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Executives

Daniel Churay - Chief Executive Officer, President, Independent Director, Chairman of Compensation Committee, Member of Nominating & Governance Committee and Member of Audit Committee

Patrick McKinney - Chief Operating Officer and Executive Vice President

Thomas Stabley - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Analysts

Leo Mariani - RBC Capital Markets, LLC

Ronald Mills - Johnson Rice & Company, L.L.C.

Raymond Deacon - Pritchard Capital Partners, LLC

Phillip Jungwirth - BMO Capital Markets U.S.

Jeffrey Hayden - Rodman & Renshaw, LLC

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Rex Energy (REXX) Q4 2010 Earnings Call February 16, 2011 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to your Rex Energy Fourth Quarter 2010 Conference Call. [Operator Instructions] I would now like to introduce Mr. Tom Stabley, Chief Financial Officer. You may begin.

Thomas Stabley

Good morning, and thank you for joining us for the Rex Energy Fourth Quarter and Year End 2010 Earnings Call. Dan Churay, President and CEO of Rex Energy; Patrick McKinney, our Chief Operating Officer and I will provide comments this morning. Now for our disclaimers. Statements made by management during this call that are not purely historical facts are forward-looking statements. This includes statements regarding the company's expectations and intentions on strategy regarding the future. It is important to note that the company's future results could differ materially from those projected in such forward-looking statements due to a variety of factors.

The format of this call does not allow us to fully discuss all of these risk factors. For a full discussion, please refer to last night's earnings release and our SEC filings, including our 10-K and today's 8-K filings. In addition, please see today's release for a reconciliation of GAAP measures to non-GAAP measures such as operating loss to adjusted EBITDAX as defined in our credit agreement. During this call, we'll refer to the non-GAAP measures of adjusted EBITDAX simply as EBITDAX.

Moving to Slide 3. We would also call your attention to our recent operations update release and Monday's release providing further information on year-end 2010 oil and gas reserves. I would like to remind our participants that our earnings release and these other releases, as well as the presentation accompanying this call, are all available on our website at rexenergy.com.

Now I'd like to introduce Dan Churay, our CEO.

Daniel Churay

Thanks, Tom. Good morning, everyone, and thank you for joining us on this call to discuss our financial and operational results for the fourth quarter of 2010, as well as our full year results for 2010. Let's begin this morning on Slide 4 and highlight some of the key takeaways from the fourth quarter and the full year.

Our average daily production for the fourth quarter increased 12% over the third quarter and was within our previous guidance given. The increase in our production was primarily attributable to gas sales through the Sarsen cryogenic gas plant in Butler County, Pennsylvania, which was commissioned during the fourth quarter.

Revenue for the quarter grew 14% over the third quarter, while maintaining even levels of lease operating expense, showing an overall decrease in cost per Mcfe. Our lease operating expense for the quarter was below guidance, which further illustrates our commitment to continue lowering production costs on a per unit basis. As a result of our increased production, higher revenue and lower per Mcfe production costs, our EBITDAX for the quarter increased 42% sequentially from the third quarter.

Looking at our results for the full year. Our production increased up 26% from 2009 to 2010. As a result of increased production and stable commodity prices, our revenue increased 28% over 2009 levels. Our proved reserve levels showed a net increase of 61%, with a reserve replacement rate of 1,560% to 201.7 Bcfe of proved reserves. Taking into consideration our reserve growth over the last few years, we currently have a compounded annual reserve growth rate of 75%.

Most importantly, we announced a drill bit finding and development cost of $0.68 per Mcfe. This is primarily attributed to our success in Butler County, where we grew reserves in the liquids-rich portion of this play by 248%. We're encouraged by these results for 2010 and are looking forward to 2011. During the next year, we expect our production to grow 71% to 95% over 2010. In addition, we expect our 2011 exit rate to grow by 63% to 95% over our 2010 exit rate, putting our expected exit rate at 40.7 to 48.5 Mcfe per day. I would also like to note that we have allocated the majority of our capital budget in areas of operations that produce oil and liquids-rich natural gas as we feel that these areas will provide the greatest return for our investors.

Now I'd like to turn the call over to Tom to review some of our financial results.

Thomas Stabley

Thank you, Dan. I'd like to begin on Slide 5, which gives a more detailed explanation of our production volumes and realized prices for the quarter. Our average daily production increased across all three production types, with natural gas showing the largest increase of 27% to 10.6 million cubic feet per day. Overall, production in the fourth quarter increased 12% over the third quarter to 22.8 million cubic feet equivalent per day. Production for both the fourth quarter and the full year was in line with our previous issued guidance. And our realized price for oil increased 6% for the quarter after accounting for the impact of cash settled derivatives. Lastly, our realized price for natural gas essentially stayed flat quarter-to-quarter.

Moving to Slide 6. Our total operating revenue for the fourth quarter of 2010, including cash settled oil and natural gas derivatives, increased by 14% from the third quarter of 2010. Looking at our expenses. I would like to highlight a few items. First, our lease operating expenses stayed flat from the third quarter of 2010 to the fourth quarter of 2010, with production and revenue increasing 12% and 14%, respectively.

