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Forest Oil (NYSE:FST)

Q1 2012 Earnings Call

May 01, 2012 2:00 pm ET

Executives

Larry C. Busnardo -

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

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

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

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Anne Cameron - BNP Paribas, Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

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

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

Joseph Patrick Magner - Macquarie Research

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

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

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Richard Dearnley

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Forest Oil Corporation Earnings Conference Call. My name is Derek, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Larry Busnardo, Director of Investor Relations. Please proceed.

Larry C. Busnardo

Good afternoon. I want to thank you for participating in our first quarter 2012 earnings conference call. I will note that the replay of this conference call will be available through May 15, as described in our press release issued yesterday.

We have joining us 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 financial performance. Reconciliations of such non-GAAP financial measures with the most comparable financial measure calculated in accordance with GAAP will be available on our website and can be viewed by clicking on 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 will now turn the call over to Michael Kennedy.

Michael N. Kennedy

Thanks, Larry, and thanks everyone joining us today. Larry just recently joined Forest and is the primary Investor Relations contact and we're happy to have him. While in the past, we've done a line-by-line review of the financial results. This quarter, I'd like to just focus on a couple of items as the details are outlined in the press release.

Our first quarter 2012 equivalent production of 337 million per day was down slightly from fourth quarter 2011 due to downtime associated with third-party plant curtailments in Oklahoma. It's important to note that our strategy of focusing on growing our oil and liquids production have been successful as is evident in our first quarter results. Notably, first quarter oil and liquids production accounted for 32% of the net sales volumes. This is the highest percentage of liquids production for Forest since early 2007.

First quarter oil volumes were up 47% year-over-year to approximately 8,400 barrels per day and NGLs were up 7% year-over-year to approximately 9,500 barrels a day. In total, we've achieved oil and liquids production growth of 24% compared to the first quarter of 2011 and all of this growth was accomplished organically.

In addition to our growing liquids production, we continue to add to our natural gas hedge portfolio, which continues to work in our favor, as we realized the 51% uplift to our unhedged natural gas realized price in Q1. Since the last earnings release, we have selectively added to our natural gas hedge position for 2013 by adding 34 million a day of swaps at approximately $4. So in total, we now have 155 million a day of swaps for the April through December 2012 period at $4.33 and 134 million per day for 2013 at $4.02.

Based on our 2012 guided natural gas volumes, this represents a hedge position of 63% of gas production for the remainder of 2012, an excess of 50% in 2013. With liquids accounting for 32%, our Q1 production and the remaining gas production hedged in the 50% to 63% range, Forest only has natural gas exposure, floating natural gas exposure, of approximately 30% with total equivalent volumes through the end of 2013.

The full summary of our hedge position can be found on Page 7 of the press release or in our 10-Q.

For the summarized quarter, we continue to see organic growth in our oil and liquids production and this component now accounts for 32% of the sales volumes. Forest is also in good financial position with meaningful hedges and liquidity as our borrowing base is reaffirmed last week at $1.25 billion and our liquids sponsored growth should continue throughout the year.

I will now turn the call over to J.C. who'll further discuss our operational highlights.

John C. Ridens

Thanks, Mike. In the Panhandle, we had success this quarter in 2 new operated oil liasons for Forest, the Tonkawa and the Granite Wash B. Tonkawa well yielded a 24-hour rate of 1,640 barrels of oil per day, 200 barrels per day of NGL and 1.6 million cubic feet per day of natural gas. Since being placed on production, this well as already produced over 46,000 barrels of oil and continues to produce almost 700 barrels of oil per day, we have further operated drilling in this area as we continue to adjust our drilling schedule toward higher oil content projects.

We're also participating in nonoperated Tonkawa oil wells and between our operated and nonoperated plants, we see an opportunity set for approximately 60 Tonkawa wells so far. We also completed our first operated Granite Wash B test, a deep well in Wheeler County, Texas. This well achieved a 24-hour IP of 16.4 million cubic feet equivalent per day, comprised of over 900 barrels each of oil and NGL, as well as 5.3 million cubic feet of residue gas, yet another deep Granite Wash zone with high liquids.

With these new zones, we've now tested or drilled a total of 13 zones horizontally, and we are not done yet. Every zone on the Granite Wash looks good now.

