the resistivities are high enough and thick enough that we think its perspective.

Certainly not to say there aren't other parts of that basin. We also haven't really mapped anywhere close to the Wattenberg Field, simply because we thought majority was HPP. So in the area we've focused on, what we've given you an outline of is an area that we think the resistivities are high enough in a thick enough zone that it should be perspective.

Brian Lively - Tudor, Pickering, Holt

Last question I had is on the Marcellus, you've talked about doing a Butler Joint Venture, just wondering what the status of that is, and any estimated timing for getting the deal done?

Benjamin Hulburt

Sure, we are continuing to look at that actively. In terms of timing, if we are to do anything, it will certainly be before the end of this year, and I think more likely before the end of the third quarter. And certainly nothing is concrete, otherwise we'd be announcing it, but we are continuing to look at that possibility and are fairly optimistic that it's something we can get done.

Brian Lively - Tudor, Pickering, Holt

And have you guys estimated just how important doing a JV deal is to finding through 2011, assuming current strip prices?

Benjamin Hulburt

Well, some sort of foreign funding is certainly part of our thinking or slowing down drilling in 2011 which is always an option. At this point we operate a vast majority of our projects. So we certainly have that in our thinking. As we said before, we do intend on looking at a bond offering in the second half of 2011, as we feel like our cash flows and production will be high enough to justify looking at that, and that's always a part of our thinking.

The JV to us is a possibility and our attitude on it is that we would only peruse it if we think it's strongly accretive. And at this point, that looks like a very good possibility.

Operator

Our next question comes from the line of Jeff Hayden from Rodman and Renshaw.

Jeff Hayden - Rodman and Renshaw

I was just thinking about, the Marcellus for a little bit. When you look into acreage, when you think about kind of ramping up the program, just wondering if you can give us any sense on what level of activity you need to run if you are only goal was to hold you acreage.

Benjamin Hulburt

I think with the pace that we are on right now, where we will be anyway by the end of this year, where we've got one rig running in central, PA and one rig running in Westmoreland, PA, and one running in Butler. I think at the pace we are on with the expirations we are looking at we are positioned to hold probably 75% of it with just that.

Since I know all three areas are looking at accelerating in 2011, two rigs in Butler and a third rig with Williams at least, not quite sure which county that would be in. I think we will be in a very good shape to hold the overwhelming majority, very high percentage of our acreage, prior to any primary expirations terms.

We also have a decent amount of acreage that has five year extension option after the expirations which start to happen at the end of 2013. And then in Central Pennsylvania in particular, several of the tracks there are several hundred and in some cases several thousand acres. So, holding acreage there happens at a much quicker pace than Westmoreland or Butler County can. So I think we've got to speed up our pace a little bit to hold acreage, but by no means do I think we have to go to four or five rigs in each area to accomplish that.

Operator

Our next comes from the line of Ron Mills from Johnson Rice.

Ron Mills - Johnson Rice

Question on the way you'll are drilling in the Niobrara right now. How are you all drilling that well? I know as SM drilled there, is under-balanced, are you doing something similar and where are you in the drilling of that well and have you lined up the frac date and just trying to get a sense of the calendar.

Pat McKinney

Yes. We've looked at the St. Mary's well and how they drilled it, and we are going to drill it under-balanced, and it flowed during the drilling process and we are set up to handle that, should that occur drilling this well. So we're in a position where we're ready for that and as far as the frac date we wanted out the third party and have that scheduled based on our drilling activity. So we are set out drill and complete that well.

Ron Mills - Johnson Rice

You always planned on drilling a couple additional test wells, I assume you're going to pop across different portions of your acreage and then to follow on to that you sound like you may look at even drilling additional wells after those tests. How quickly would you? Do you have the rig for a long enough term to just continue going back to back and end up drilling five to seven wells there?