Our G&A expenses dropped by 16% from the third quarter levels, with a decrease being attributable to the higher G&A in the third quarter caused by the Sumitomo joint venture closing. Impairment expenses were high in the fourth quarter as the company recognized impairment expense of two vertical test wells that the company drilled in west Clearfield County, PA in 2008. Our earnings comparable with analyst estimates, which is a non-GAAP measure for the fourth quarter, was a loss of $0.02 per share. And EBITDAX, which is also a non-GAAP measure, increased 42% over the third quarter of 2010 to approximately $8.1 million or $0.19 per share.

Moving on to Slide 7. You can see that we are continuing our aggressive hedging strategy to protect our future cash flows.80% of our oil and 104% of our natural gas December exit rate production is hedged for protection. We have provided more specific types and volumes of hedging positions in the appendix at the back of this presentation.

Moving on to Slide 8. Looking at Slide 8, we have our consolidated balance sheet. There are a few items I would like to draw attention to. At the end of the fourth quarter, we had $11 million in cash with $10 million of debt drawn on our line of credit. This would leave an additional $150 million available under our senior credit facility. We are in the process currently of our year-end borrowing base redetermination and expect to have that information available in early March. Lastly, as of the end of the year, we had $28.8 million remaining in drilling carries from the Sumitomo joint venture and would expect to extinguish these carries by middle of second quarter 2011.

Lastly, on Slide 9, I would like to finish up the financial portion of our call by reaffirming our previous issued guidance for the first quarter and full year 2011. Patrick McKinney will now provide an update on our operations for 2010.

Patrick McKinney

Thanks, Tom. I'll begin on Slide 10 with our Butler County operations, where we operate on our 70-30 joint venture with Sumitomo. Looking at our entire position in Butler County, we have 34,100 total net acres with over 21,000 net acres, principally concentrated in a four-township area adjacent to the Dominion gas sales line and our Sarsen cryogenic gas plant.

Inception to date in Butler County, we have drilled 17 gross wells, 11 of which are completed and producing and six wells awaiting fracture stimulation. Rex is scheduled to frac the five well Drushel pad on March 1. And we are drilling on the second of the three well Talarico pad, which we have scheduled to frac in May. We have previously announced that we will pick up a second operated rig early in the second quarter and drill 24 gross, 15 net wells in Butler County in 2011.

The Sarsen cryogenic gas plant was commissioned in December 2010. We are presently producing approximately 20 million cubic feet per day into the plant, which has a current plant capacity of 30 million cubic feet per day. Current sales volumes at the plant are 22 million cubic feet equivalent per day. We expect the plant inlet capacity to increase to 40 million cubic feet per day by the end of the first quarter 2011. Given the upcoming five well Drushel pad frac scheduled for March 1 and the three well Talarico pad frac scheduled in May, we believe this gives Rex a real good chance of filling up the Sarsen Plant and its 40 million cubic feet per day inlet plant capacity in the third quarter.

We're also in the permitting process of our second cryogenic processing facility, which also has a 40 million cubic feet per day inlet capacity. We're expecting to have the facility commissioned sometime during the first quarter of 2012. I'd also like to add that we're in the process of closing out the acquisition of an additional 9,000 acres in the Butler area as required as part of our Sumitomo joint venture. Once completed, we'll begin growing Rex net acreage with our 2011 leasing program.

Slide 11 shows our drilling schedule for our Butler County operated area. We mentioned on the previous slide where we're at in regard to the Drushel and Talarico pad drilling. We want to give some more color on other pads that will be drilled in order to get to our 24 gross well count in 2011. At present, the vertical portion of all seven Grosick wells have been completed, and the wells are waiting for the horizontal drilling rig to drill the lateral portions of the well. The Grosick pad is being drilled as part of a unit, with Gas STAR as a non-op partner. As a result, Rex working interest in this unit will be about 42% as opposed to its normal 70%. The vertical rig is currently drilling the pilot hole on the last of the six wells in the Gilliland unit.

Of note, on the Gilliland unit, we have scheduled the drilling and completion of an Upper Devonian Shale horizontal test well. We would expect results from this well in the fourth quarter of 2011.

We expect the second rig to arrive in Butler during the second quarter of 2011. And at that time, the rig will begin drilling operations on the McElhinney wells. One last note on the drilling rig schedule. We have drilling permits in hand for all of these units and cleared all the title work. In fact, we are well on our way for the permits and the title work for our anticipated 2012 campaign in Butler County.

Finally, before we leave Butler County, as Dan mentioned in his overview section, we reported drill bit finding and development cost of $0.68 per Mcfe, which is primarily attributed to our efforts in Butler County. When you combine this with our reported transportation, gathering and lease operating expense of $1.50 per Mcfe, we have total cash cost to find, develop and produce of $2.18 per Mcfe. This is really the key to the economics in the liquids-rich section of the Marcellus Shale and the reason why we feel we can thrive at lower natural gas prices in this area.

Moving to Slide 12. We'd like to highlight some items in our Westmoreland, Pennsylvania project area, where Williams is the operator. As a reminder, Rex has a 40% working interest in this area. At this time, we have nine gross wells in service producing at an average rate of approximately 12.5 million cubic feet per day. Williams has completed drilling on the five well Uschak #2 pad and the wells are waiting for fracture stimulation at this time. Drilling operations are currently underway on the last of the three well Androstic pad and are also on the last well of the four well Uschak #1 pad. Williams is expecting to drill 20 gross resulting in eight net wells in 2011.

