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Rex Energy (NASDAQ:REXX)

Q1 2011 Earnings Call

May 04, 2011 10:00 am ET

Executives

Daniel Churay - Chief Executive Officer, President and Independent Director

Patrick McKinney - Chief Operating Officer and Executive Vice President

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

Analysts

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

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

Jeffrey Hayden - Rodman & Renshaw, LLC

Operator

Good morning, ladies and gentlemen, and welcome to Rex Energy Corporation's Conference Call to discuss its first quarter 2011 financial results. [Operator Instructions] I would now like to introduce Tom Stabley, Executive Vice President and CFO of Rex Energy.

Thomas Stabley

Good morning, and thank you for joining us for Rex Energy First Quarter 2011 Financial Results Call. Dan Churay, President and CEO of Rex Energy; Patrick McKinney, our Chief Operating Officer; and I will provide you comments this morning. Now for our disclaimers.

Statements made by management during this call and 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 filing.

Moving on to Slide 3. In addition, please see today's release for 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 will refer to the non-GAAP measures of adjusted EBITDAX simply as EBITDAX.

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

Daniel Churay

Good morning, everyone, and thank you for joining as we discuss our financial and operational results for the first quarter of 2011.

Last quarter, we discussed 7 main focus areas that Rex would execute against in 2011, which have been reproduced on Slide 4. Let's review our progress against each.

Let's start with Butler County, Pennsylvania. There, our principal focus area is to fill the Sarsen plant as soon as possible. As you may recall, we commissioned our Sarsen cryogenic gas processing plant last December. For the month of April, we averaged 24 million cubic feet per day with the current plant capacity of 34 million cubic feet per day. We expect the plant to reach its full capacity of 40 million cubic feet per day, by the end of the third quarter after installation of field compression. Our goal to fill the plant should be well on its way as we complete the Talarico and McElhinney wells during the second quarter.

We are anticipating having a second cryogenic gas processing plant, the Bluestone Plant, commissioned early next year. As we have executed our Butler County drilling program this year, drilling days per well have been reduced, which has put us ahead of our schedule for 2011 drilling program. As a result, we have added another 9 wells to our drilling schedule to build an inventory of wells available to be fracture stimulated should a plant be commissioned earlier than expected. This in turn can put us in a good position to fill the Bluestone Plant when it's operational.

Rex continues to strive to improve production levels and each new Marcellus gas well are using lessons learned to improve our drilling and fracture stimulation techniques. Taking into account the learning from each prior well, the data that we have accumulated and the microseismic testing that we have performed, we are learning the best methods to drill and fracture stimulate our Marcellus wells to increase production on each new well.

We have experienced continued improvements in our IP and early production rates. While it's too early to declare a sustained trend, we are cautiously optimistic that these improved techniques can increase our average production rates. Likewise, we are working to improve our F&D cost. As mentioned earlier, drilling days per well have been reduced which has lowered than our cycle times. Improved cycle times can form the basis of improved well costs. Our new technical personnel have greatly contributed to this process.

In our Illinois and Indiana oil fields, we are concentrating on reducing production declines and per unit lease operating expenses. Since the end of 2010, we have increased average daily production in our Illinois Basin operations by 1% while at the same time, decreasing lease operating expense per barrel of oil by 4%. Comparing our first quarter 2011 results to the first quarter 2010, LOE per barrel of oil has decreased by 3%.

We are also working to complete our Lawrence Field ASP program in our Middagh Unit and to prepare the Perkins-Smith Unit for ASP flooding. We are seeing positive results from the Middagh ASP project area with increasing oil cuts and oil production. Pat McKinney will provide you with more details on this later in the call.

As a result, we have the confidence to increase our capital budget for the ASP program by $3 million to fund the larger 58-acre ASP project in the Perkins-Smith area. Results from the Middagh ASP are being analyzed to maximize oil recovery in the Perkins-Smith Unit. ASP injection on the Perkins-Smith Unit is expected to begin during the fourth quarter this year following brine water injection, which we expect to commence shortly.

In addition to Appalachia and the Illinois Basin, we have focused our Niobrara acreage in the DJ Basin. Seismic data from our Silo Field operations is currently under review. We are in the process of selecting top drilling locations to execute our drilling plans in the Niobrara starting with the Steege 11-31H well, which is currently being drilled. We have identified several locations of high natural fracturing in the East Silo area, which may lead to higher production and ultimate recoveries.

