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Forest Oil (NYSE:FST)

Q3 2011 Earnings Call

November 01, 2011 2:00 pm ET

Executives

H. Craig Clark - Chief Executive Officer, President, Director and Member of Executive Committee

Michael N. Kennedy - Chief Financial Officer and Executive Vice President

John C. Ridens - Chief Operating Officer and Executive Vice President

Patrick J. Redmond - Vice President of Corporate Planning and Investor Relations

Analysts

Pearce W. Hammond - Simmons & Company International, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Brian Hunsaker

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Unknown Analyst -

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Operator

Hello, my name is Philip, and I will be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Third Quarter 2011 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. Patrick Redmond. Sir, you may begin.

Patrick J. Redmond

Thank you. Good afternoon. I want to thank you for participating in our third quarter 2011 earnings conference call. I will note that a replay of this conference call will be available through November 15 as described in our press release issued yesterday. We have joining us on the call today, Craig Clark, President and CEO; Michael Kennedy, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and COO.

Some of the presenters today will reference certain non-GAAP financial measures regularly used by Forest in measuring its operating and financial performance. Reconciliations of such non-GAAP financial measures with the most comparable financial measure calculated in accordance with GAAP are available on our website and can be viewed by clicking the Investor Relations tab, then non-GAAP at www.forestoil.com. In addition, I'd like to caution you about our forward-looking statements. All statements other than statements of historical facts, that address activities and outcomes that Forest expects, assumes, plans, believes, budgets, forecasts, projects, estimates, anticipates, et cetera about what will, should or may occur in the future are forward-looking statements. Please carefully review our cautionary language regarding forward-looking statements that is contained at the end of our press release.

I'll now turn the call over to Michael Kennedy. Thank you.

Michael N. Kennedy

Thanks, Pat, and thanks, everyone, joining us today. The third quarter of 2011 was highlighted by the completion of our spinoff of Lone Pine resources to our shareholders. On September 30, 2011, Forest distributed its ownership of 82% of Lone Pine's shares to its shareholders, which resulted in Forest shareholders receiving 0.612 of a share of Lone Pine for every Forest share held. This transaction provided another meaningful dividend to our shareholders in a tax-efficient manner, and still allows them to have exposure to Lone Pine's high-quality asset base in Canada.

We have accounted for ownership in Lone Pine during the third quarter as discontinued operations in our financial statements. We've also provided our results excluding Lone Pine from Q3 in comparable periods. In my remarks today, I will first briefly cover our earnings, including Lone Pine, and then my remaining comments will pertain to Forest excluding Lone Pine. We have noted that our analysts have modeled our results using different methods. Hopefully, we are presenting them in a fashion that is useful to everyone.

Including our ownership and interest in Lone Pine, our adjusted net earnings were $37 million or $0.32 per diluted share. Adjusted EBITDA was $173 million and adjusted discretionary cash flow was $134 million. These figures are net to our 82% ownership during the quarter. The remainder of my remarks will now relate to Forest, excluding Lone Pine.

Forest produced 323 million per day, including 14,400 barrels per day of liquids during the quarter. This is below our expectations due to third-party infrastructure issues in the Texas Panhandle that resulted in production downtime of 10 million a day in the quarter. Adjusted earnings came in at $29 million or $0.25 per share, with adjusted EBIT of $142 million and adjusted cash flow of $106 million.

Differentials for natural gas were $0.33 per Mcfe, and oil was a positive differential of $2.11 per barrel. NGL pricing was approximately 50% of NYMEX. Differentials continue to be better than expected. Production expense for the quarter was also better than expected at $1.16 per Mcfe, which was an 11% sequential decrease. The SG&A remained in line at $11 million or $0.37 per Mcfe. DD&A increased as expected to $1.83 per Mcfe as our capital program is focused on liquids projects, and those projects have higher F&D costs than our current the DD&A rates. Our E&D capital expenditures were in line with guidance at $182 million. We also invested $76 million in leasehold acquisitions as we continue to bolster our liquids acreage in the Panhandle, Eagle Ford Shale and Permian basin. The latest round of leasehold acquisitions have provided us with a significant opportunity set that we'll be evaluating for the remainder of 2011 and into 2012 through the drill bit. We do not anticipate material, undeveloped leasehold acquisitions going forward into 2012.

Our net debt as predicted increased to $1.6 billion. We recently had our borrowing base reaffirmed at $1.25 billion, no amounts drawn and have $270 million of cash, which results in approximately $1.5 billion of liquidity.

We are well hedged for the remainder of 2011 and 2012 with $150 million a day hedged at $5.48 for 2011 and $105 million per day hedged at $5.30 for 2012. Also, we provided an update for our guidance for production and differentials. We are guiding production at $335 million per day to $345 million per day for Q4, assuming no improvement in the third-party infrastructure issues, which represents a 5% sequential organic growth rate sponsored by the recent wells that will be highlighted later in the call. We also narrowed our differentials to account for the strong product pricing we have recently realized.

So to summarize, Q3 2011 was a transitional quarter as we completed the spinoff of Lone Pine and got our first results from testing some new oil concepts. As we discussed at midyear, we saw value from our portfolio of assets through focusing on our oil- and liquids-bearing plays. However, to realize this value, we indicated a significant amount of science capital would need to be deployed. This science capital is expected to be focused in 2011 and is not expected to be replicated in 2012, which will result in total capital expenditures more in line with cash flow in 2012.

Initial results from this capital have been successful in each of the areas, so we're off to a good start and intend to provide further clarity by issuing 2012 guidance before year end.

With that, I will now turn the call over to J.C. for his review of the third quarter operational results.

John C. Ridens

Thanks, Michael. In the Texas Panhandle, we continue to have success in both development of previous delineated intervals, as well as new intervals. Notably, in this quarter, we drilled wells that were productive in 7 different pay zones. This is the highest number of pays we have tested in any quarter, which speaks to the quality of our acreage holdings from a multiple pay perspective. We drilled a total of 9 horizontal wells, 7 of which were horizontal wells in the Granite Wash. The average IP from the Granite Wash horizontal well were 15 million cubic feet equivalent per day, with 45% of the equivalent production coming from liquids. This continues to exceed our type curve on a blended basis between Wheeler and Hemphill Counties.

Today, I will speak as to which zones we completed wells in to give greater clarity to our Panhandle drilling program. There's been sufficient industry activity now that we feel we can discuss zone results without yielding any competitive advantages. Previously, we called the zone by numbers, so here's our numbering convention that was used in the past.