We completed one more Missourian Wash well, which had a 24-hour IP of 650 barrels of oil equivalent. While this rate was less than our original well, it was a short lateral. We drilled a 2,500-foot lateral testing the limits of the reservoir and this is about what we would have expected as for short lateral with the thinning sand.

During the first quarter, due to the success of drilling higher liquids content zones, our total liquids production increased to 49% of the total production during the first quarter. For comparison's sake, in the Panhandle, this percentage was 45% in the fourth quarter of last year.

We made the transition of our first producing area in the Panhandle to our new gatherer and purchaser. The transition was made on April 1 and it went very smoothly. During the course of 2012, we will continue to transition other areas to ensure we get the best operating conditions possible.

In the Haynesville program, we shut down the drilling program and moved the rig to the Cotton Valley. This is due solely to the difference in value between liquids and natural gas. Prior to shutting down the program, we completed one well in the Haynesville that had a restricted rate of over 9 million cubic feet per day, with a pulling pressure of 7,500-PSI. The well rates are still great and restricting the initial rate that led to higher overall cumulative recoveries. Our Cotton Valley program has superior economics due to the liquids they produce. We completed an additional Cotton Valley well during the quarter that produced over 660 barrels of liquids and 10 million cubic feet per day at an initial rate. A simple comparison of this to the Haynesville shows about the same gas rate with 660 barrels of liquid added was about 3 million barrels per well, less costs.

We put the second rig to work in this program based on the success that we've achieved so far. These tested the pressure pumping rates with lower than last year by about 25% and that further boosted the economics of this play.

With the landing target being raised into the upper Eagle Ford, the well resulted to improve significantly over the lower Eagle Ford completions. The 30-day average production rate for the upper Eagle Ford has been 468 barrels of oil equivalent per day compared to 200 barrels of oil equivalent per day for the lower completions. The lateral lengths and number of stages are actually less for the upper Eagle Ford completions in this comparison, since our first well that we did in the modified program only had 4,000 foot laterals with 12 to 13 stages of frac. The typical recoveries for these wells are markedly different than our first wells built in the lower Eagle Ford as well. The first 2 wells drilled into the upper Eagle Ford program have combined accumulative production that exceeds the combined production of 6 of the wells drilled in the lower landing target. But this is despite being on production for a much short a time. All of these points to the improvement in well results observed thus far, with wells being drilled faster than predicted, frac costs declining and gaining further understanding of the limits of the play.

In the Permian, we completed 2 horizontal wells of the lower Wolfcamp Shale in Crockett County, Texas, with an average initial rate of 200 barrels of oil equivalent per day. This was virtually all oil as there's minimal gas associated with Wolfcamp. These 2 wells completed our initial testing program at the lower Wolfcamp, utilizing microseismic monitor drilling frac techniques, perforation spacing, as well as cost of spacing.

While longer-term production from the Wolfcamp program is obtained, we saw a vertical testing of the other zones to do, utilizing the existing vertical microseismic wells. The thickness of the Wolfcamp is sufficient in our acreage position. Then we will also have to test the middle and upper Wolfcamp in the future.

Our first Wolfbone vertical well was drilled and cased after an extensive coring program. We expect to complete that well in the next couple of weeks and are now drilling the second well in the program.

And with that, I'll now turn the call over to Craig.

H. Craig Clark

Thanks, J.C. for the ops highlights. Good work on adding more crude oil targets in the Panhandle. It seems like the business unit may have to revise our Panhandle location count every time we complete a new horizontal objective. The over 1,000 identified locations we have in the Panhandle looks somewhat conservative at this point. Since Mike covered the liquid production growth in the first quarter, I will focus on our marketing takeaway efforts as it has affected us, industry trends, our outlook and our capital reallocation that results from the outlook at this point in the 2012 cycle.

Briefly, on the marketing takeaway side, which impacted the first quarter volumes, the Oneok Medford NGL storage facility planned outage in March was the main culprit as opposed to gathering line pressures in 2011. This is not a function of our field operations, as all volumes going to this plant were affected in Western Oklahoma and the Texas Panhandle. In order to address the Highline pressures, we transitioned, as previously announced, our first Panhandle production to our new gas purchaser, DCP Midstream, on April 1 which basically does 2 things for us going forward. First, it lowers our line pressures, which is the culprit last year; and secondly, provides for future options for moving our Y-grade NGL product to Mont Belvieu as opposed to Conway from the Panhandle. We are the anchor tenant for DCP on the Texas side of the Panhandle.