Finally, our first focus area is to maintain a safe workplace, free of injury and environmental damage. We continued our safety focus in the first quarter with no significant accidents. In addition, we're drilling all our Marcellus operated wells in a closed loop environment. Utilizing closed loop drilling systems, we are not using open pits to dispose the drilling mud and cuttings. Rather, any remaining solids from the drilling process are being sent to landfills that are permitted to receive these solids.

Recently, the Pennsylvania Department of Environmental Protection called on all Marcellus Shale gas operators to cease delivering wastewater from drilling operations to 15 facilities that Pennsylvania currently permits to accept it. We reuse our frac water multiple times before we ultimately dispose of the remaining flowback. However, until DEP concerns are satisfied, we along with other members of the Marcellus Shale coalition, have heeded this request and ceased disposing of any remaining flow backwater at these previously permitted wastewater treatment plants. We are now trucking our wastewater to permitted injection wells in Ohio.

On Slide 5, I'd like to highlight some key takeaways from our first quarter operations. Our overall production increased 22% over fourth quarter 2010, and increased 46% above first quarter 2010 production levels. Operating revenue also increased up 25% over fourth quarter and 50% over first quarter 2010. This increase is attributable to our increased production primarily in Appalachia, as well as increased sales prices for crude oil. We always aim to reduce our lease operating expenses. We saw a decrease of 7% and 17% in lease operating expense per Mcfe from fourth quarter 2010 and the first quarter 2010, respectively. We consider this a good sign that we are accomplishing our operating goals to reduce lease operating expenses per unit of production. As a result of our increased production, revenue and decreased lease operating expenses, our EBITDAX grew 39% over year end and 69% over the same period in 2010.

We were very pleased with the performance of our cryogenic plant in Butler County and minimal experience of downtime. During the quarter in Butler County we drilled 10 gross, 6 net wells and our partners Williams, drilled 10 gross, 4 net wells in Westmoreland and Clearfield counties. And as I stated before, we have begun to see a response from our ASP Middagh program and are encouraged by positive results for the program.

I'll now turn the presentation over to Tom Stabley, Executive Vice President and Chief Financial Officer, to discuss our financial results.

Thomas Stabley

Thank you, Dan. I will begin on Slide 6, where I'd like to draw some attention to a few items. Production levels in all commodity types have increased compared to the fourth quarter of 2010, with an overall increase of approximately 5,000 Mcfes per day or 22%. Our natural gas production increased 34% over the previous quarter, which is primarily the result of our operated area of the Marcellus Shale and Butler County. Our natural gas liquids production increased 223% over the previous quarter, which is attributable to the new Sarsen processing plant being operational for the full quarter. Natural gas liquids this quarter received $48.84 per barrel, which is approximately 52% of NYMEX quoted average price of oil for the quarter.

Moving on to Slide 7. As Dan pointed out early in the presentation, our total revenue after the impact of derivatives grew 25% over the previous quarter to $24.8 million. Lease operating expenses for the period were $7.2 million, which was an increase of 11% over the previous quarter. However, this total is in line with our previous issued guidance. This amount also included a onetime charge of $200,000 associated with the decommissioning of the Yellow Creek refrigeration plant after it was replaced by the Sarsen plant.

Cash G&A exceeded previous issued guidance of $5.3 million. The increase was attributable to costs associated with the company's leasing lawsuit and costs related to the recent management changes and our hiring of additional technical staff. Exploration expense for the first quarter was $0.7 million higher than in the fourth quarter of 2010 or $3 million in total. Most of the expenses was due to the completion of our 3-D seismic in the Silo area of Wyoming, also our Westmoreland, Centre and Clearfield counties in Pennsylvania. The total also includes microseismic testing related to the monitoring of fracture stimulation operations in Butler County, Pennsylvania.

Moving on to Slide 8. Our current hedging position is summarized on this page. The company has taken advantage of the current increase in commodity prices to begin hedging portions of its 2013 production. As noted on the slide, the percentages hedged is calculated using the low case of our provided second quarter guidance on Page 11 of this presentation. Lastly, the company continues to maintain a high percentage of natural gas hedged at floor prices that are on average above $5 per Mcf. If you would like more details, information on our hedging position, please refer to the hedging tables located in the appendix portion of this presentation.