Zone #1 is the Britt. Zone #2 is the Des Moines, which overlies the Britt and is the top of the Granite Wash sequence. We also previously tested the Atoka and Morrow horizontally and named to those intervals. In today's comment, I will address the Missourian Wash, where Hogshooter, the Cleveland, Granite Wash A and the Granite Wash "C", thus bringing our total number of operated horizontal zones to 9. Beyond this, we participated in tests of the Tonkawa and St. Louis Lime with other operators. Our total testing at the Panhandle horizontally was up to 11 zones with more named zones to be tested horizontally.

As we stated earlier, we plan to start testing new zones horizontally specifically focused on oil, once we begin the discussion of well results by talking about the oil zones. We completed our first test of the Missourian Wash or Hogshooter formation, which is above the Granite Wash. A horizontal well with a cost of between $7 million and $7.5 million achieved an IP of over 3,900 barrels of oil equivalent per day. Over 70% of this equivalent rate was oil, oil not condensate. Since this well is not considered part of the Granite Wash sequence, this rate was not included in the average IP that I quoted earlier. During its first month of production, this well has produced over 83,000 barrel oil equivalents and continues to produce at a current rate of approximately 2,800 barrel of oil equivalents.

This is a fantastic result and we will continue to run a rig, further testing this formation for the remainder of the year and beyond. Based upon continued success in this program, we see about 30 potential locations for the Hogshooter than what we have initially identified.

We also successfully tested oil in the Cleveland formation from both an operated and non-operated well completed during the quarter. The operated well came in at 654 barrels of oil per day. We have an additional operated well that's cased, waiting on completion and are drilling our third well currently. Based upon the continued success in this program, we'll see about 90 potential locations for the Cleveland. In the Granite Wash program, we had success in the Britt, Granite Wash A and Granite Wash "C" intervals. We drilled a total of 5 Granite Wash A wells that had an average IP of 13 million cubic feet equivalents per day, of which 48% was liquids.

These wells were drilled in both Wheeler and Hemphill County, showing once again the productive extent of the Granite Wash A formation. We also had a very successful test of Granite Wash "C" of IP of over 30 million cubic feet equivalents per day, 40% of which was liquids. This well has been on production approximately 2 months, has already produced over 1.5 billion cubic feet equivalent and continues to produce at a rate of approximately 25 million cubic feet equivalents per day.

We've been utilizing pads constructed previously for Britt wells to drill both the Granite Wash A and C formations. So far we have drilled 4 pad locations. This not only reduces the expense of constructing a new location, but more importantly, demonstrates that the previously completed Britt interval has not communicated with the A or C zone. We are conducting pad drilling for either the A or C intervals, we've also been able to maintain the production from the Britt wells by conducting simultaneous operations. The Britt well has shut in only what the drilling rig is rigging up and rigging down, and while the A or C zone is being fracture stimulated for safety reasons. Other than those times, production from the Britt is maintained. We have started recycling frac water using the same frac bed to frac 2 wells, of which we flow the recovered water back into the pit after frac-ing the first well and then use it on the subsequent well.

Moving on to the Eagle Ford, we continue to seek the optimal completion by altering the zone in which the lateral is landed, as well as decreasing our frac sizes. Savings from reducing the frac sizes are approximately $40,000 per stage so it's a meaningful savings. As a matter of fact, our last 2 wells have been under $6 million through completion.

However, it isn't just about cost savings, it's also about increasing the efficiency of the stimulations and achieving better well results. The first cluster of well drilled to hold acreage that did not have extensions were all landed in the lower portion of the Eagle Ford. While achieving good initial production rates, the performance was then variable. We began to raise the lateral into the middle and finally the upper portion of the Eagle Ford, while also moving into different portions of our Eagle Ford acreage. We monitored the newer wells with microseismic to determine the effect of the stimulation. We are encouraged by the results that came from this and we'll continue this program through the 4 wells remaining to be frac-ed this year.

Our latest well, using the higher landing zone and the smaller frac, achieved an IP of approximately 950 barrels of oil equivalent per day and has produced at an average rate of over 550 barrels of oil per day during the first 21 days of production while flowing up casing. Our type curve is based on a 24-hour IP of approximately 600 barrels of oil per day. You should note that this well is drilled in the shallowest, most updip portion of our acreage. So we feel this is an important data point. The first well that we completed in the middle section of the Eagle Ford earlier this summer has produced over 50,000 barrels of oil. It continues to produce at a rate of approximately 400 barrels of oil per day. We will continue to refine our techniques of landing the laterals higher and increasing the numbers of stages, while optimizing the size of the frac using microseismic to calibrate the results on our remaining completions this year.

Our first horizontal Wolfcamp well, drilled with a lateral length of 5,000 feet is currently being frac-ed with 15 stages planned, and it is also being monitored with microseismic during the completion. Utilizing the microseismic, the frac techniques had been altered on the fly by changing the perforation clusters and frac rates. We have drilled the second of our vertical monitoring wells in a different portion of the Wolfcamp and we'll begin a horizontal outfit in the next couple of weeks. After drilling that horizontal, we will then move back and drill yet another horizontal offsetting our first monitor well as we continue to refine the stimulations of the Wolfcamp, which is over 700 feet thick. After the horizontals are completed, the vertical wells will be utilized to test other prospective pay zones that lie outside of the Wolfcamp sequence.

We resumed the Haynesville Shale drilling program based on the success of the restricted rate program, combined with decreasing completion costs. Our first well in 2011 was completed for a restricted rate of 12 million cubic feet per day, with over 8,600 psi of flowing casing pressure. We increased the number of frac stages on this well to 16. A comparable well that we drilled last year has produced 2.8 Bcf and continues to produce approximately 8 million cubic feet per day over the first 240 days of production. This indicates the EURs from the restricted rate well should be in the order of 8 Bcf, or an increase of approximately 25% over our earlier EURs. These results yield economic wells with the rate of return greater than 20% even in today's gas price environment.

Further cost reductions will be obtained through pad drilling in 2012, as we have purchased a rig walking system to use with our lantern rigs for this area. As a final note, our success rate for our overall drilling program this year is 98%.

I'll now turn the call over to Craig.

H. Craig Clark

Thanks, J.C. for the good summary. The third quarter essentially completes our transition to a U.S. onshore-focused company following the spinoff of our remaining shares of Lone Pine Resources, yet another big dividend payday to the Forest shareholders following on the Mariner offshore transaction in 2006. I'll personally thank the employees of both Forest and Lone Pine for their tireless efforts on this transaction over the past year. The employees at both companies hold shares in both Forest and Lone Pine, including yours truly.

And now we turn our focus to a slimmed-down Forest that we believe is fat with opportunities. We can see some of these opportunities begin to materialize from the early results of our technical work in several areas, new zones in the Texas Panhandle, Eagle Ford and now the Wolfcamp.