Also, on a marketing note, we extended our premium Eagle Ford crude oil contract through the end of 2013, which is currently netting us about $8 over NYMEX WTI. Despite the Medford planned outage, our liquids volume grew sequentially, as Mike referred to, the 4% on the strength of the Panhandle oil wells drilled this year. I noted even our work in interest donors in some of wells that highlighted them in their pressure releases. As noted by Mike, the liquids now comprised 32% of our first quarter production, the highest percent in about 5 years.

Our E&D CapEx for the first quarter 2012 was around $180 million, including $30 million spent in new ventures. We spent $8 million cash and $36 million in equity on land acquisitions that we previously announced, that totaled about 36,000 acres and calculated to be about $1,200 an acre, the same as before. Most of this was in the Permian in the Panhandle.

Our pace of capital spending is usually higher in the first quarter as we get off to a fast start, but we also font-end loaded all the new venture stuff to provide for time for evaluation with minimal amounts in the second half of the year. We're also -- we're moving our Haynesville rig to East Texas, including our pad drilling apparatus. The completed Cotton Valley wells take about $3 million a well over a typical Haynesville fee.

All of our rig activity, as of now, have crude or condensate or NGLs associated with it. The recent Cotton Valley wells that J.C. highlights, makes more revenue from liquids than gas. Activity has certainly picked up in East Texas in the counties of Harrison, Panola and Rust, where most of our acreage is located, following the Anadarko announcement.

Rigs are deployed as follows: 5 in the Panhandle, 2 in East Texas, one in the Eagle Ford, one in the Permian. All are drilling horizontally, except for the Permian Wolfbone rig. Please note that we have used and did use our rigs in the first quarter to drill our water disposal wells in both the Panhandle and starting in the Eagle Ford. Higher disposal cost in the Panhandle and Eagle Ford but, particularly in the Panhandle, are a direct result of the increased demand for this type of activity, specifically in the Panhandle because of the nearby high water producers from the Mississippian play.

The only material non-op activity we have in the company is in the Texas Panhandle, drilling Granite Wash, Mississippian Wash a.k.a. Hogshooter, Tonkawa, Cleveland and Marmaton horizontals. This is the reason why we say 5 to 6 rigs in the Panhandle. We also have one nonoperated rig Uinta Basin, drilling for the Uteland play.

The rigs that could be moved to the Eagle Ford in the case of future capital reallocation from a JV would come from our existing stack Lantern fleet, the Permian and the pad rig from the Haynesville. The Eagle Ford JV, I should note, the data room is still open for a few late comers. We did accomplish cost savings in the Haynesville program, as J.C. alluded to. We reached our goal of 20% to 30% before we moved the rig. We expect to see these kind of savings on the East Texas programs as well.

As J.C. referenced, we're seeing large service discounts in East Texas, and to a lesser extent, the Panhandle and the Eagle Ford. The lower Eagle Ford frac costs were a welcome surprise. Our target well for the Eagle Ford is to try and get with pad drilling from around $5.5 million. The only place in our portfolio, which is not seeing service cost decreases, as I sit here today, is the Permian Basin.

As we go forward in 2012, we will remain flexible for capital reallocation, particularly in the case of the Eagle Ford. Our goal is to monetize our non-reserve base assets within the company, specifically in international and midstream. We have used, as I said on the last call, $4 gas, and $90 crude, NYMEX and our economics flat. But clearly, liquids at the current prices are much more favorable than natural gas, specifically crude oil.

Mike detailed our efforts to mitigate our exposure to the natural gas price fluctuations with our additional hedging program done last year and already this year.

So in summary, is the points I want to exercise are the liquid crude-up volumes, increased despite the plant added speeds bumps it to a 5-year high. Our markets, and even crude oil pricing have been enhanced, trying to get ahead of the peaks' downtime we saw with plants last year. Our 1,000 locations in the Panhandle are significant, and that we have not counted locations all over the untested lands. With 15 zones that J.C. said we've tested successfully, this figures out to be about 60 to 70 locations per zone. Certainly, this compares very favorably to recently-announced transactions in the Panhandle.

It looks like every member of the good-old Granite Wash now works horizontally and we would certainly like to own more assets in this area.

That wraps ups our remarks. Thanks for listening. Operator, we're ready for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question is coming from the line of Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So can you talk about in the Panhandle, Texas, are you all seeing any kind of ethane rejection? And I know you guys brought your guidance down for NGL pricing. Can you give us a sense of what's going on there?