Moving on to Slide 9. We have our consolidated balance sheet. I'd like to highlight some of the key areas. Rex continues to maintain a strong balance sheet with a strong cash position and low debt levels. With only $30 million drawn on our revolving line of credit, the company has $130 million still available. The next re-determination for the line is scheduled for July of this year and should reflect any additional interim reserves from the production it has incurred so far this year. The company also ended the first quarter with $6.4 million in drilling carries remaining from the Sumitomo joint venture deal, which will be fully extinguished during the second quarter. We feel that our case position, joint venture drilling carries and line of credit put us in a good position to continue executing on our current capital investments for the remainder of 2011, especially in light of the improved commodity pricing environment that we have experienced.

Moving to Slide 9. As a result of our successful leasing, accelerated drilling in the Marcellus operations in Butler County and preliminary results for the company's ASP flood, we have increased our 2011 capital investment budget by $26.7 million. This increase in drilling capital will position the company to accelerate production should the Bluestone cryogenic plant be commissioned early. The company plans to fund this increased budget through an increase in cash flows associated with higher commodity prices and the existing line of credit.

Going to Slide 11. I would like to review our second quarter and full year 2011 guidance. We expect our second quarter daily production to be 30.6 million to 32.2 million cubic feet equivalent per day. This would represent growth of approximately 10% to 16% over quarter one. We are factoring into this increase a reduction of approximately 285 gross barrels per day for a 60-day period in our Illinois Basin due to the extensive flooding that is presently restricting our operations.

Although we are upstream from Cairo area, Illinois flooding that you may have been reading about in the press, we have experienced greater flooding than usual as floodwaters backed up from that point and rain continues to fall. Full year guidance for the production will remain unchanged.

As discussed in the previous slide, we are increasing our capital budget from $148.7 million to $175.4 million for an increase of $26.7 million. Lease operating expenses and cash G&A amounts for the full year will remain unchanged from previous issued amounts.

Lastly, we have a shelf registration statement filed with the SEC that we used earlier last year to issue shares of common stock. We expect to file shortly a new shelf registration that will include both debt and equity securities. We have no current plans to draw on this shelf, as we believe that our existing cash flow and revolving line of credit are sufficient to meet our capital needs this year and into next. Even so, as a public company, we believe that it is prudent to maintain financial flexibility by having a shelf in place. Therefore, we expect that we will file a shelf in the near future.

I will now turn the presentation over to Pat McKinney, our Executive Vice President and Chief Operating Officer.

Patrick McKinney

Thanks, Tom. Moving to Slide 12, and focusing our operated Marcellus area in Butler County. As Tom mentioned, we now have increased our acreage position here by 3,000 net acres in the quarter to approximately 37,000 net acres. This is consistent with our strategy of filling in future drilling units and other contiguous acreage blocks in our core operational area.

As we've discuss today, we're decreasing the cycle time for drilling completions at our Marcellus operations in Butler County. We are benefiting from the strategic contracts with our drilling company, Union Drilling, and our high-pressure pumping company, Frac Tech, in executing our program here in 2011.

Moreover, the geographic concentration of our pads translates into shorter rig moves, shorter pipeline connections and synergies related to water sourcing and completion operations. Our recent well results at our Drushel pad were the first wells that we used to enhance completion designs, which utilize more sand and tighter clusters on the completion interval. We are pleased that the 30-day rates have hung in there and averaged 3.6 million cubic feet equivalent per day on 3 of the wells that received the full enhanced frac designs. As a reference point, these rates have exceeded a tight [ph] curve that we have used for the last 2 years for our proved reserve bookings in Butler.

Lastly, our Midstream partners, Keystone Midstream, have increased the plant throughput design for the Bluestone cryogenic plant from 40 million to 50 million cubic feet per day. The plant is in the permitting stage with the Pennsylvania DEP but all the long lead time components have been ordered, the plant site is secured and local permitting is in queue. We hope to break ground on this location in June. We also have filed our permit for a third cryogenic plant with the Pennsylvania DEP.