The Panhandle, in particular, the new Granite Wash and oil zones there, always seemed to surprise us to the upside as we've added new horizontal objectives to our inventory. The Texas Panhandle is certainly our top highlight for the third quarter with 3 new zones in the Panhandle that by far exceeded our expectations. They're using our type curve, though. The 2,800-barrel a day oil well is the best well that we can find in our long history. It's the best we can track. For those people keeping track, with these successful tests that brings a number of zones drilled horizontally or participated by Forest to 9, with more tests this year alone, and as many as 5 identified zones remaining. This led to our large inventory of horizontal and vertical locations as time goes on, kind of like piling on my favorite football team.

Our other 2 oil plays, the Eagle Ford and Wolfcamp, were progressed forward in the quarter as J.C. detailed. I'm especially pleased with the drilling and completion efficiencies gained to date specifically in the Eagle Ford, especially being one of the first operators to gain these efficiencies in horizontal laterals using a smaller 1,000 horsepower drilling rig. We are just now halfway through our microseismic program and it's already yielded benefits by allowing us to get better results from smaller stages, in particular in the updip area of our acreage. There seems to be some past confusion with investors or others of our drilling activity in the Eagle Ford. I'm not sure why this has been since we've been very clear since July of our intentions to drill multiple producers in the upper, middle and lower Eagle Ford and drill a microseismic monitor well next to each producer, and use the microseismic results for future drilling and fracture stimulation. The monitor wells are permitted as water wells folks, they're going to be used as water supply wells, but they do still need a drilling rig to drill them. In the Wolfcamp, we have conventionally cored 2 wells of approximately 1,000 foot from each. We've drilled another monitor well at each and are presently completing our first producer. Operations have gone smoothly so far.

We also saw offset acreage prices skyrocket in the university lease sale this quarter to around 5,000 per acre, a new record in that area at least. We also had some good offset well results posted by other operators. Throughout the Permian, our Wolfcamp acreage is now up to 58,000 gross, 51,000 net acres, that's just in that area. As Mike detailed, our E&D spending was in line with guidance and includes the science work, as they called it, on the shales. This despite little relief from service costs in the quarter. The exception is East Texas, where we're seeing some signs of pricing relief through the industry Haynesville rig count coming down as we predicted. It was our plan to move back into East Texas when service cost relief was achieved to drill horizontal wells in either liquids-rich Cotton Valley zones or the Haynesville. We do plan to attempt to co-mingling of a horizontal Haynesville along the shallow Cotton Valley to enhance the well economics, but that's in next year's budget.

In terms of land year-to-date, we acquired year-to-date through the third quarter of 2011, we spent $182 million to have 174,000 net acres for an average acreage cost of approximately $1,000 per net acre. This was mostly in the Permian basin. However, year-to-date we added about 7,500 net acres in the Panhandle, about 20,000 net acres in the Eagle Ford to fill in our Eagle Ford units.

As Mike mentioned, this is obviously a big acreage inventory that we won't replicate, but it gives us a great start in the slimmed-down Remainco after the Long Pine spin out. Our third quarter capital spending included some money for laying pipelines through our midstream subsidiary Forest Texas Gathering in the Texas Panhandle since we saw minimal relief from the high-line pressures and outages that has plagued us and others in 2011. I guess if you want it done, go do it yourself. We also will be bringing in new purchases into the area into 2012 to provide competition. This was also pretty much the lost production in the third quarter.

These issues are affecting our areas to the south more than in the north and central, which is one of the reasons we moved to the central and northern areas, but also due to the oily zones. Our cost control continues to be a highlight. Post the Canada spinoff, we were slightly lower on per unit operating costs, again, despite external cost pressures from service companies. Lastly, as Mike mentioned, our margins are up on the condensate and crudes prices. There's a reason for that. Most of our Gulf Coast crude and condensate now sells at a premium to WTI, and in some cases to a Louisiana Light posting. As a note, that Louisiana Light posting is trading at even a premium to Brent, so we've enjoyed that along the Gulf Coast.

In terms of our current industry trends, the service providers, I'm speaking for them, have yet to see a material change in operator behavior, specifically, in terms of spending levels. We, therefore, don't forecast much service price relief going into 2012, the exception being notably East Texas. We may see some gas-prone basin get price relief in 2012, even with the liquids component like our Panhandle area. I say this for 2 reasons: the oil rig count has certainly exceeded the gas rig count for the first time in a long while; and secondly, as we've shown in our roadshow slides, there's less horsepower required for tight sands versus the shales. Our contrarian behavior is not to drill dry gas wells but to take advantage of regional service cost trends, look for tight sand opportunities, specifically tight oil and try and use the rigs, smaller than 1,500 horsepower. This competition and frac -- completion and frac cost will be the sole cost focus in our mind for the industry going forward, particularly in the shales due to the large horsepower requirements and the size of the fracs themselves versus tight oil or gas. We switch to different proppants and frac design as well, as J.C. mentioned, it was not the price book that gave us those savings. All things are on the table in our battle against high horizontal well cost.

The other issue in terms of trends I would like to address is infrastructure. As we see in the Panhandle, even with huge takeaway capacity on interstate pipes, the bottleneck getting there has happened industry-wide and will be the issue in the high-activity areas not just here but the Eagle Ford and Marcellus, particularly where there are natural gas liquids involved. We've been contracting our trucks for oil hauling and water for some time directly, we've been doing that for a while. We've been able to dodge these issues in our operating areas with the exception of the Panhandle where we're now laying pipe or bringing in more third-party pipeline companies.

So in summary, we moved the 3 plays forward that J.C. described as we promised post-Lone Pine in the summer guidance. New Panhandle zones, Eagle Ford and Wolfcamp highlight those. In the case of the Panhandle, we are certainly way ahead of schedule and we are also making strides in the Eagle Ford as well. So we had hoped this would set us up going into 2012, and we believe it has. We plan to issue 2012 guidance a little earlier than we usually do but later this year, after the final well results from the 2 shales and board approvals are received. Again, as Mike said, spending more in line with cash flow.

Thanks for listening in our call today. Operator, we are now ready for questions.

Question-and-Answer Session

Operator

[Operator Instructions] First question or comment comes from Jessica Chipman with Tudor, Pickering, Holt.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

My first question, I realize that Haynesville has over a 20% rate of return, even at these gas prices. But just wondering, what's the rationalization of adding a rig there today? Why not add another rig in even the Eagle Ford?