Our Midstream capacity is currently constrained at 14 million cubic feet per day in this area, but we expect to complete a jointly owned gathering system that will tap into the Equitrans pipeline in May of 2011. This expansion in gathering infrastructure will increase our capacity to a range of 26 million to 38 million cubic feet per day.

On Slide 13, the present drilling schedule is shown for our Westmoreland area. Again, the Uschak #2 wells have been drilled and are waiting fracture stimulation and completion. And the last well of the three well Androstic pad is in the process of being drilled. The second drilling rig in the Westmoreland area is drilling the last of four wells on the Uschak #1 pad. Of note here is the current gas sales bottleneck is being remedied by the expansion to the Equitrans pipeline, and Williams will have a total of 12 wells to be frac-ed by the end of the second quarter, early third quarter in an attempt to fill the previously mentioned 12 million to 24 million cubic foot per day increase in capacity.

Looking at the Central Pennsylvania project area on Slide 14, where Williams is also the operator. We now have four wells in line, producing on a total aggregate flow rate of approximately 6.5 million cubic feet per day. Right now, a vertical rig has begun drilling operations on the first of four wells on the Resource Recovery #3 pad. Back in October 2010, Williams completed tie-in to the Columbia Gas sales pipeline to initiate sales. The line has a current capacity of 10 million cubic feet per day with a present option to add another 30 million cubic feet per day. We are pleased that Williams is preparing this Resource Recovery pad for drilling because, as we mentioned, there's not a physical gas constraint in this area that would not allow us to ramp up production. I'd also like to provide a brief update on our ASP project in the Illinois Basin.

Moving to Slide 15. We have finished the injection of the Alkali-Surfactant-Polymer phase with a final pore volume of 25%. We're now in the process of completing the polymer push phase of the project and are at a total injection of 10% of the pore volume in this phase for a total injection of the project at 35% of pore volume. To date, we've had excellent run time for the ASP plant. We've not seen any indications that the pilot is not performing according to our testing and simulation model. We are still on track to announce preliminary results from this project by the end of the first quarter or early second quarter in 2011.

Looking at the summary of our Niobrara operations on Slide 16. As we recently noted in our operational update, all three wells have been drilled, fracture stimulated and are recovering load fluid with reported controlled test rates. All three have been on artificial lift with electric submersible pumps for the last two weeks. And as you can see, we still have roughly 50% or higher amounts of frac fluid load yet to recover. We've really been battling the winter weather in Wyoming, which has slowed us down considerably. Temperatures of minus 20 and strong winds have hampered our efforts.

Nonetheless, we’ve got the wells on pump and they're continuing to cleanup. We are selling oil daily at the Herrington well site. I mentioned previously our goal is to report a stabilized IP rate after the wells have cleaned up, and then report 30-, 60- and 90-day production averages. We believe that this is the only true way to get a reliable basis for an EUR on these wells.

We continue to work hard to analyzing the recently processed seismic data that we shot over the east Silo Field area. The quality of this data is great. We expect to be able to select a number of high potential drilling locations from this data. The seismic data shoot over the west Silo area should be available for our preliminary review in the next couple weeks. As we mentioned, we plan to pick up a drilling rig in the second quarter to restart our drilling program in the Silo area, and we have 11 additional drilling locations offsetting the Herrington well.

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

Daniel Churay

Thanks, Pat. This year, our story is about execution. We believe that we have three terrific sets of assets in Butler County, the Lawrence Field and in the Niobrara. In our acreage that includes four continuous Butler County Townships alone, we have line of sight to 400 potential drilling locations out of the over 500 locations that we have identified. This acreage is strategically located in the wet gas area, which is bisected by the Dominion gas line with terrific source of water for operations. This core area reduces the need for moving rigs and frac crews across long distances in Pennsylvania.

In Illinois, we have a position in one of the oldest oil fields in country. Our acreage is all held by production and provides a steady base of cash flow for the company. We are optimistic that our ASP pilot will show positive results at the end of this quarter or early next quarter, which can give us the confidence to continue the project to substantially increase production in this field. Finally, we are encouraged about the results that we have seen to date in our three Niobrara wells and are even more encouraged from the early views that we have reviewed from the seismic data that we have received in the east Silo Field. We are optimistic that this acreage can provide us increased exposure to oil that will add to the liquids-rich gas that we have in Butler County.

Therefore, in 2011, we'll be focused on seven priorities in these three locations. First and foremost, we will be focused on safety. Rex has had a good record on safety and environmental issues and we want to keep it that way. It's important not only to keep our employees and the employees of our contractors safe at the well site, but to remain an environmentally responsible steward of our natural resources in our operations.

Second, we will be focused on filling the Sarsen Plant as soon as possible. Again, we're producing at about 20 million cubic feet per day inlet to the plant. And with scheduled frac-ing of the Drushels and Talaricos, we could fill the plant at 40 million cubic feet per day by the third quarter.