Slide 13 shows our drilling completion scheduled for Butler County. The company completed drilling at the 3-well Talarico pad and began fracture stimulation process on May 1. We've completed drilling 4 to 7 wells on the Grosick pad. The company's second operated rig, Union Drilling #52, completed drilling both wells on the McElhinney pad and the company has scheduled fracture stimulation for late May. The company has now moved this rig to its Behm pad, where it's drilling the second of 3 wells.

Rex has also contracted a third rig in Butler County, Bronco Drilling #10, which arrived in late April. The company has retained this rig for a 7-well commitment. This third contracted rig is currently drilling the first of 6 wells on the Gilliland pad, which includes Rex Energy's first Upper Devonian Burkett test well. Subsequent to the drilling of the Gilliland pad, the company has scheduled a rig to drill its first Utica test well beginning in July 2011.

Before we leave this slide, we mentioned earlier the Sarsen plant is currently capable of processing 34 million cubic feet per day of inlet gas. Installation of field compression late in the third quarter is planned to take this plant to its full capacity of 40 million cubic feet per day.

Subsequent to the completion of the Drushel wells, the plant has averaged 24 million cubic feet per day of inlet production for the month of April. Rex plans to continue to fracture stimulate and fracture stimulation drilling efforts through the remainder of 2011 to fill the Sarsen plant. The company also plans to build an inventory of wells available to fracture stimulate in anticipation of commissioning the Keystone Midstream second cryogenic gas plant, the Bluestone Plant, which is scheduled for completion in the first quarter 2012. From the numbers we have shown here, we would be at a 14-well inventory by year end available to complete.

On the non-operated areas on Slide 14 where Williams is the operator, in early May, Williams completed Phase 3 of its midstream pipeline through the new Salem Beagle Club tab into the EQT natural gas pipeline, which is capable of receiving up to 24 million cubic feet per day. Williams has completed frac-ing 2 of the 5 Uschak wells in Westmoreland County. The 2 wells had a combined average 5-day rate of 7.6 million cubic feet per day. Williams has placed these wells into sales through the new Salem tab.

We are also very encouraged by the performance of 2 Slavek Trust wells in Westmoreland County, which has averaged 3.4 million cubic feet per day each for the first 155 days of their production. These rates exceed the company's existing type curve for this area. Williams expects to frac an additional 4 wells in Westmoreland County during the month of May.

Moving to Slide 15 and looking at the Williams drilling and completion schedule, Williams completed drilling on its 2-well National Metal pad. The first rig has spud the first of 2 wells on the Frye pad, and the second rig is currently drilling the second of 3 wells on the Marco pad. The Patterson 480 rig will be released after drilling of the Marco pad.

In Clearfield County, Williams has recently commenced drilling with a third rig on the first of 4 wells on the Resource Recovery #1 pad. This rig will also be released after drilling in Clearfield County, so Williams will finish the second half of the year with 1 operated rig. Williams has also begun pipeline expansion into the Resource Recovery lease and expects completion during the third quarter of this year. Williams plans on frac-ing the remaining well inventory over the course of the year to match pipeline infrastructure increases.

Shifting to Slide 16 in our Lawrence Field ASP update. We are very excited to announce that we have seen preliminary oil response at our pilot. The 15-acre ASP Pilot project at the Middagh Unit, which began ASP injection during August of 2010, has experienced an average oil cut increase from 1% to 5% in the project area. Oil production in the unit has climbed from 16 to 62 gross barrels per day. In one producing well, the company has experienced a steady increase from 1.5% to 15% oil cut over the past 45 to 60 days. Three other producers are starting to ramp up their oil cuts and production. This ramp up in production is consistent thus far with the company's extensive reservoir simulation modeling.

Based on what we're seeing in the field, we feel confident that an oil bank is forming in the reservoir. All signs point to the pilot behaving appropriately. We will continue to evaluate the results from the pilot to determine the overall effectiveness of the flood. This will allow for better definition [ph] of a reservoir simulation modeling for future ASP projects.

Based on these initial ASP results, Rex has increased the company's 2011 capital budget by $3 million to expand the ASP flood into the 58-acre Perkins-Smith project area. As you see from the map, the Perkins-Smith area is directly west of the Middagh Unit, and development will entail drilling 9 replacement wells and completing various injection well tie-ins to the ASP plan. Since we have substantial excess capacity at the plant and these replacement wells are shallow, over 1/2 of this capital will be for chemical injection, which is planned to start late in the fourth quarter of this year.