Benjamin Hulburt

Ron, this is Ben. The answer is yes, the first well is actually in the 640 an acre section adjacent to St. Mary's well. So it's on the south-eastern portion of the Silo Field. The rig, the second well is then located on the north-western portion of the Silo Field, in that area by acres that you can see on the map.

Those are the first two wells and that's what's in our capital budget currently. In addition to that we're permitting a total of six wells for the year. We've not put those in our capital budget yet, because we want to see how these first two go. But we do have the option of keeping the rig if we choose to, through the end of the year and probably beyond. So if the wells go as we all hope they do, and we choose that we want to do a few more wells this year, we will have access to the rig to do it.

Ron Mills - Johnson Rice

Okay. And then two follow ups just on the Marcellus. The cryo plant, what are the steps once you receive the air permit to increase the visibility of that earlier or mid October or some time in October timeframe, you were supposed to get it online and I know you'll have all the wells drilled. I think in the release you talked about, into 20 or 25 main a day of capacity when you bring it on and then 40 main a day early next year. What are some of the steps from your production standpoint, your completion standpoint to get up to those levels?

Benjamin Hulburt

Well one, there is a lot of preliminary work on that plant. The things that you are allowed to do without having this permit or either done or ahead of schedule. So those things are going very well. For instance most of the pads are in place, most of the preliminary plumbing. What really has to happen as the air permit comes in is all the pieces have to be set on site and piped together.

Several of which are on the trucks being shipped to the site now; and really sitting and waiting for the air permit to be issued to us. So really what has to happen is the piecing together of each of the individual components of the plant and the compression.

In addition to that, obviously piping in all of the wells, which is happening as we complete them, because our plan throughout the year has been to flow-test wells and then actually put them into production, shut off the two previous wells and put two additional ones through our refrigeration plant which is located about 100 yards from the cryogenic plant.

So a lot of the pipelining for individual wells is already taking place.

Ron Mills - Johnson Rice

Okay. But when you have those ten wells and when you bring them all on line, is that what we should read into the 20 to 25 million a day that your expect your production to go relatively quickly from the 5 million capacity currently to the low to mid-20s?

Pat McKinney

Yes. So we should have 10 new wells this year. In addition to that, our P. Knauff will go online, but that's not an incremental increase in production.

Ron Mills - Johnson Rice

And then, other than just having one or maybe even the second rig, I'm just trying to get a sense of the build. And then as you go to the 40 million a day and the discussions you're having with Stonehenge on a potential second plant, which else that process is from a development standpoint pace?

Pat McKinney

Sure. Well, first to start in October, the initial cryogenic plant capacity is 20 million a day. And then we can continue to run our refrigeration plant. So right now our refrigeration plant maxes out at about 4.2 million a day. So that's where we think, after the first week I'm sure they'll slowly incrementally increase production and get it up to that 24 million a day or so.

We also have ordered the compression to put the plant capacity up to 40 million a day, which will happen late December, early January. One of the things we're testing is the wells that we drilled this year, these 10 wells are all done on two well pads. We are now moving the rig to five well pads, and we anticipate that speeds up the drilling considerably, even faster than the way we've been able to improve it this year, which I think is almost 50% faster than we were able to do it last year.

So we do intend on adding a second rig in 2011, but in addition to that, as we move to these larger pads, we're able to drill a lot more wells than we used to be with just a single rig. So I guess to answer your question in how to model 2011 and beyond, we aren't ready to put that out yet; those models are still being done internally, and over the next couple of months, we'll be able to give you a better guidance on 2011.

Ron Mills - Johnson Rice

And then lastly, just the Alder Run wells that's originally a February/March start-up to now. A lot's probably happened, although it would be slower than you thought since February/March. What's left to do to be able to get that infrastructure in place and hook those wells up, because as I recall, those are 3 million or 3 million-plus a day net yield?

Pat McKinney

Yes, they were tested for 14 to 17 days. And one of them tested at about 4.2 million a day, and then one of them was at 2.8 or 2.9. And again, we'd own half of that. They've been shut in since that time, which has been about a year, year-and-a-half.