Third, we're going to focus on completing our Butler County drilling program in anticipation of having additional midstream capacity from the Bluestone Plant in the first quarter of 2012. The permitting process for this plant has already begun.

Fourth, we expect to take what we've learned this past couple of years in the Marcellus to focus on improving well design and completions and reducing our F&D costs. We are looking forward to the contributions to some of the new technical members of our team in this process.

Fifth, we will continue to focus on lease operating expense and operational improvements in our Illinois and Indiana properties to maintain good base oil production from this area.

Sixth, we are looking forward to results from our 15-acre ASP pilot in anticipation of success for preparing the next larger unit for the next ASP flood.

Finally, as we said before, we'll be reviewing the seismic data from the east and west Silo Fields, as well as the information we've learned from our first three Niobrara wells, so we can top grade our drilling order and execute our five well Niobrara program this year. For these seven focus areas, we hope to drive home the execution this year to meet production guidance that we have released.

With that, operator, at this time, I would like to open the line for any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Leo Mariani from RBC.

Leo Mariani - RBC Capital Markets, LLC

Just wanted to focus a little bit on the Niobrara here. I guess you guys said that you got your wells on pump for the last couple of weeks. Have you seen any change in the production rate as a result of that?

Daniel Churay

Sure. I'll let Pat answer that question.

Patrick McKinney

Yes, the wells are cleaning up, Leo. We're pretty pleased with the level of gross fluid production that we're getting out of the Herrington in particular. And as we mentioned, we're selling oil every day. I really don't want to get into details on specific oil cuts. I can just tell you they're cleaning up.

Leo Mariani - RBC Capital Markets, LLC

And I guess, is it sort of stabilized production? Is the movement higher? Just sort of give us some kind of directional feel for what's happening as a result of putting the pumps on.

Patrick McKinney

The oil cut is increasing.

Leo Mariani - RBC Capital Markets, LLC

How about the total fluid? Is that increasing, flat, declining?

Patrick McKinney

The total fluid is about constant.

Leo Mariani - RBC Capital Markets, LLC

When do you guys plan to spud your next Niobrara well?

Patrick McKinney

We're in the process now of looking at the seismic, Leo, and we've got a couple of locations that look really good. We're in the process of going out and working out the final details with the drilling rig company, and we hope to get something spudded in the early second quarter.

Leo Mariani - RBC Capital Markets, LLC

I guess jumping over to the Marcellus here a little bit. Have you guys started to increase say, the lateral length on your wells in the 2011 drilling program? And do have sort of a target lateral length for anything here in 2011?

Patrick McKinney

Leo, this is Pat. We're taking a look at that now. I know a lot of other operators like Range and Atlas have come out kind of set their programs at about 3,500 foot in 10 to 12 frac stages. I think we're going to learn a lot from our Drushel fracs that we have upcoming. And I can tell you, we don't have any plans to really go much longer than our longest wells almost 4,000 foot right now. I would probably tell you we have more opportunity to increase rate with frac design than we would with lateral length extension.

Leo Mariani - RBC Capital Markets, LLC

I guess, in terms of your NGLs, I noticed that your price moved up pretty significantly in the fourth quarter in terms of what you guys are realizing. Just can you kind of walk us through that and then kind of what do you think NGL prices are going to shake out for you guys on the next couple of quarters?

Thomas Stabley

Leo, it's Tom. On the NGL pricing, our guys -- we're at about 50% in NYMEX is the number that we're at right now.

Leo Mariani - RBC Capital Markets, LLC

And you're talking about NYMEX oil?

Thomas Stabley

That's correct, yes.

Leo Mariani - RBC Capital Markets, LLC

So I guess, I mean any reason for the recent improvement? Have you started tab at different market in terms of how you're selling that or what's kind of the range?

Thomas Stabley

Both. With the turning on of the cryogenic plant obviously, the product that we receive out is more efficient. And then secondly, the marketing of the product because it's coming out of the cryogenic plant is going to a different location, and we receive better pricing as well. So both of those.

Operator

Our next question comes from Phillip Jungwirth from BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

Just looking at your 2011 production guidance, the chart in the presentation and then focusing specifically on the oil component. It looks like the midpoint of 2011 implies roughly flat oil production growth. But if I look at your year-end negative rate, it looks like you're forecasting about 30% year-over-year oil growth. I'm just wondering what the assumptions are behind this and if you could split that out between running one rig in the Niobrara in your ASP project.

Daniel Churay

We don't have anything now for the ASP project in the guidance at this point. Tom can give you more detail on the other.

Thomas Stabley

Yes, any increase in the oil production that's associated with those figures would be a result of the Niobrara.

Phillip Jungwirth - BMO Capital Markets U.S.

So you think you can get that type of growth by year end just running one rig in that play?

Thomas Stabley

I don't think the increase in the oil production is 30% on this. I'm not sure where you got that number.

Phillip Jungwirth - BMO Capital Markets U.S.

I can circle back if you will. I'm just looking at the 2011 mid-case exit rate, the purple bar. And then, just on the Niobrara and then looking at the Herrington well, it IP-ed at 408 barrels a day and 450 BOE a day. After including the infrastructure costs to take that gas away, is there any present value still associated with that gas?