John C. Ridens

Part of that decision, Jessica, was based on the fact that we were seeing higher EURs progressively as we move this program forward with lower well costs. Secondly, it's a portfolio decision to avoid concentrating activity in any one area to avoid any weather or infrastructure pitfalls. Thirdly, we do have a correlative rights situation that we need to protect from ongoing activity from other operators. That, in summary, is why we're currently back in the Haynesville.

H. Craig Clark

And the Eagle Ford is still waiting on the science, and we should note since we own our rigs, we had left a rig there in the first place.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Then just, I guess, moving to the Eagle Ford. I think you have about 140 wells that you need to drill in order to HBP acreage there. I mean, what does translate to in number of rigs related to next year and to 2013?

John C. Ridens

It's about a 5-rig program through 2012 and '13. In order to accommodate that, our drilling times have decreased sharply since we entered the play. Thus, we can drill more wells than we originally forecast.

H. Craig Clark

That's not 5 rigs through 2012 and '13. That's ramping up to 5 rigs.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. I guess, just kind of an obvious question then. If you're running 5 rigs in Eagle Ford, you're ramping up in Haynesville, assuming you have some success in some of these oil zones and the Granite Wash, how close do you think you can get to cash flow really in 2012? Or is that less of a priority than keeping some of this acreage and testing these new zones?

John C. Ridens

Well, clearly, you've made a good point about the Eagle Ford. That is still something that we would be interested in seeking a joint venture on at the right price. Because as we look at the capital commitments that we have there and in some of these other zones, that clearly is one place that we would still consider a joint venture, particularly given the results that we're seeing and proving up our shallow updip acreage, which gives us an excellent data point, as well as spreading the results across that entire acreage base now that we have protected the 2011 acreage expiry that we addressed earlier.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then just last one for me. I think you've outlined 30 locations in the Hogshooter, 90 for Cleveland. Are those a risk number? Or is this -- over the next 12 months you'll de-risk that inventory?

John C. Ridens

So I think that we've already de-risked it to a certain extent because the results that we've seen have been -- aren't what we have originally projected. But clearly, with the work that we've got under way down in Cleveland, particularly with another well down ready to be completed, the third well currently drilling, we think we're going to see some pretty rapid results on that. The Hogshooter, I feel very confident about our ability to deliver on that given the mapping that we've done, the modeling that we've done on other producing vertical wells in that area. So that we've got a pretty good handle on how that Hogshooter is really going to perform.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Sorry, I apologize and I said that was the last question. But do you think about maybe 5 to 10 wells over the next 12 months in each of those zones? Is that the right way to think of that?

John C. Ridens

The Cleveland, we would probably expect more than that because given how quickly those wells drill, we can have that program accelerated. Because in the quarter since we started the Cleveland program, we've already got 2 down with the third drilling. I think that we will probably look to run a rig in the Hogshooter for the remainder of this year and next, and so I would expect that we would probably see somewhere between 7 to 10 wells in the Hogshooter.

Operator

The next question or comment comes from Gil Yang with BoA Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

How much science capital is being spent today that would not reappear next year?

Michael N. Kennedy

Gil, I have to get you the exact numbers but the science capital we're speaking to you is the Eagle Ford Shale capital and the Wolfcamp Shale capital. I don't have the exact numbers for the second half, but those are the 2 programs that we classify as science.

John C. Ridens

It would be the monitor wells that we use for water supply or otherwise, the macroseismic and then 3D seismic itself, in the case of the Wolfcamp.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And would there be some science spending in the early part of next year? Or does it really sort of cut out at the end of this year?

Michael N. Kennedy

It will be a little but not nearly the amount this year. I think -- -- and I'm just recalling the slides, I think we've spent or spending approximately $120 million in the Eagle Ford in the second half and $50 million in the Wolfcamp. That's $170 million for the second half, there would be some but not near that amount.

John C. Ridens

Gil, I would speculate that it would be in the Wolfcamp, probably exclusively since we can hold 225,000 acre tracts with essentially 2 wells. There's no lease-holding issues going on in there as opposed to the Eagle Ford tracts and units that would relate to the question the previous caller asked.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Mike, I'm sorry, how much did you say is the Wolfcamp science?

Michael N. Kennedy

The Wolfcamp will be $50 million, but that was for 6 wells. And I don't think we're going to be able to get that much done this year. Some of that will roll over into 2012.

John C. Ridens

That's not lease-holding. That's -- it's already basically done at that point.

Gil Yang - BofA Merrill Lynch, Research Division

Right, right. Okay. I'm sorry if you mentioned this, but what did you say is the well cost in the Haynesville?

Michael N. Kennedy

We didn't say what the well cost was, just that the costs are coming down, Gil. But I think that as we look at it, we're looking at about a $10 million well cost compared to previous editions of those wells that were in excess of $11 million or $11.5 million.

Gil Yang - BofA Merrill Lynch, Research Division

Okay.

John C. Ridens

We left it when we shut down years -- a year and a half ago, we left it at about $8 million, and that's our target. It's heavily driven by the EURs and the new completion efficiency.

Gil Yang - BofA Merrill Lynch, Research Division

All right. Okay. Then, for one 900-some barrel per day well that IP'ed in the Eagle Ford. How -- I know you said, J.C., that it was updip and shallow areas, can you talk about -- if you look at your acreage in Gonzales, in sort of the northwest, southeast sort of a direction. How far up along that horizon, is it sort of closer to the northwest edge, or is it closer to the southeast edge of your property?

John C. Ridens

It's very close to the northwest edge. You can't go much further updip than this and still be on the yellow acreage, Gil.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And do you think that -- if you look at that shallow zone, is it as contiguous as you would expect a normal resource play to be in that area?

John C. Ridens

Yes, absolutely.

Gil Yang - BofA Merrill Lynch, Research Division

Is there any kind of -- are there any kind of geological features that you need to look for in drilling that well? Or is it fairly smooth between each edge?

John C. Ridens

It's smooth. We did not drill this on any sort of geologic features such as looking for something adjacent to any faulting or any structural component. But geology is pretty benign across the Eagle Ford with distance, thickness and consistent structural positions across the entire acreage. This was drilled purely to get into a very updip position and determine the productivity in a shallow updip interval of our acreage.

H. Craig Clark

And we're dealing with a pretty uniform thickness, that's why we've been able to drill the upper, the middle and the lower and keep those separate in our testing operations.

Operator

Your next question or comment comes from Pearce Hammond with Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

I was curious, how much capital would you need to spend next year, kind of maintenance capital to keep your production roughly flat?

Michael N. Kennedy

We don't have that calculation handy, Pearce, right now. We'll have to determine it when we look at our budget and our capital efficiency from that program.

Pearce W. Hammond - Simmons & Company International, Research Division

Is there any way you can help us think about growth for next year, if you're going to keep the CapEx roughly around cash flow?