What's left to do to our knowledge is to bore under one final small stream, which our engineers estimate is about a week long process. It's not a very large stream or a difficult boring operation. So we do think that they are very close to nearing the finish line on this.

Operator

Our next question comes from the line of Marshall Carver from Capital One Southcoast.

Marshall Carver - Capital One Southcoast

Yes, Ron asked most of my questions on the cryo plant for the fourth quarter. But I did have one more. Your guidance for the year, are you assuming an October 1 startup or October 15? Or what's cooked into your numbers?

Tom Stabley

Sure. At this point, we're expecting a mid-October startup.

Marshall Carver - Capital One Southcoast

Okay. And one other question, switching subjects to the ASP, the two potential units next year, you talked about $8 million to $10 million in CapEx in '11. Is that combined or is that each?

Tom Stabley

That's each. But I think the most likely thing is that we start only one of those in 2011.

Marshall Carver - Capital One Southcoast

Okay. And so that's $8 million to $10 million for one of those in '11, but the total project would cost more than that?

Tom Stabley

Well, the total cost for those units is around $15 million for each of them. So if you had $8 million to $10 million in 2011 for the first unit you'd have another $5 million for that unit in 2012 and then you'd be starting another unit in 2012. So the easiest way to model it, and again, this is before we really issue a capital budget for next year.

So this may change, but $10 million in 2011, and then $15 million in 2012 and then we're going to start to look at bigger and bigger units after that like the Delta Unit which we've shown in the presentation.

Operator

Our next question comes from Derrick Whitfield from Canaccord Genuity.

Derrick Whitfield - Canaccord Genuity

On the Butler wells, you guys have tried several different completions to-date, and I'm interested in your thoughts on the R. Knauff well and how close you are to an optimal well design?

Benjamin Hulbert

Yes, that's an interesting question, Derrick. These R. Knauff wells, one was drilled lower in the section of the Marcellus, which most operators are saying is where they're getting better results.

One of the problems with doing that in Butler County is, the organic content is very high, much higher than we see in other parts of the county, which means the rock's harder to frac. So with these particular wells, because we're in that higher organics, they use larger amounts of water pads and less sand, so it required a greater amount of pressure to get them to crack.

Once we did, it looks like we've gotten some pretty good wells. And I will say, it's very early in the life of these wells, but it looks like that works fairly well. So the next step is to plan the well, which is actually, the next two wells are more up towards the Cherry Valley where the rock is a little more brittle and use the higher amounts of water and the combination of the two and see how that results.

So the good news is, we absolutely have a working model that's consistently getting, we think, good wells. When I say we're optimized, I think the answer is, absolutely not.

Derrick Whitfield - Canaccord Genuity

That's terrific color. Moving over to the Niobrara, how would you characterize the state of your current leasing activities? Are you guys comfortable with the scale of your position here?

Benjamin Hulbert

The state I guess of our leasing activities is temporarily dormant. In our opinion, we spend enough money on acreage until we make sure this works. If it does, we'd like to continue to add acreage. But I guess our attitude was, we're going to know in the next month or two how we're looking. And so for the time being we aren't continuing to spend any significant amounts of capital on leasing there.

Derrick Whitfield - Canaccord Genuity

And then staying on the Niobrara still, did you comment on the changes you guys are seeing in structure from a geologic perspective across your position? Silo appears to be highly fractured. And is that preferred to get mined?

Pat McKinney

I think it's preferred. We have not commented on structure; one, I think it changes throughout the basin. We have dug some seismics over the acreage in Weld County, Colorado, and the limited lines that we shot showed it to be very heavily faulted.

So that was going to originally be our first well. We've moved it back in the queue until we can shoot the whole thing with 3D.