Patrick McKinney

Phil, this is Pat. I'll just make a point that the rate that we put out on the Herrington was actually a test rate. So I wouldn't necessarily call it an IP rate. But nonetheless, it's a rate. As far as the infrastructure, we're modeling internally about 18 months until we get gas sales out in that area. There is no infrastructure out in that part of the Silo Field on the east side. So we're delaying any economic value from the gas for about 18 months.

Phillip Jungwirth - BMO Capital Markets U.S.

And then on the Marcellus, it didn't sound like -- I mean, other operators like, as you mentioned, ETT is down. They're talking about 5,300-foot laterals. It didn't sound like you guys were looking to increase your lateral length, at least near term. But if you did longer term over the next six months or 12 months or so, decide to increase the lateral length, how would that impact your ability to hold the acreage? If you've looked at that yet.

Patrick McKinney

With our two rig program that we've got laid out, we feel very confident we're going to handle any lease expiry issues here in 2011 and even into 2012. So I think as we may have mentioned before, when we go and do these pads, we'll typically drill, what, two to four wells on maybe an eight-well pad that's already laid out between 600 and 900 acres. And we'll hold the acreage with those wells and move on and then have what we call the B pad portion to come back and drill at a later day.

Operator

Our next question comes from Neal Dingmann from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Just wondered on overall oilfield service costs. I assume over on the Marcellus because the pad drilling you're able to keep those down, just wondered if you can give us a quick comment on what you see there. And then, obviously, on the five well program on Niobrara kind of what you're anticipating for complete. Obviously, it sounds like the rig’s locked in for more on the completion cost.

Daniel Churay

We'll let Pat give a little more commentary. But as you know, we've locked in our frac and drilling costs over a two-year period. Frac costs, we get at least two weeks a month from our vendors. So we feel pretty confident there. We've got a 4.7 million kind of target or less in terms of each of our Marcellus wells. And then out in Wyoming, I don't think you were seeing a tremendous amount of pressure there, just a different sort of well. We’ll let Pat give you a few more details about that.

Patrick McKinney

The frac, the high-pressure pumping costs obviously are up. They're going to be up for us probably around the 30% range over 2010. And as Dan mentioned, we locked those in. We feel pretty good about the other prices. We locked in a flat rig rate with Union Drilling in the Marcellus. Our tubular costs are flat to slightly down and a lot of the other service costs, we do have that scale now that you mentioned in the Butler area. So we're going to really focus on taking the drilling days down to start to take that 4.7 million number in Butler and take it down. So we're working on that. And also in the Rockies, with the way we complete these wells, you're just not going to put as much pressure on the frac companies to really be as tight as other areas. And the drilling costs, since it's shallower in the Niobrara, you don't need the new generation rig, so you can tend to keep those costs on the lower side.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

And then, back over in Butler, just I guess the overall Marcellus in general. How cap -- I guess, I'm wondering is your liquids takeaway? Is there some options if where you're taking that now pricing becomes a little tight, are there other options to take that away?

Thomas Stabley

Yes. Neal, it's Tom. At the present time, we rail it out to Aux Sable, but we do have some other options that we can take it to. And right now, the capacity at Aux Sable is available and don't foresee any problems in the future.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Just on the Lawrence Field, you mentioned a slide about the initial results expected late first quarter, early second. Based on these results, I mean, should we expect, based on what you see, are we going to see any different in operations there? Or is it pretty much set for this year?

Patrick McKinney

This is Pat. In the capital budget we put out, we only have a small amount for kind of the tail of the ASP, which is the polymer push. What we plan to do is go back and with the results, go back and take to the market a plan of development going forward. And we assume we're going to be successful and go ahead and layout that plan at that time late first quarter, early second quarter.

Operator

Our next question comes from Brian Lively from Tudor, Pickering and Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Just looking at the Marcellus and coming back to the NGL realization question from earlier. Within your 2011 guidance, just curious of how much condensates you're actually producing out of the Marcellus versus NGLs?

Patrick McKinney

Yes, Brian, this is Pat. We produced very little condensate that's actually separated out at the wellhead. I would say 99.8% of our liquids production volume is NGLs out of the plant.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

So that's not a driver in getting a better sequential realizations on NGLs, it's the other comments that Tom mentioned earlier then?

Thomas Stabley

Yes, that's absolutely correct. It's the start-up, the cryogenic plant and then the transportation out to a better market.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

In the Niobrara, some of your previous comments have been that you have some confidence in the matrix contributing to production. Just curious of what you guys are monitoring to come to that conclusion? Is that just within the Silo Field? And then, is that also as you get down to the southeast in some of your other acreage?

Patrick McKinney

Brian, this is Pat. I mean, really, if you go back and look at the production history, we've got 20 years of production history in the Silo Field. You can tell from the shape of those decline curves that you're getting fracture contribution as well as some matrix. Because that's the only way those wells can cume with the prior frac technology, which was just one-stage job or just open hole slotted liners. As you could get that type of production, you got to have some matrix with it. We're probably also encouraged by the fact that we've seen 11% and 12% porosity in the Niobrara, in the Chalk sections. So that's reservoir quality that's really good enough to have some matrix contribution.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And then, how does that work and just what you've seen whether it's from old logs, whatever, stack up with the acreage down into Colorado?