Michael N. Kennedy

We'll be providing guidance before year end, is our intent. And when we do provide that, you'll be able to get a growth forecast from it.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. And then touching on the potential of the joint venture in the Eagle Ford, how is the level of interest right now? Is it about the same that you're experiencing before? Or has it actually stepped up?

H. Craig Clark

I would say it stepped up a little bit compared to where we were earlier. We've got some new parties that have been approaching us and inquiring about this. So I think that as we continue to delineate the acreage and provide updated results, we are starting to see a little bit more interest than we've seen previously, Pearce.

John C. Ridens

That may have something to do with results of the wells, which obviously we're encouraged about. But also the fact that 2 of the larger un-JV blocks just got bought last quarter in El Paso and Petrohawk.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then in the Hogshooter, what sort of well cost are you looking at there?

Michael N. Kennedy

So that initial well was between $7 million and $7.5 million. The reason I'm quoting the range is because we still have some facility costs that will be expended later -- at some point that well needs artificial lift.

Pearce W. Hammond - Simmons & Company International, Research Division

And then, do you have an internal EUR that you feel comfortable sharing with us or a target?

Michael N. Kennedy

No, not at this time, Pearce.

H. Craig Clark

But it blew away the type curve by a country mile.

Pearce W. Hammond - Simmons & Company International, Research Division

And then lastly, on the Cleveland, what about the well cost there?

Michael N. Kennedy

Those wells were in a ballpark of $4 million, Pearce.

Operator

Your next question or comment comes from Scott Hanold with RBC Capital.

Scott Hanold - RBC Capital Markets, LLC, Research Division

On the Eagle Ford wells that you're testing the upper zone, can you talk a little bit about the reservoir or how it differs from the lower part to the middle part or to the upper part? Are you seeing any like clay content differences or anything that makes the upper more or less attractive than some of the lower members?

John C. Ridens

Now the clay content in the upper is not significantly different from the middle. Obviously, as you get into the very lower portion of the Eagle Ford, that's where the highest clay content is observed. And we've never drilled into the lowest member, simply for that reason. It's fairly consistent. It's very easy for us to mark these landing zones. So we have not required pilot wells to do that. We've been able to do it off of the previously-drilled wells. We've been able to delineate those zones that way, and pick our landing zones. So it's pretty consistent. Now what we're doing is looking for and we still see a fairly consistent TOC through that entire interval. We're just looking for how can we get into an Eagle Ford completion that's still effective in the Eagle Ford but also gives us access to the Austin Chalk.

H. Craig Clark

We give, of course, Scott, the entire interval on our previous efforts out there with conventional core.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So correct me if I'm wrong here in what I'm hearing, the upper member may be a little bit more attractive because you're also sourcing from your Austin Chalk, as well as -- so your drawing from both reservoirs given what you think could be better performance, is that correct?

John C. Ridens

Yes, that is correct. That was one of the things that we figured we were going to be doing when we first started this program. And the microseismic is confirming that, that we can see treatment in both intervals.

Scott Hanold - RBC Capital Markets, LLC, Research Division

But did you see -- now that, that well came on at over 900 barrels a day in over the first, I think, 21 days, instead of about 500 barrels. It seems like it's declined a fair amount. Is that typical what you saw with some of the other parts of the Eagle Ford? Or is that -- how did that decline compare to sort of your type curve?

John C. Ridens

That decline compared to our type curve would be spot on the type curve or slightly above it. What we have seen previously with some of our other wells is we got the IPs that we wanted, but we were seeing variable production in later periods with a lot of them. Some of them were above the type curve, some of them were below. Obviously, what we're trying to do is get everything to or above the type curve.

H. Craig Clark

And, Scott, we saw some performance that a third party reported about the performance, flowing up casing in pure oil wells with or without the water, we're going to need a pump. And I think we detail the types of pump on the last call and the fact that it's surrounding here in frac per stage. I think at the time that report was written, only half the wells were un-pumped. These wells currently that J.C. are discussing from the science project, if I can call it that, are all flowing up casing as we speak. No tubing or pump on them yet. And then when they hold up or have tendencies, we put them on pump and have in some cases seen a higher rate on pump than we had on the initial IP production test with the state and that's because they both flow and pump at the same time.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Understood. And maybe one quick one for Mike. The positive oil differentials that you all saw during the past quarter, what are you seeing right now? Do you think that's going to persist a little bit here into the next quarter or so?

Michael N. Kennedy

Yes, we do. We actually decreased our differential. I believe the previous guidance was $6 to $8 per barrel, and now we're basically $0 to $2 per barrel differential. So we do see that continuing, heavily sponsored by the LLS and the South Louisiana.

H. Craig Clark

And our marketing contracts as some of us have, have reflected that posting reference if applicable. Although I don't think we have any that's specifically go up Brent. It's either WTI plus or P plus or quite frankly, the most lucrative posting is Louisiana Light even if it's not Louisiana.

Operator

Your next question or comment comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Just following up on a couple of the earlier questions on the Hogshooter and the Cleveland. I mean, you talked about the 30 locations in Hogshooter and 90 in Cleveland. Over what acreage, spacing and number of zones are assumed? Just trying to think about what you would need to see, what your base assumptions are and what you would need to see for those numbers of locations to potentially increase from here?

John C. Ridens

The Hogshooter and Cleveland both anticipate about 3 horizontal wells per section.

H. Craig Clark

And, Brian, to spread out -- because you've seen to the north where we are quite a bit of Cleveland and Tonkawa, our acreage is spread on both sides of the Oklahoma-Texas border. The issue with that location is spread out and identified by our only -- our penetrations horizontally or vertically even though we have a considerable greater amount of acreage -- called spreading out.

Brian Singer - Goldman Sachs Group Inc., Research Division

And do you have locations in the same block for where you've drilled kind of 3 per section? Or is that something -- is that a thesis that you test here in the near term or one that gets tested more over the long term as you drill other parts of your acreage blocks?

John C. Ridens

In the Hogshooter and Cleveland, we have not drilled 3 per section. We have drilled 3 wells per section. And we have seen other operators drill some of the other formations that I named that have been participated in, in the Granite Wash, the 3 per section. But the Hogshooter and Cleveland, that's new developments for us, have not seen that density yet.

H. Craig Clark

Most of the zones we've yet to drill 3 wells per section or in some cases, more than one horizontal. And that's one reason why, quite frankly, our acreage is all held by production for the most part in the Texas Panhandle.