We want to reiterate that while we're very encouraged by the ASP pilot performance to date, it is still premature to estimate the eventual poor volume oil recovery of this pilot or translate this preliminary response into tertiary recovery crude reserves. We'll keep you posted in future updates as to how the pilot continues to perform.

Moving to the Rockies on Slide 17. Rex has completed the interpretation of its 3-D seismic survey in the East Silo area in Laramie County, Wyoming. The company believes the result showed well-defined areas, where interpretation indicates a high degree of natural fracturing associated with faulting and salt edge deposition that can enhance productivity. The company believes that these areas may be characterized as dual matrix porosity areas, which are capable of yielding higher EURs. Conversely, areas of minimal natural fracturing combined with closed or filled fractures that would potentially limit productivity are characterized as matrix porosity only contribution resilience.

As you can see from the 3D cross-section, the difference in amplitude and faulting between the Steege and the Herrington wells across the Niobrara section are displayed. We're currently drilling the Steege #11-33H to test this thesis.

On Slide 18, Rex Energy previously announced the well results from our Herrington, BJB and Silo State wells, where the company characterized the results as matrix porosity only type wells. Based on the results of the 3-D seismic interpretation, Rex has identified a number of locations in the East Silo area where a high degree of natural fracturing is anticipated and has permitted 2 wells. The company believes that these 2 locations have dual matrix porosity.

As mentioned, the initial well test to look at the fractured area, the Steege 11-31H, has been spud and is currently being drilled. Rex completed the drilling of a commitment well, the Shapley 14-45H in Weld County, Colorado to hold approximately 5,200 net acres. The well has reached total depth and is awaiting completion. The company also completed the interpretation of its 3-D seismic in the West Silo area in Laramie County, Wyoming. And as a result, has let certain leases containing 4,016 net acres expire. The company incurred a $5 million impairment associated with this expired acreage.

And with that, I'll turn the call back over to Dan for some closing remarks.

Daniel Churay

Thanks, Pat. As the second quarter progresses, we will continue to concentrate on our 7 main focus areas. Drilling and completing wells to fill the Sarsen plant in our operated Butler area, have flowing gas to the Salem Beagle Club tap at the Williams operated area, provide us a path to continued production growth in 2011. Beginning the ASP flood at the Perkins-Smith Unit and preparing an inventory of wells for the Bluestone Plant, together with the continued development of our Appalachian and DJ Basin acreage, can provide the path for production growth next year.

I want to thank our hard-working employees for their efforts this past quarter. Every day they have been focused on maintaining safety and a sound environment, filling the Sarsen plant and preparing for the Bluestone Plant, improving our drilling and completion practices while working to reduce drilling and operating cost, maintaining production in the Illinois basin, improving the ASP project to prepare our Niobrara acreage. In short, they are working hard to build an execution culture in our company and with the first quarter, we have a good start.

With that, let's open up the telephone lines for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Jeff Hayden with Rodman and Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

Couple quick questions. One, just want to make sure I'm looking at it right. In the Niobrara, the 39,000 net acres, does that include the 4,000 you let go?

Daniel Churay

No, that takes out the 4,000 that we let go.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay, that's what I meant. All right, I just want to clear that up. And then also based on kind of what you guys have seen on the 3D. Is there any other acreage that we could possibly see you all let go or do you kind of like the majority of what you've got left?

Patrick McKinney

This is Pat. I think it's still a little early for us to comment on that. I think we're going to learn a lot when we complete our Steege well. And I think after that point, we'll be able to give more color on what we think the quality of acreage is.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay. And then just couple quick questions on the cost side in the Marcellus and then I'll jump off. One, what are you guys kind of seeing as far as well costs right now in Butler? And how much is it adding to the cost to truck the wastewater over to Ohio?

Patrick McKinney

Jeff, this is Pat. I think as we mentioned, we're really pleased with the trend we're seeing of reducing our cycle times. And what we're working towards is trying to offset some of these additional costs right now. One of them is the closed loop drilling system on all the wells that Dan mentioned. We have been using the disposal wells in Ohio that we mentioned for some time anyway. So we're really not seeing a lot of incremental cost per se for that. But with our frac costs increasing over last year as many other companies have talked about, I feel very good where we're at today to start to take that number down and offset some of these other costs that we've seen to try to put some pressure on that $4.7 million number and start to take it down.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay. I'll jump back in the queue.