Patrick McKinney

Well, down there, we have old logs and probably not as much well control as we'd like. I think we've mentioned previously that we're going to drill one well in 2011 in Weld County in that Colorado acreage to actually hold some acreage. So I think we're looking forward to drilling that well live unit taking a look at it, really see what we got down there. But we're offsetting some prior Niobrara production, so we feel pretty good that the reservoir quality is pretty good down there. But we need to drill a well and see what we've got.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Are there any just general trends from a geologic standpoint? Does natural fracturing decrease as you go to the east or porosity improved? I mean, how are you guys thinking about it?

Patrick McKinney

We got to see the seismic. I mean, at the end of the day, the seismic is going to tell us a lot out there. And so we're looking forward to analyzing the seismic and the quality of the data has been really good. So I think we're going to base any comments after we have a chance to review that seismic.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

On the 2010 reserves, what's the future development cost in the PV-10 calculation?

Patrick McKinney

If I can't get it here, we'll get back to you. But let me take a quick look. For the total proved reserves, it looked like future capital cost is about $1.5 billion.

Operator

Our next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

I guess staying on the reserves. Looking at your PUD reserves in the Marcellus, it looks like -- I try to back into a gross EUR per well. It looks like it's a little bit under four Bcf, does that sound about right?

Patrick McKinney

No, it's gross. It's 4.4 Bcfe.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

What's the reserve life on those?

Patrick McKinney

We're running those out to economic limit or 50 years.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

So some of them do stretch to 50 years?

Patrick McKinney

Not a lot, but the most are between 30 and 50.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then, following up on the last question on the Niobrara, so it sounds like you expect to be able to see natural fraction with the 3D?

Patrick McKinney

I don't think -- if anybody tells you they can truly see it, that's really not true. I think what the geologists feel comfortable they can see between the faults and how things are laid down in underlying salt, they can see areas that would appear to be more busted up just by the geology. But you can't really go in and identify the extent of natural fracturing. I think we're going to be able to identify areas that are going to be a lot prone to natural fracturing. And then, based on some logs and other things, that we give you a higher degree of confidence you're going to get into an area that has a lot more fracture contribution.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And both the BJB and the Herrington, I guess the Silos State well for that matter as well, those were all completed in the B-bench, is that correct?

Patrick McKinney

That's correct.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Do you see any potential for any other Niobrara zones like the C for example?

Patrick McKinney

Well, I think we did micro-seismic on two of those wells, Mike. And I would tell you we're getting everything that's down there.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then, back to Marcellus, you mentioned you’re actually going to be drilling an Upper Devonian test this year. Any plans for a Utica test as well?

Daniel Churay

We're looking at a possibility of doing that in the fourth quarter, but it's not something that we're rushing to do. We continue to see what other folks are doing in the area, and we'll plan something around that time.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And would you add a rig for that? Or can use your Union rigs in Butler for that?

Patrick McKinney

Mike, this is Pat. We'd have to get a little bit more horsepower for that because it's going to be about 3,000-foot deeper. And so we need a little bit more pump pressure and a little bit more hook load. So we would have to get another rig.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And it looks like your outspend of cash flowed by a fair amount this year. Any plans to divest of any non-core assets?

Thomas Stabley

We don't have any current plans to do that. There's always a possibility of selling some of our non-core properties in the Illinois Basin, but there's no pressing need to. We're obviously in the process of having our borrowing base redetermined, and we'll continue to look kind of the overall portfolio whether JVs make sense, whether the non-core assets make sense, whether a high yield offering at some point makes sense. Those sorts of capital decisions we're reviewing and we'll know more about as the year progresses.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Daniel, for you, I guess you talked about some personnel changes you've made. Can you elaborate on those a little bit? And maybe what you might be trying to do differently for the company going forward?

Daniel Churay

I think what we're trying to do is build a deeper technical bench, and I think we've done a pretty nice job this past year doing that. We've got a terrific VP of Land on board. As we said, all of our title is clear for 2011, and he's working on 2012. We brought on a Director of Reservoir Engineering, a Completions Engineer and a Drilling Engineer, all focused on the Marcellus. We've recently hired a young Masters in Petroleum Engineering to help us with ASP project. He's actually worked on these projects at UT, for us. So our bench is getting a little bit deeper. We're very much focused on execution and project management and having the right people to lead each of these basins. We've recently also hired a Basin Manager for the Rockies with over 20 years of experience. So I think these sorts of people are adding and contributing greatly. I think we've improved a lot fourth quarter to prior quarters. And in this quarter, I think we're improving even more by having kind of the right technical and project management mindset around the company.

Operator

Our next question comes from Jeff Hayden from Rodman & Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

First, kind of jumping over the Niobrara. It looks like you all have picked up about 5,000 or so net acres really from kind of the last official update. Just wondered if you could give a little color on where some of that acreage was. Was it more kind of around east Silo and Wyoming, maybe down in Colorado? And kind of what prices break are you paying for that?

Thomas Stabley

Yes, Jeff, it's Tom. It's probably about 50-50, where we picked that up, part of it down in the Colorado area, and then some additional up in the Wyoming, both in our state line area and east Silo. And as far as the price, I don't think we'll talk about that right now, but it's still at a very reasonable level.