Brian Singer - Goldman Sachs Group Inc., Research Division

All right. And then, you've obviously reported some very strong well results in the Eagle Ford Panhandle, let alone some uplift coming from the resumption of activity in the Haynesville. Trying to think about the impact that these wells that you reported have had on the third quarter or would have on the fourth quarter. Can you just kind of talk about the timing of those wells coming on, was it predominantly back-end loaded in the third quarter or more recently here on the fourth quarter? And what level of delays, midstream-related delays, have you baked into fourth quarter guidance?

Michael N. Kennedy

We left midstream issues pretty much the same for the Q4 since we have not seen any improvement with the previous quarters. And the -- I'm sorry, what was your other question?

H. Craig Clark

The wells were actually -- the Hogshooter in Cleveland were late third quarter.

Michael N. Kennedy

Right.

H. Craig Clark

And then the Haynesville well was October.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. So, I guess, if we look at the midpoint of guidance being up, I think about 12 million cubic feet a day relative to the third quarter, no change in midstream delays. So should we think about that as kind of a run rate based on this level of spending taking out the science and the types of well results that you're saying -- that you've shown?

Michael N. Kennedy

Yes. I wouldn't imply run rate on that. But definitely, the midstream, we haven't baked in any improvement in that. Trying to do this by month is pretty hard to do because they're down and up, so you don't get full month's production. So it's pretty hard then for 2012 through this run rate.

John C. Ridens

Basically, we ignored any midstream improvement because this whole malarkey started late last winter in the first place. So let's keep our fingers crossed but we're taking, to some extent, matters into our own hands.

Operator

Your next question or comment comes from Biju Perincheril with Jefferies & Company.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

A couple of questions. On the Eagle Ford well, so are you -- this latest completion, are you frac-ing into the Chalk?

John C. Ridens

Yes.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

And is there any issues with water there? Or is that -- you're not seeing any of that?

John C. Ridens

The Chalk produces some water in the area. But currently, the well that is flowing back is recovering load water only by chloride testing.

H. Craig Clark

Biju, this is Craig. I think the microseismic would indicate you have some upper growth. We'll probably never know the difference, but let's be very clear the laterals in all 3 phases are directionally controlled in the type target than they are in the Eagle Ford. If we're getting some contribution from the Chalk, great. But there is some upward growth and that's why J.C. said it, but all the laterals are in the Eagle Ford.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. Okay. And then I think you had another really standout well in the Eagle Ford. I think maybe in the Holmes well, was that completed -- was that in the middle section? And did you try anything different? Was its completion that would account for a much better IP rate on that well?

John C. Ridens

That well was drilled in the middle section of the Eagle Ford and it was a longer lateral treated with more stages of frac than what we have been doing subsequently.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. So it was just more of a longer lateral and more stages?

John C. Ridens

That's true.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. So what was the cost in that well? I think you said, this latest one was under $6 million?

John C. Ridens

Yes. If memory serves, the Holmes was in the range of $8.5 million to $9 million.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it.

H. Craig Clark

Even though it was a longer lateral, the number of stages has gravitated up from roughly 10, 19 stages. And I believe that well was about 19 or 20 stages, but they were far apart.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. So the explanation for the rates on that well is just the longer lateral and stages, it's not any sort of where it is located or anything like that?

H. Craig Clark

Yes. But it did help and why we did that other than the arbitrary zone costs with the completion cost still being too high even then and now in my opinion for industry, that well was also an intentional well to hold quite a bit more acreage as one horizontal. It's like in the Bakken. That's where we got the idea.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it, okay. And then, so you're running 2 rigs from the Eagle Ford now? Is that right?

John C. Ridens

Yes.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

And what do you need to see -- to step up to that 5 rigs? What are you looking for?

John C. Ridens

I think that what we're looking for, frankly, is continuing to deliver good results from the changes that we've made in optimizing the landing zone, the completion costs and as we step across our acreage position, further delineating the productivity of this. And so as I mentioned earlier, our initial cluster of about 8 wells was all drilled down in one portion of our acreage to handle lease expiry, to show the depth and breadth, if you will, of our Eagle Ford productivity.

H. Craig Clark

The emphasis on getting refinement on the zone, the horizontal, the lateral and the completion technique. I would probably tell you that we're not geological reasons selecting locations as much as acreage expirations, that's why the book '11 is already being taken care of. And when we go to the 5 that was quoted by the previous caller, we don't skip, we go from 1 to 5 or 2 to 5, it's 1, 2, 3, 4. It's a ramp-up. Hopefully, using the 1,000 horse rig, which is more plentiful than the 15-horsepower rig.

Operator

The next question or comment comes from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Couple of questions. J.C., you mentioned a potential for JV, how many more wells do you think you have to get down before you can -- before a buyer would take a -- would give you the number you want, let's put it that way.

John C. Ridens

Well, Dave, I would say that given that the -- we still have 4 wells to complete, and we are showing positive results from what we've done previously on those 4 wells, and continue to move across our acreage. But we hope that after those next 4, maybe another handful after that. We've got a pretty good position scoped out here particularly since we've been updip, downdip, west and now moving east.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And, Craig, I think in the past, you've talked about, you had a data room open but it wasn't -- you'd have something open with BofA, but my impression was never a full scale data room. Can you just talk about anything you've had out there -- do you yet -- to date?

H. Craig Clark

No, because of the reverse inquiries on the heels of the deal they did, and the bids were not acceptable, either because of the lack of wells or the acreage or whatever. Just as a note, where we sold 10,000 acres and nobody cared for $11,000 an acre, we had one net well, two 1/2 interest wells on that. I wish I knew the magic number of wells to do that because that would be a nice promote. But I think the fact that we've been delineating our land as opposed to others in Gonzales, Wilson and the Wood County, where they cluster around a 12,000 or 20,000 acre block into other sweet spots. And we can do that now, but that does nothing for holding acreage and delineating our position, that's almost 120,000 acres now. The acreage that we did lease is to fill in the hole, so we can drill those sweet spots, including our sneaky way of grabbing some of the updip based on what we saw up there. So some of the land money was intended to fill up the holes. So once we go for it, we can drill all these laterals unabated.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And price, all else being equal, would you rather JV and keep operator-ship or sell it off outright?

H. Craig Clark

Money talks. We've said we'd like to keep part of it but money talks. In this case, the one-off deal we did, they wanted to operate, so we sold that to them for cash. I think it's safe to say with our lantern rigs down there, and doing a pretty good job, like to operate but not mandatory. Heck, if somebody pays 100% of the bills, they can operate. But we have tried to, thus far -- and I think all of the wells but the first 2 were 100% working interest. So we have that data as well using our own rig. And you could do a one-off deal, I guess, like that again, which is attractive. Again, we want to stick around the acreage that we've got because you've got so many variables. Knowing which zone and which frac to put, it's really the only thing that's holding us back.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. And I'm sure you've answered this, J.C., and I just missed it. These next 4 wells, are you going to complete them the exact -- using the same concept you're using the well that worked?