So we do think that the faults and the fractures will obviously produce a better well, but can make the drilling more difficult. So we don't have a structural model across the basin yet. We are planning to rather size both 3D shoots on either end of the Silo field, which will help us define our acreage a little better.

Derrick Whitfield - Canaccord Genuity

Got it. What do you guys expect in the far eastern part of your position?

Pat McKinney

In Weld County, Colorado you mean?

Derrick Whitfield - Canaccord Genuity

Yes.

Pat McKinney

The reason we went to that area was, there was a well drilled in the middle of our blocks that flowed a decent amount of oil from the Niobrara as it went through it into the D&J sands. So we knew with very good data what the resistivity was and that there was oil generated. And that's really why we started in that area, an area that I think most consider too far east in the fairway, so we were to able to get the acreage there very cheap.

As we've mapped around it, we've continued to expand what we think is the perspective area in and around that initial prospect. But that's why we went there initially.

Derrick Whitfield - Canaccord Genuity

Got it. And then if I look down to where you are in Colorado, the far eastern side of that, what are you expecting there?

Pat McKinney

Well, that's what I was referring to, the far eastern side. I don't think I would at this point go any farther east than where that acreage is.

Operator

Our next question comes from Ray Deacon from Pritchard Capital.

Ray Deacon - Pritchard Capital

Hey, Ben I was curious, I thought I heard you say before, your production for the year, you would exit the year at 25 to 29. You mean the average for the year?

Benjamin Hulburt

That's the average for the year. Our exit I would expect to be up around 40.

Ray Deacon - Pritchard Capital

Okay, got it. And you guys spent less than I thought in the quarter. I guess is this kind of a good run rate for CapEx for the rest of the year? Is that fair?

Tom Stabley

Well, I think it's fair with the exception of the acquisition that we just completed last week. That was just under a $19 million acquisition.

Ray Deacon - Pritchard Capital

Right, for the Niobrara; got it, okay. And I guess if you were to compare the most recent Butler County Wells to what you've drilled in the past based on the fact that it's early in the flow back, do these look better than what you've done in the past?

Benjamin Hulburt

I think it's too early to tell that. One of the positive things about these two wells in particular, the Magill wells if you remember that we announced last quarter, one of them was very strong, undoubtedly I'd say the biggest well we've drilled in that county and maybe in all three counties, and then the other one wasn't as strong. So they weren't really even.

These two R. Knauff wells, both have very similar flow rates. So the production wasn't skewed really to one well or the other. I think it's a good sign that we're proving our consistency. But I think it's too early to tell really how they'd compare to the other wells until they get a longer flow rate.

Ray Deacon - Pritchard Capital

But for no reason, I think they're below 4 Bcf EURs. I guess it's early?

Benjamin Hulburt

Our original estimation reserves in that county I think was about 3.5 Bs.

Ray Deacon - Pritchard Capital

3.5, got it. Okay.

Benjamin Hulburt

Again, we have very limited data; I don't see why it'd be below that, but I don't know that any of us could go to the 4 Bcf level yet.

Ray Deacon - Pritchard Capital

Okay, got it. And could you talk about your expectations with Williams? I thought I heard them say, they'd like to go to a second rig on their call with your guys in August. And I guess would you think there's a potential third rig that gets added at some point in '11?

Benjamin Hulburt

They have confirmed to us that they are bringing a second rig in August that will go to the Clearfield County area. We actually have two more Alder Run well pads that we have built and permitted prior to turning over operations. So they are immediately drilled, bored and ready to go. So the rig will go there.

And then we have had some preliminary discussions with Williams that they expect to bring in a third rig early in 2011, but they're very preliminary.

Operator

Our next question comes from the line of Mike Scialla from Stifel Nicolaus.

Mike Scialla - Stifel Nicolaus

Question on the Sarsen plant; in terms of getting the permit, you said in the commentary, what is the actual process now? I mean, if there are no comments, is it automatically going to be issued in mid-August, or is there anything else that could affect the timing there?