Jeffrey Hayden - Rodman & Renshaw, LLC

And then, one thing just a little clarification, make sure I'm kind of thinking about the guidance in the right way. In the slide when you guys break out kind of the percent production oil, is that just oil? Or is that oil and NGLs?

Thomas Stabley

Well, we break it down on the slide, that's Slide 7, and I think Phil was referring to it. I looked at it where we talk about 22% to 40%, it's growth in oil and NGL production. So the slide breaks it down, the purple section would be the oil and then the green section would be the NGL and condensate.

Jeffrey Hayden - Rodman & Renshaw, LLC

And that was Slide 7.

Thomas Stabley

That's Slide 7 in the corporate presentation, Jeff.

Operator

Our next question comes from Ray Deacon from Pritchard Capital.

Raymond Deacon - Pritchard Capital Partners, LLC

I was wondering, what do you expect recoveries to be in the first and second year out of a Butler County well?

Patrick McKinney

Well, Ray, this is Pat. I mean, as we mentioned for the reserves, we haven't changed the decline curve from the prior year, which is still pretty much a typical Marcellus decline curve. I think we want to see these wells produce now for a period of time through the plant and really have them establish their curve. We’ve really only got the Penop [ph] well, which probably has only declined 20% in the year and a half it's been on in kind of in a restricted flow environment. So I really can't give you that answer. What we think they're going to be going forward. From the reserves, we've got first year declines at 88%. So they're pretty state. So we're hoping we'll be able to do a little bit better than that when we get these wells on and get them flow tested for a period of time.

Raymond Deacon - Pritchard Capital Partners, LLC

And up in Wyoming, are you seeing any other activity by other operators drilling wells up there? Or are you guys kind of the pioneers on that? I know EOG has got some acreage up there.

Patrick McKinney

No, I mean, around us in that part of Wyoming, there's a few smaller operators that are up there drilling. We've been able to kind of get a feel for what's going on with them. And all of them really have had a lot of the similar issues that we've been talking about, where the wells are normally pressured to slightly under pressured. They're not going to flow for a long period of time. They've had sand control issues. They've had emulsion issues. And so I think most of the other operators are in similar camps that we are. It'd be nice if Noble and others would announce more of their results, but and/or EOG. So we’ll have to stay tuned with them. But we don't have as much activity right around this in the Silo Field, most of it's a little further south.

Raymond Deacon - Pritchard Capital Partners, LLC

And $4.5 million for a gross well cost in the Marcellus, is that fair?

Patrick McKinney

Well, we're listing $4.7 million and that's what's in our reserves. As we've touched on a little bit here today, the frac cost is kind of locked in at $2.2 million or so. We're going to work hard to cut the drilling days in Butler because we are so centrally located. We think we’ve got a great advantage to really be able to go and knock some days off of these wells and are managing towards getting that number lower and also managing towards looking at the performance of those wells and getting the EURs up, which are both going to improve the economics for these wells.

Raymond Deacon - Pritchard Capital Partners, LLC

The acreage that you acquired in Butler, is that contiguous to what you already own?

Thomas Stabley

Ray, it's Tom. Most of the acreage is filling in additional drilling units, and it's all contiguous to what we have.

Operator

Our next question comes from Ron Mills from Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

In the Marcellus you talked about the well costs and the EURs of 4.4 Bs. Are the EURs -- are you still using varying EURs Butler County versus your Westmoreland/Central PA?

Patrick McKinney

Yes, as we are, Ron. We're at 3.0 Bcf in Westmoreland and Clearfield and 4.4 in Butler.

Ronald Mills - Johnson Rice & Company, L.L.C.

And of the 4.4 in Butler, how much of that do you expect one to be in NGLs versus gas?

Patrick McKinney

Roughly probably 20% of the equivalent volumes.

Ronald Mills - Johnson Rice & Company, L.L.C.

And a follow up on I think Mike Scialla's question earlier, Utica versus Upper Devonian. I know as you move north through Pennsylvania, there's been talk that the Utica could become more liquidy as you move towards northwest Pennsylvania. If you end up touching that, would you still expect to be within the gas window within the Utica?

Thomas Stabley

Well, Ron, it's Tom. I mean, our early indications, I mean obviously, we don't have any wells that go down that deep. But we do think that as we move to the north and west just as you indicated that we could potentially be in a wet gas area. But it's very early to make that assumption.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then, I think you'd had one of -- another company has actually drilled a well to the Utica not far from your acreage in Butler County or near Butler County. Has there been any, I guess, intelligence gained off of that?

Thomas Stabley

No, not at the present time, maybe just what we hear in the open market. I mean, we haven't had any additional conversation. I mean, Range announced that well. It's about seven miles from our acreage in Beaver County. Obviously, we've seen the flare and pay close attention to what we can from afar, but that's all we know at this time.

Ronald Mills - Johnson Rice & Company, L.L.C.

And maybe, Pat, for you or maybe, Tom, from an economic standpoint. Pat, you were walking through in Butler County the finding cost and the all-in finding cost. I missed a couple of those numbers. But not just from a reserve standpoint, but also due to the liquids component and the higher price realizations, is there a thought that you could -- I mean, you're just talking about going to a second rig, but the economics there are obviously much better. What are Williams’ plans in the gassy area versus what you would like to do in more the liquidy area?