John C. Ridens

Yes. Pretty much, Dave. They'll be completed in the same interval. The only thing that remains to be tweaked is, as we look at what we're seeing on microseismic, would we want to continue to change anything in the fracture stimulation. But having said that, I think that pretty much is going to be the same recipe overall, minor changes.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then you're going to -- does that imply that you have to use microseismic in everything you drill on '12 and '13 or?

H. Craig Clark

No.

John C. Ridens

No. The simple reason the microseismic essentially has seen variability in the initial wells. We said we need to get some microseismic and understand how these frac jobs are actually being transmitted into the reservoir, if you will. And from that, came the idea of let's start raising the lateral landing zone and going with some smaller stages.

H. Craig Clark

And, Dave, that's why we spread the monitor wells out on our program, it takes a little longer but that's why we did them. We, obviously, would be done with the once we've got, just like we're going to do the same.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. That's good color. Moving to the Granite Wash, you talked about -- and I assume that's Granite Wash, you talked about third quarter production being impacted $10 million a day, third-party infrastructure issues. You haven't included that in your fourth quarter guidance.

H. Craig Clark

We have not included any improvement, so we're still modeling $10 million a day down.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. So within the new fourth quarter guidance, you have $10 million a day offline, if you will?

John C. Ridens

Correct.

H. Craig Clark

Correct. That comes in 2 forms, either due to high-line pressure fracs right now or the plants are not fully cutting our liquids and, therefore, we don't get the profit from the ethane, propane, butane mix.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. So it's not necessarily the case where something is down, it just to has come back online in order for you to get that back. It's more -- there's more to it than that?

H. Craig Clark

Yes. But the downtime on the high-line pressure is downtime. It backs out wells, right?

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Yes.

John C. Ridens

And we're under a contract for a lower line pressure.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Maybe let me just ask the damn question rather than dance around it. What are the chances this comes out in the fourth quarter? How do you risk it? Is it 70-30? Is it 20-80?

H. Craig Clark

No. I risk it, it's not coming back on.

John C. Ridens

The reason is we're back into the winter phase again, which is how this got started. But it should be, but by laying our own lines and looping lines and offloading we help the situation. Unfortunately, we're doing it.

Michael N. Kennedy

We're in November 1 and it hasn't come back on, so the chances are slim to none.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. You weren't necessarily sandbagging production, you actually think the chance of it coming back on is...

H. Craig Clark

Yes. There's no sandbag there.

John C. Ridens

There was some plant outages force majeure in Oklahoma by another purchaser. Those trains have come back on, and then they went back down. So it's not -- I'm not optimistic that they're helping us out, although they should. The contract says so.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. And then, correct me if I'm wrong, but were there some in the prepared remarks about potentially building your own pipeline?

H. Craig Clark

Forest Texas Gathering has lines in the southern area of their gathering. I don't know that it's as substantial as our East Texas. We've been laying some looping of lines and offloading some gas ourselves, if we can get the gas released on a one-by-one basis.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

And that's all on the Texas side, right?

H. Craig Clark

Yes. Nothing on the Oklahoma side in terms of pipeline.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

You had acquired -- earlier this year, you bought some acreage in Oklahoma. Have you done anything more on that, to that end?

John C. Ridens

We've added a little bit of minor acreage, Dave, but nothing substantial.

Operator

On to the next question, David Heikkinen with TPH.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just thinking about the Hogshooter and this well's high IP, how should we think about kind of drainage and spacing around this well and how it impacts your thoughts?

John C. Ridens

Well, based on the modeling that we've done, David, we're still thinking 3 wells per section. And that high IP was back into -- off of our successful model that we've ran to indicate that, that well performance could still be consistent with 3 wells per section.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. So thinking about 3 wells per section and a 30-well inventory, are those engineered well locations? Or is it really just 3 wells per section, spacing times 30 wells and that's the acreage that...

John C. Ridens

Those are geologically and engineered-based locations given that we have looked at continuity of pay, thickness of pay, quality of pay and performance of the wells that we observe vertically, as well as this first horizontal test.

H. Craig Clark

The subsurface mapping in the verticals and the horizontals, we do not and I think we've been very clear in the past, take the spacing and divide it by the number of locations even though others have.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So don't think about it your inventory...

H. Craig Clark

We have not exceeded 3 wells per section, sorry.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes. And don't think about your inventory only being 30 wells, is that fair?

H. Craig Clark

Well it's because you haven't spread out very far. Probably the biggest analogy is the Cleveland Tonkawa, which is substantially active on both sides of the Texas and Oklahoma border. And with only 90, we've only basically surrounded our wells. That's because we have the subsurface or a vertical log or test to prove that up with the mapping J.C. referenced. But they are spudded in the geologic model. They are not divided by the spacing in the acreage.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then, I'm not trying to draw an analogy directly here, but expectations for the Granite Wash were driven up from an investor standpoint by your first set of wells. And as I think about this well versus the type curve, how do you want us to help guide investor expectations for the remaining wells? And kind of how that fits in, how big of a statistical anomaly is this well? I mean, how do you want to talk about that? And how should we talk about it?

John C. Ridens

Well, this well exceeds the type curve. I think it's safe to say that everything that we've drilled in the Granite Wash exceeded our initial expectations of horizontals in the Granite Wash. We continue to deliver results that are above the type curve for both Hemphill and Wheeler Counties on a blended basis. So I think that if you look at this, we continue to step through our inventory, we are continually surprised with the upside and deliver results that exceed our type curves. I think that that's the way you should guide investors.

Unknown Analyst -

Okay. So we should guide investors to exceed the type curve for the Hogshooter?

H. Craig Clark

No, I would guide them flat to this curve.

John C. Ridens

We have not...

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's repeating what you said.

H. Craig Clark

That's why it's called the type curve, yes?

John C. Ridens

The type curves he's referring to were the dip doing the Granite Wash, where we've exceeded in the central area, in the $30-million a day well was in the central area. So we stuck to those numbers and used the statistics to bring those up based on well results. That's how we got to the 14 in the south. We've had the wells that brought the average up. We didn't just create a new average. But because of industry activity in the Cleveland and Tonkawa, we have a type curve based on offsets. Although the Missourian Wash, the Hogshooter, whatever you want to call it, we've got to develop a type curve because the one we use for the pre-drill was way more conservative than this rig.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Can you talk about what you think the type curve should be then?

H. Craig Clark

We've not developed the type curve yet. We only have one well.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

All right. So I'm just trying to think how we should guide investors given the 2,800-barrel a day oil well. I didn't really get clarity around that then.