Pat McKinney

I really can only go by what we experienced when we did this last year with our refrigeration plan. And since we didn't have any comments, I think we got the permit in our hand about six days later. So that's what we're anticipating again this time. And at this point, we don't see any reason why that's not accurate.

Mike Scialla - Stifel Nicolaus

I think you had said in the past that that plant is going to be able to reject ethane, but you need to get the BTU content below 1,100. Anything from these new Butler wells that suggest that's going to be an issue?

Pat McKinney

No, in fact, I think we're in very good shape. We recently signed a deal with Enbridge to market all the liquids out of there. The plant is designed with an ethane, as you said, rejection tower that can separate out the ethane. And then the ethane will then get injected back into the gas stream, until the BTU or the gas hits 1,100, which is the maximum that we can put into that pipeline.

And we had originally thought, given transportation requirements around ethane that we had to max out that 1,100 BTU level. Now that we're going to rail out the systems, it looks like we actually have some swing in the ethane, so that we'll be able to play with where we're getting a better price, whether we're getting a better price in the BTU upgrade on the gas side or to the liquid side.

So it's actually a little better situation than we had originally anticipated it.

Mike Scialla - Stifel Nicolaus

So you're going to rail out the ethane?

Pat McKinney

Rail out all the liquid, doesn't mix with.

Mike Scialla - Stifel Nicolaus

All the liquids, okay. And then I want to ask you, on some of the rigs on some of these Butler County wells, probably get those two Magill wells, I guess the better of the two is the one you quoted in your presentation; that 30-day rate of 2.3 million a day, do you have any sense for what that would have been, had it not been constrained for one of the constraints that you're facing with the processing?

Pat McKinney

We have an estimation of some of the guys in the field. I mean their comments were that that well could easily have done twice that if not more. You have a lot of pressure on it. We do think it's important to not let wells do that, to hold back the flow, otherwise all we do is pull the sand back into the hole. But that looks like it could have easily done twice the rate that it did on the restricted flow.

Mike Scialla - Stifel Nicolaus

And then looking at the P. Knauff well, so it's done 7 tons of Bcf already, and you're forecasting I think 3.5 Bcf or 3.9 Bcf. What kind of reserve life are you estimating there?

Pat McKinney

I believe all our reserves are done with the 30-year life, off the top of my head.

Mike Scialla - Stifel Nicolaus

And then the Panizzi well, they're constrained as well, is that correct?

Pat McKinney

No, I don't think at this point they are. I mean they probably had periods when they were constrained, but I don't think for the most part the Panizzi have been held back.

Mike Scialla - Stifel Nicolaus

Okay, so we're seeing a good rate there. Okay. Can you give some costs on some of these newer wells?

Pat McKinney

Well, the last two Magill wells, I think by the time they were done were about $4.2 million a piece or so. I don't have numbers on the R. Knauff wells. We expect them to be about $4 million a piece. And then, in Westmoreland I don't think we have final numbers yet from Williams on the Slavek Trust well.

I do think because of Westmoreland's complexity and it's deeper, it will be more expensive than what we see in the Butler area. But remember that we have in the presentation of about $4.2 million at Butler. I think at this point it's pretty accurate.

Mike Scialla - Stifel Nicolaus

How about when you go to the five well pads, where do you think that can go?

Pat McKinney

I think that will bring the number down maybe 5% or 10%, assuming we can get the drilling efficiencies that we think we can by staying on the same pad. The trade-off we're doing that, however, is you're obviously holding less acreage because you're on a five-well pad. So there are trade-offs.

Operator

Our next question comes from Leo Mariani from RBC Capital.

Leo Mariani - RBC Capital

I'm curious if there are any remedies you guys have in your GDP agreement to kind of get Williams move in a little bit faster there?

Benjamin Hulburt

No. And I think I want to caution, the Williams moving in faster is, they're only on their third well. And this is not easy drilling, especially in Westmoreland County. So I think just them getting more wells down, we're going to start to see it go faster and faster like everybody has done.