Operator

[Operator Instructions] Our next question comes from Mike Scialla with Stifel, Nicolaus.

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

On the Niobrara, is that Steege well really enough to test the concept here or do you need a couple wells? I mean basically, if it doesn't work would you be done in the Niobrara or do you need more wells to test that fracture intensity concept?

Patrick McKinney

Well, we mentioned we permitted 2 wells up there, Mike, and I don't think one well is going to totally define what we've got out there. But again, we really like the quality of the seismic data we've got and it seems to correlate on what we got at the Herrington. And the Steege well, I think, will tell us a lot. So I don't think we can sit here right now and say if that well is going to prove -- totally proved the thesis or not. But I think it's going to lead us in the right direction on that.

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

Okay. In your 3 existing wells up there, what are those producing now? I see you're showing 125 MBoe for your low case matrix porosity only. Do those fit that profile?

Patrick McKinney

Well, from where we IP-ed the Herrington, that was the profile off the IP. We've got the wells on -- or that well on ripe pump right now and so we've just got about 30 days or so of production. We're going to continue to monitor it to see if it stays on that trend. I think it's still too early to go and say if it's off that trend or if anything's changed yet.

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

What kind of rate is the Herrington producing, can you say?

Patrick McKinney

We haven't really discussed that, so we're going to pass on that one right now.

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

Okay. And switching over to the Marcellus on your non-op. Just trying to get a handle on where you think the -- what the type curves look like now. You said the Uschak wells are really well above your type curve for the area. Can you say what you expect out of those wells?

Patrick McKinney

Well, as you know last year, really for the last 2 years, we've kept both of our EURs and both the operated and non-op areas the same. And we had used an IP rate of roughly 3 million a day for the Westmoreland well. So the fact that we're above that here after 155 days puts us above that type curve. We like the trend we're seeing and I can just tell you we're above the type curve right now. We're not going to throw out what we think the new EUR is going to be yet.

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

Okay. If I remember right, that old type curve was 4.4 Bcf, is that correct?

Patrick McKinney

That was in Butler. We were right around I think 3, right at 3.0 gross Bcf for Westmoreland.

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

Right. Okay, sorry about that. And then looking at the Bluestone plant, have do you handicap the timing there? You said you hope to break ground in June. If you do get the permit and are able to start work in June, would that scenario lead to the plant being operational before the end of the year or -- I'm just trying to figure out how to handicap that.

Patrick McKinney

Well, Mike, I think well, we've got basically the same sister plant that's going to go in. And so this will be the second plant that we've constructed. And I think everybody feels comfortable that from the construction side, they're already looking at ways to cut time on the construction. As far as the procurement, they're coming up with a lot of different novel ideas to try to cut some time out. So we hope to do better than we did on the second plant. And I think our goal is once we get some line of sight of when we're going to get that permit then we can come back to market and talk about what we think that's going to be.

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

So the real unknown here is just the timing of the permit?

Daniel Churay

That's right and it should take 6 to 9 months to get the permit. We're well on our way in that time period, but it's going to take a little bit of time for us to get any sort of nod from the DEP.

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

Great. I'll hop back in the queue.

Operator

Our next question comes from Ron Mills with Johnson Rice.

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

You started to talk on the Marcellus a little bit more in your ramping activity there as you get prepared for that next plant. But also, can you just provide a little bit more color on just the efficiencies and the number of wells that are being added to your bed [ph] just from drilling efficiencies and the impact that's having on costs.

Patrick McKinney

Sure, Ron. Now that we've got the 2 rigs out there and we've got all of our momentum with our associated service providers and everything, we're getting on the wells quicker. We're able to go and get them to TD quicker, move the rigs quicker and then obviously get our water sourcing and everything lined up. So our cycle times are decreasing. We're seeing a great trend on the last 7 wells to do that. So as you could see in the first quarter, we drilled 10 wells and we drilled 10 wells all of last year. So I mean we're really starting to hit our stride out there and this is something we wanted to do was to try to get ahead of this. And I guess we are a little surprised at how good we're doing early in the quarter. And so, our plan, as Tom and Dan have mentioned, is to go through and continue with the 2-rig program and build an inventory of wells available to frac to be able to go once we get a line of sight of that Bluestone Plant to attempt to fill it up as soon as it comes online.