H. Craig Clark

We've not had any NGL rejection ever in terms of the ethane. The biggest issue is the prices were depressed, and we tried to guide for that because our product as a company is split between Conway and Mont Belvieu. And it was the Conway prices that were depressed.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And you mentioned -- I think you said you've got a rig active in the Uteland play, is that right?

John C. Ridens

No, we did not mention that. But we do have some OBO interest in the Uteland play where a rig is running. And it's a nonoperated rig, Scott.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. It's a nonoperated -- how much acres do you have in that play?

H. Craig Clark

That's the old Huston Exploration acreage we had in and around Natural Buttes. I think it's around 80,000 acres.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So can you operate any of that or is that mostly non-op stuff?

H. Craig Clark

It's both. It's the stuff that Houston Exploration had near Natural Buttes.

John C. Ridens

It's primarily a nonoperated position.

Scott Hanold - RBC Capital Markets, LLC, Research Division

I'm sorry, say that again?

John C. Ridens

It's primarily a nonoperated position.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And one last question. In the Eagle Ford, it sounds like your well performance in the upper portion looks much better and I got the sense, you've kind of hinted the fact that you could look to increased activity. Can you kind of give a sense of what you're thinking at this point in time? What would it take for you guys to put a second or even a third rig out there, because I think you've got some acreage exploration you need to work?

Michael N. Kennedy

Right. And right now, what would it take for us to increase that rig count is to see what the determination towards the joint venture process is going to be. And then make that determination as to what the rig schedule needs to be for the remainder of the year, Scott.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Can you give us an update on where that is, that JV process?

Michael N. Kennedy

I can't. The dataroom's still open, because the late comers, as I mentioned, and we're still targeting. Obviously, we've had some new comers, but targeting late second quarter.

Operator

Your next question is coming from the line of Peter Hammond from Simmons & Company.

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

Just curious, how should we think about production and production mix, specifically from Q1 to Q2? Very good liquids production, better than your guidance, do we think that should continue for this quarter?

John C. Ridens

Yes, Pearce, we do. Because basically, the reason that we've gotten off to such a hot start on our liquids production is because of the extremely good results that we've posted out of new zones in the Panhandle, primarily the Missourian Wash and the Tonkawa. And as those results hold up and we continue to look for further exploitation of that, then we would expect to see that the liquids mix would continue to grow.

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

Great. And then, obviously, you've taken that rig from the Haynesville to the Cotton Valley, giving you 2 rigs there. Was there any consideration to potentially move that rig to the Permian? Is there some advantages maybe in trying to derisk that acreage faster in the Permian?

H. Craig Clark

Well, the attraction to that particular rig is that's the rig that we own the rig apparatus for pad drilling, which would be applicable more so in the Eagle Ford, I might say, than in would be in the undelineated Permian base we've got. But we put our -- the Permian plan was as follows, to do the horizontals and the verticals and the monitor wells and Wolfbone and stand back and be able to evaluate them, so we'll still stick to that plan. That rig would be a candidate for the Eagle Ford because of the pad drilling apparatus though.

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

Great. And then just lastly, and I guess this touches on your last comment as a candidate for the Eagle Ford, but do you have a contingency plan in the Eagle Ford to hold the acreage if the JV process is maybe not to your satisfaction?

H. Craig Clark

We'll have to do some reallocation and get some board approvals, but the answer is yes. But what we've done is position rigs accordingly whether or not we can get a JV or not. Obviously, the JV partner would like to know that we have rigs available as opposed to getting in line for one. So we've used the 1,000 and 1,500 horse rigs. The candidates for those types of rigs would be, when we're finished in the Permian, the Haynesville and the rest them that we've laid on the ground just anticipating that.

Operator

The next question, from the line of Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

What are the constraints, if any, to accelerating further in the Panhandle? Should you want to do that, is it capital, is it people, facilities, midstream, and how does the potential further acceleration given the results that you've talked about fall in your priorities?