H. Craig Clark

Yes, I wouldn't guide them right now. I would just assume we're having one rig and we're drilling wells on it. When we have further data, we'll update the investment community.

Michael N. Kennedy

And we risked that in our guidance that we just provided.

John C. Ridens

My comments about the type curve and guiding investors on it was for the Granite Wash. I thought that was the issue.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

No, no. I was talking about the -- trying to think about the go-forward plans, not the past.

Operator

[Operator Instructions] Your next question or comment is a follow-up from Biju Perincheril with Jefferies & Company.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

A quick follow-up. What's your timing for testing some of the wider area of your Panhandle acreage for the Hogshooter potential?

John C. Ridens

We're continuing to run a rig on that, Biju. And so we'll have additional results on Q4 and Q1 calls.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Can you say where this well was located?

John C. Ridens

No.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

And then just on -- you mentioned, I mean, you're assuming 3 wells per section, when will you drill the first downspace well there?

John C. Ridens

I wouldn't anticipate that we would be doing that until about the middle of next year as we continue to delineate first. That's always the first thing that we do is delineate the acreage, showing productivity across a broader area and then coming in and downspacing.

H. Craig Clark

I would like to spread out as I mentioned earlier, in more than just one section. That's how we'll develop that location camp.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And I know you talked about the drainage pattern that you still have from the modeling. When you think back and look at Granite Wash and when those spacing assumptions were developed, how did the models compare to what you're seeing today there? How confident are you in the model, I guess, is the question?

John C. Ridens

We're pretty confident in the model because we've done 2 things. We went in and modeled hydraulically fractured wells should do in this area. And then we have been monitoring the production subsequently looking at step rate testing to say, is that consistent with what we thought the model could have been? The answer is yes.

H. Craig Clark

Remember, we did it off the vertical test, too.

John C. Ridens

And I should be clear about this, that modeling is done based on anticipating a drainage area, not anticipating an initial production rate.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And one last question. Can you talk about how you expect your sort of oil and gas mix to evolve over the next year as you drill more Haynesville wells but you're also drilling more of these oily wells?

Michael N. Kennedy

Yes, Biju, we said we're going to be 70%, 30% in Q4 and then as I said, we'll come out with guidance here before year end for 2012.

Operator

Your next question or comment comes from Brian Kuzma with Weiss Multi-Strategy.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

I just want to make sure I got the rig -- currently where your rigs are at. You have 2 in the Eagle Ford, one in the Hogshooter. Where are the rest?

H. Craig Clark

One in the Haynesville, one in the Cleveland, 2 to 3 in the regular Granite Wash, one in the Wolfcamp and then one in East Texas as well testing a liquids concept.

John C. Ridens

And the ones in the Panhandle will bounce back and forth between the plays as we've done in the past, but they're spread evenly between the north, south and central.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Got it. Okay.

John C. Ridens

That's the nice thing about owning your rigs, you can send them where you need to.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

In the average working interest in your Haynesville wells, what is that going to look like?

John C. Ridens

It will vary depending on what section we're in. But on average, it's probably going to be somewhere in the neighborhood of 75% working interest.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Got it. Okay.

H. Craig Clark

You asked a good question, Brian. In Louisiana, if you get a -- with the 25% of our own unit, you have 75%. He's going to try and operate up with the 25%, that's one of the reasons when we said we're protecting our correlative rights that we're active over there today.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Got it. Okay. And then earlier, when you guys were talking about the science capital in 2011, you threw out $120 million for the Eagle Ford. I want to make sure I understood, what does that number pertain to, that's second half total spending?

Michael N. Kennedy

Yes, it's second half total spending.

H. Craig Clark

That was the increase post-Lone Pine.

Michael N. Kennedy

And when I said that won't continue in 2012, I'm hoping that some of that converts to development capital.

H. Craig Clark

Typically, the monitor wells, the course, all the sundry and microseismic and any of the consultants we've had working on things like the [indiscernible].

Operator

The next question or comment comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Just slipping one here, just thinking about the East Texas side of things. I guess, what additionally is needed to kind of get cost down back to $8.5 million range that you guys are targeting, I guess, for Haynesville and what might that level be for Cotton Valley?

Michael N. Kennedy

The things that remain as we continue to -- as we're increasing stages of stimulation in the Haynesville lateral, looking at the overall science per stage, continuing to work on profit cost and then the way that we will continue to drive this cost down is through pad drilling, where we can move batched completions forward and reduce the amount of mobilization on those costs, if you will. On the Cotton Valley, that's an evolving program in that we are drilling longer laterals with more stages. And so in actuality, I would anticipate we will see some higher well cost in the Cotton Valley than we had seen previously but it's because we're going to have longer lateral with more stages, which should give us better IPs and EURs.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. And are you doing much microseismic out there as well or is it primarily just happening in the Eagle Ford?

John C. Ridens

We've got a surface array buried for our Haynesville, so we get microseismic without having to drill monitor wells. We're not planning any microseismic activity currently for Cotton Valley.

H. Craig Clark

And we are doing it in the Wolfcamp.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

And then if I understand it correctly, are you doing -- so the microseismic that has given you some idea on half length, so you kind see how close you can stack the laterals together?

John C. Ridens

In?

Andrew Coleman - Raymond James & Associates, Inc., Research Division

In all the plays, as you're looking at kind of the -- kind of collecting the data?

John C. Ridens

Yes, that's one thing that can help guide us to. The other thing is, primarily in Eagle Ford, we're looking for what kind of frac height are we getting as well to understand how we are impacting both the Eagle Ford and potential penetration of the Chalk, thus making it a Chalk of Ford.[ph].

Operator

And your final question comes from Brian Hunsaker with New Salem Investments.

Brian Hunsaker

I got a cash flow balance sheet question. I see a payment coming due at the end of this year on your long-term debt. And based on your higher CapEx this year, you need to raise capital for that? Or what are the plans for paying that off?

Michael N. Kennedy

Considering I've got $270 million of cash on the balance sheet, I don't think a capital raise is necessary to take out the $285 million debt issuance.

H. Craig Clark

That's why it's been there for most of this year.

Brian Hunsaker

So you got enough additional cash flow. You don't think you're going to do...

Michael N. Kennedy

I've got cash on the balance sheet that's been earmarked to take out that.

Operator

There are no further questions at this time. I would now like to turn the call back over to Patrick Redmond for closing remarks.

Patrick J. Redmond

This concludes our conference call. I want to thank everyone for their interest and participation in our call. If you have any further questions, please feel free to contact us. Thank you.

Operator

This does conclude today's teleconference. You may now disconnect.

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