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

Okay. And the Westmoreland wells, you talked about exceeding the type curve. Your Butler type curve has moved up from where it was originally, but now standing at 4.4 Bs. How are the wells performing versus the Butler County type curve? Are you seeing outperformance there as well?

Patrick McKinney

Sure. I mean, we're coming off at the end of the year, we were still constrained by the Yellow Creek plant. So now we really got a quarter here where we've got some production history on some wells. And so, you're right. They are starting to come in on top of that curve. I want to see a little bit more production history before we can comment on what really that means. But just by the numbers that we released going from 31 to now 37 and then with the 30-day rate of the 3 wells that got the full fractured treatment. Out there at the Drushel, they're hanging in there at 36. I think it's safe to say that we feel pretty good about being above that curve. Where you recall, we were using IP rates at $2.5 million a day or 30-day rates of $2.5 million a day. So as each month goes on, we're going to get more and more confidence to take that number up.

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

And the reason I'm asking the question is I'm assuming then that your production guidance, especially as you work through the remainder of the year and you have the incremental compression in your plant, that your guidance volumes are really based off of the type curve, not necessarily how the wells are actually performing to this point.

Daniel Churay

That would be a correct statement. And obviously, to get to the higher end of the guidance, you need some of that increased performance from the wells that Patrick's talking about. But certainly at some point, we had modeled into our forecast that the plant was full. So there is -- the way we excel and get ahead of that is to get the plant full quicker to get to that high end of the range. So yes, I mean obviously your statement is correct.

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

Okay. I'm not sure if I missed this, but particularly in the second quarter, with all the flooding going on right now, what's the impact on your Illinois Basin just conventional oil production at this point?

Daniel Churay

Well, on a gross basis, what we're factoring in, Ron, to the second quarter number is 285 barrels a day. And we have about an 86% working interest in that area. So you're talking about to us it's about 245 barrels a day that's going to affect us. And we're modeling in 60 days, I mean obviously if the flooding subsides and the guys can get out there a little quicker, we'll get that back. And if it doesn't, obviously the opposite is true. So we're hopeful that Mother Nature will cooperate and we don't take that full hit.

Thomas Stabley

Yes, and the biggest issue out there is the electric grid and some downed power lines as a result of the flooding, and being able to get those lines back up to get the pumps working again. So that kind of gives you the nature of the issue. And as soon as the floods subside, they can get in there and do the electric work.

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

Okay. And I probably also missed your comments, but as you look at the drill in your Burkett well, recent commentary by at least one other operator, it seems like they're getting more and more encouraged by the performance of their initial Upper Devonian wells. Can you just provide a little bit more color about the Upper Devonian as it exists on your acreage position? Do you think it's present over most of your Butler County? And the same thing on the Utica as you look to test that kind of later this summer.

Patrick McKinney

Well, on Burkett first. We're fortunate we got to drill through it to get down to our Marcellus wells. So now on, whatever, 18 or 19 penetrations we've got a real good look at it. And I think our geologists feel really good about what they're seeing as far as the thickness and extent out there. So we have a pretty high degree of confidence it exists in our core area. On the Utica, you got to extrapolate a little bit more. We've got the range well about 8 miles west of us that we got to look at and we've got a few other logs. But again, we feel that it's going to exist under our acreage and our test well, the [indiscernible] well is going to be a chance to go and prove that.

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

Okay, let me let someone else jump in.

Operator

Our next question is a follow-up from Jeff Hayden with Rodman & Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

Just wondered if you could give us a little color on how we should look for exploration expense to kind of progress through the year?

Thomas Stabley

Jeff, it's Tom. I think with the majority of the 3D were completed in the Rockies, on the East Silo portion. The only remaining -- there's 2 additional sections and if we work on those it will be later in the year. And then as far as Clearfield and Westmoreland goes, those are is evolving shot [ph] now. So we'll be finished with the 3-D seismic in those areas. And I think for the most part, the geologists are comfortable with the microseismic they've seen thus far in Butler County and don't plan any additional microseismic in those areas. So I think for modeling purposes, you going to still have some delay rentals and some smaller amounts in there, but you're probably around $1 million a quarter going forward.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay. And then kind of looking at Williams, with them kind of backing off to just 1 rig, I assume that's mostly due to just their infrastructure issues as far as deliverability goes. Any sense of looking at it a little longer term? May be kind of what they're expecting to be running in terms of activity in 2012 and beyond?