Daniel Churay

This is Dan. I think, first, we've got a plan to hold back production. So with an A and B pad on most of these units, we think the two-well program and maybe adding a third towards the end can hold everything by production. And given the current gas environment, we think that's probably kind of the prudent step to go forward. Clearly, Williams is in the drier area and we'll continue to evaluate our participation over time in that area.

Ronald Mills - Johnson Rice & Company, L.L.C.

Pat, you talked about the well costs in the Marcellus. What are your wells costing in the Niobrara right now? And are you still -- I mean, it's still early for you all, but believe that the industry expectations of 250,000 to 400,000 barrels is kind of the right target in the Niobrara?

Patrick McKinney

Yes, Ron, I think they are. I mean, the first two wells, the Silo State and the Herrington, we drilled, we did a lot of extra things that we didn't do on the BJB. So those wells were a little bit out of bounds as far as cost. On the BJB well, we got in pretty quick, drilled it, completed it and put it on pump a lot quicker than the other wells. So that well is going to be in this 3.5 million to 4.2 million range. We think that over time, we should be able to consistently be under 4 million out there. And then, to your last point, I really think that you can start getting 200 to 400 type EUR ranges. I think you're going to have to really -- it's going to be a statistical play, and you're going to have some wells on the lower end of some on the higher end and a bunch in the middle. But just based on what the history is at the Silo Field, you've got a number of wells that were just drilled with slotted liners that produced over 200,000 barrels. So we still kind of go with that range out there, and we hope to get better at it once we start taking a look at Sarsen.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then lastly, on the cost side, I know in the Marcellus you have the agreement with Frac Tech and Union. And so the 30% higher pressure pumping cost that you talked about, I'm assuming incorporates the agreement you have with Frac Tech starting up here in April.

Patrick McKinney

Yes, it does.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then going forward, is that something that you would also pursue in the Niobrara as pressure pumping -- I think, I've heard it’s not as big of an issue there as it is in some of the other basins.

Patrick McKinney

I think we're going to look at it. I mean, I think once we kind of set on what level of activity we're going to have out there, we can definitely look at that

Operator

We do have a follow up from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

On your CapEx, you'd mentioned you had some additional CapEx in Illinois. How much was that? And what was that for?

Thomas Stabley

That number was about $3.5 million to $4 million and was for some line clean outs mainly in the waterflood fields.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then you'd said you'd spent more on the Niobrara for an extra well. How many did you budget?

Thomas Stabley

Well, the original plan that we had put out was for just the Silo State and the Herrington well. And obviously, we were able to finish the BJB well completely. So that was the third well that we discussed.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And then lastly, can you break out of that 45,000 net acres that you have now, how much is on the west side of the Silo and east side and how much is in a well?

Patrick McKinney

I think and we'll get back to you with the exact numbers, but I believe it's about 5,600 acres in west Silo and about 1,500 on kind of the east Silo and as you start to get a little further south towards the state line area. Out of the 45,000, Tom jump in here, I think we still have basically around 10,000 in Colorado.

Thomas Stabley

Yes, it's about 10,000 in Colorado and the remainder is in Wyoming.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

You've got 1,500 on the east and 5,600 on the west. . .

Thomas Stabley

The rest of it would be the state line acreage that you see southeast of the Silo Field.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

And do you view that as essentially the same sort of geologic setting as Silo, or is that different?

Patrick McKinney

No, we view it similar as we sit here today. I think we're all going to learn a lot more here once we get the seismic done. But as we sit here today, it appears to be a similar rock.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Does that seismic cover that southern acreage? Or is this just on the east and west sides so far?

Patrick McKinney

It's just on the east and west, and we're looking at -- seeing if we can get another joint chute down in that state line area, but it will not cover that state line area.

Operator

Our next question comes from Ray Deacon from Pritchard Capital.

Raymond Deacon - Pritchard Capital Partners, LLC

I just had a question about the way the mechanics work on the accounting with the gathering. Will there be a gathering charge? Or is it just netted against the lease operating expense? I mean, I'm sorry, gathering credit, I guess for your ownership.

Thomas Stabley

No, on the accounting for the Midstream services in Butler, that's under the equity method. So what we recognize on the financials is the percent of proceeds cost for the actual plant, goes into our LOEs. And then, there's a per Mcf charge on the transportation side. Ray, that's all included on our slide in the Butler section of the corporate presentation. I think it's $1.48.

Raymond Deacon - Pritchard Capital Partners, LLC

Any concerns about being able to market with the new plant, the NGLs? Or where do those go? Or do you market those or does your partner, I think?

Thomas Stabley

Enbridge actually markets them for us, and they get railed out to Aux Sable in Chicago. And at the present time, we have no concerns about being able to get those out and get it marketed.

Operator

I am not showing any further questions. I would now like to turn it back for any other remarks.

Daniel Churay

Well, again, we appreciate everybody joining us today, and thank you very much. Talk to you later. Goodbye.

Operator

Ladies and gentlemen, this does conclude today's program. You may now disconnect, and have a wonderful day.

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