We are not allowed right now to propose operations in the joint venture areas with Williams until the key area is extended, which will certainly be extended by the end of this year. And at that point we are a 50% partner and we have the right to propose operations to the extent we want something done that they don't.

But our relationship with Williams is very strong; we're very happy with them. That is the right we have. But we expect that they're on the verge of starting to accelerate things in both those project areas.

Leo Mariani - RBC Capital

Any estimate to how long it took to drill those Slavek wells? Do you guys know?

Benjamin Hulburt

I don't know if I have the final number, but one of the Slavek wells or two of the Slavek wells we drilled, and I think they came in, I don't want to give you the wrong number, in the 30s, 35 days or so. The third Slavek well they drilled, I think around the same time period. And now they've moved to the Uschak wells, and I don't know the days on those yet.

Leo Mariani - RBC Capital

Just looking at your production guidance for the year, if you guys are at 25 to 29, and I guess 20 or 22 for 3Q, I guess if I plug in 22 in 3Q, you guys will have to be I guess roughly 40 in 4Q to be at that guidance. Do you guys think you can get to the 40 there?

Benjamin Hulburt

We do. Right now, I mean at June our production was a little over 20 million a day. So if you assume that the Butler plant comes on at 20 million a day, you're right there. One, we think we'll be able to flow a little more than 20 million a day with the refrigeration plant.

We've built into our numbers some pretty conservative time periods for some of the other non-operated wells. We also, into them we have not included any Niobrara production. So yes, I think we can. We do think we'll be at the low end of that guidance, which is what we put out today. But yes, we still think it's very possible assuming the plant comes online in mid-October like we anticipated to.

Operator

Our next question comes from Ron Mills from Johnson Rice.

Ron Mills - Johnson Rice

Tom, for you; just a clarification on the G&A guidance of $4.6 million, that would be flat with the second quarter, although in your presentation you showed that as cash-only as opposed to cash plus non-cash comp. Can you just clarify that you'd expect total G&A to still be $4.6 million rather than just the cash component?

Tom Stabley

No, the cash component we're projecting to be a poor six.

Ron Mills - Johnson Rice

And so, overall, your G&A you would expect to be five plus?

Tom Stabley

That's correct. Well that 4.6 lines out to what we gave guidance last quarter for the year-to-date, which is a total of 16.7.

Ron Mills - Johnson Rice

But in the second quarter you were only at about $4 million or $4.1 million in cash, correct?

Tom Stabley

That's correct.

Ron Mills - Johnson Rice

So what's the jump in G&A?

Tom Stabley

Some of the partnership G&A that we're experiencing from the Midstream and our water treatment processing.

Ron Mills - Johnson Rice

So going forward that 4.6 plus on the cash is the better number?

Tom Stabley

Is the run rate, yes.

Operator

We have a question from Ray Deacon from Pritchard Capital.

Ray Deacon - Pritchard Capital

Ben, you mentioned in the past potentially drawing some shallow, vertical Geneseo wells to hold acreage in order to be able to drill more horizontals from pads and save efficiencies or maybe grow quicker. I guess I don't know, what are you thinking on that?

Ben Hulburt

We are continuing to work on that Ray. And we will do at least one if not two Upper Devonian tests in Butler County this year, predominantly testing and probably commingling the Burkett and the Rhinestreet shales.

Initially with vertical wells, what we're trying to do right now is to put together a well design to get that cost well under $1 million, which is not an easy thing to do, with a decent sized frac on those two shales. So that's our challenge, and that's what we're working on. And we do intend on testing that at least once this year if not twice.

Operator

I'm not showing any more questions in the question queue. I would now like to hand the call back over to Mr. Hulburt.

Benjamin Hulburt

Thank you, and we'd like to thank everybody for participating today.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may now all disconnect. Everyone have a great day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!