Daniel Churay

Well, I think the plan was this year to drill 20 gross and 8 net in the Williams areas for Rex, and that's what Williams has discussed. They're on target to do that so obviously, the releasing of those 2 rigs doesn't impact the results that we discussed and what they said they were going to do. It's probably a little early to discuss 2012, but what we've preliminary said to them or what they've said to us is that they would probably go back to a 2 rig program next year.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay. I appreciate it, guys.

Operator

Our next question is a follow-up from Ron Mills with Johnson Rice.

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

And just a question on the ASP. Obviously, based on your going forward with the second unit area, you're very encouraged with the results. Can you just provide a little bit more substance around what you're seeing that makes you excited and how that compares with the reservoir modeling that [indiscernible] had performed, which suggested 35 or 40 million barrels of opportunity there?

Patrick McKinney

Sure, Ron. This is Pat. The ramp that we saw in the first well that was really the closest well to the injection out there that's why it's poor volume pattern received a response first. With the shape of that curve going from 1.5% to 15% oil cut, really, really tracked the modeling that we have done. And 3 other wells that were spaced a little bit, slightly differently so you needed a little bit more injection to get to those wells. How they're responding in the shape of its response really gives us a lot of comfort that we're seeing everything we should be seeing in this reservoir. And additionally, we've got an observation well that we monitor which kind of lets us look behind the curtain a little bit to see what's going on kind of behind the flood front. Again were very pleased with what we're seeing there, which would indicate that we're really in the early stages of this response, and more good things are to come. So really, it goes back to a lot of the mechanics that were in the reservoir simulation modeling. That it looks like we're hitting a lot of these milestones that were forecast out there.

Daniel Churay

And we also haven't seen a breakthrough of any of the ASP chemicals at this point, which is good, because that means that it's still flooding.

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

Great. I appreciate the color. I'll jump back off.

Operator

Our next mission is a follow-up from Mike Scialla with Stifel, Nicolaus.

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

Yes, the follow-up on that, I guess you're at 62 barrels a day now. Where do you expect that to plateau, can you say? And when do you think you might reach that plateau?

Patrick McKinney

Sure, Mike. Well, as any reservoir simulation modeling goes, it's kind of like when you're watching the weather channel and they're trying to predict the path of a hurricane coming into the Gulf Coast that can go a lot of different ways. And what we're really encouraged with is the magnitude of the increase and the shape of the curve of how it's starting. What we don't know yet is how high it will go and then when it will plateau and how long it will plateau. The end of the day, it's about recovering oil out of this poor volume. And it can take a number of different shapes. So we have a couple of different forecasts, if you will, to see what this thing is going to do. And so once we see it start to turnover and plateau, that's one piece. The other piece is how long it plateaus and then you can calculate the amount of oil under that curve. So really, there's a couple things going on there. We've been asked, well, are you looking for a 30% oil cut, are you looking for a couple of 100 barrels a day. And I'll just answer, "It's going to depend." A successful flood out here doesn't necessarily mean a huge initial oil increase. It's really for what that initial increase is, how it plateaus and again it's all about poor volume recovery at the end of the day.

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

At this point though, you're still seeing it continue to hedge up, is that correct?

Patrick McKinney

That's correct.

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

Okay. And then one more on the Niobrara. You talked about, the main thing here is using the seismic on the Steege well. Do you plan to complete this well any differently than you did the other 3?

Patrick McKinney

Well, that's a good question, Mike, because I think the industry as a whole has made a lot of progress just in the last couple months in really looking at how we complete these wells. And what additives we put in it, how much sand we use, et cetera. So I don't think we're not ready to discuss the changes yet, but I think we are looking at this completion a little bit differently than we have the others.

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

Have you seen this well drilled differently or is it too early to say?

Patrick McKinney

It's too early. We haven't made the curve yet on it.

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

Okay, that's all for me.

Operator

[Operator Instructions]  I'm showing no further questions in the queue and I'd like to turn it over to our speakers for any closing remarks.

Daniel Churay

Again, thank you for everybody participating today and we look forward to talking to you next time. Goodbye.

Operator

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

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