John C. Ridens

Well, the only thing that we think about there, Brian, is we're already putting the largest percentage of our capital to work in the Panhandle. And with our stated purpose of always trying to maintain a portfolio, we're just trying not to put too many eggs in one basket. Right now, we could run additional rigs with the personnel that we have, that would not be a limiting factor. We could always reallocate rigs out of the Lantern fleet, so rig line could hold up. I will tell you that given some of the outages that we've had on the infrastructure side, I would prefer not to load up any further until we get the rest of the transitions to our new purchaser gatherer in place. Because I think that, that's going to help us with our overall runtime for infrastructure in the Panhandle.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And in Eagle Ford, with regards to the third well that you drilled, the updip delineation well. What was your conclusion following that rate about aerial extent of your acreage to that direction and then prospectivity?

John C. Ridens

Well, it's the same play. There's variability as you get to the edge. This well that we drilled in the updip position was not significantly different from the other well that we drilled in the updip position that had a very good result. And so we've seen a good result, a weak result in the updip portions and I don't think that, that condemns a lot of the acreage because we were right at the edge, as I said of earlier. So right now, we're drilling more in the downdip position and avoiding the edge effects.

H. Craig Clark

Look, to be very clear, we have tested all over the entire acreage base now. The weird part of that well is that it took a long time to clean up. So I don't know if it's the frac or the changes of the fracs, because the frac continue to evolve. But that would be certainly a weak well compared to the average that we've experienced in this last grouping because they've been pretty consistent for the last couple of months.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then lastly, Craig, you mentioned at the end of your comments your interest in adding more Panhandle acreage. Could you add any color how sizable that could be or you would want it to be?

H. Craig Clark

It's all HBP. It's always tough. Some of the leasing that I quoted in the 36,000 was in the Panhandle. It's extremely competitive because of the announced transaction earlier this year. And it's mostly HBP. So you're going to have to do that with farm-ins, some leasing, some top leasing and even some small acquisitions. But it's still one of our best areas and we seem to do pretty well there when we test new zones. So we would love to have more assets in the Panhandle.

Operator

Your next question is coming from the line of Anne Cameron from BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

I just have a question about the Eagle Ford wells. You say in your release that the 30-day average production rates for the new frac technique are over 468 barrels a day, and how many wells are you, including in that sample and which ones are they?

John C. Ridens

Those are 5 wells and we don't name individual wells, Anne, when we go into data releases. But that population is comprised of 5 wells that have production exceeding 30 days. Obviously, the wells that were just added in March and I don't have that 30 day or the second half of March don't have the 30 days yet, so we have not included those.

H. Craig Clark

And those groupings are targeting the middle to upper with the most recent fracs that we're doing, which is more stages, less pound per stage. And those all have the same completion characteristics.

Anne Cameron - BNP Paribas, Research Division

Okay, that's helpful. And how many wells have you completed in the upper member?

John C. Ridens

The 5 that has 30-day history in the middle to upper included in that average.

Anne Cameron - BNP Paribas, Research Division

Okay. But aren't there 2 more today that you see on...

John C. Ridens

There's a couple of wells that are being completed right now that are not included in that average, they are just -- one of them is slowing back and the other is just going on test, I think. But they don't have 30 days.

H. Craig Clark

But to be clear, we're completing 2 drilling one. But the wells going forward will be under that same completion technique.

Anne Cameron - BNP Paribas, Research Division

Okay, got it. And you have a 30-day rate for that Cotton Valley well, the 10.3 million a day?

John C. Ridens

I don't have a 30-day rate. But I'll tell you that I looked at it yesterday and it was still producing an excess of 5 million cubic feet of gas, and that does not included the oil and NGLs associated with that. So it's still performing quite well.

Operator

Your next question is coming from the line of Michael Hall from Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Craig, you mentioned in your prepared remarks an increased ability to get to Mont Belvieu later this year, it sounds like. And just trying to kind of square that up with the NGL guidance, NGL price realization guidance of 35%? Is there may be some upside to that number, and if you can kind of leverage the ability to get to Mont Belvieu?

H. Craig Clark

I didn't give a timeline for it, and I'll just say that number one, most of everything we have along -- well, outside the Panhandle, ends up at Mont Belvieu. It's basically located there, East Texas, leveraging off of that. So what we had done prior to the DCP contract is we had taken some liquids and transported them down there ourselves. Our total -- however, most of your liquids from people in the Mid-Continent go to Conway, that's just the way it's hooked up. And there's been several pipelines announced. I don't know the timing on the first, but the DCP part of our transaction with them is to get their pipeline in, but it won't be this year. But to relieve ourselves of the Conway because it's great in the winter, you hate it in the summer. I don't think it's physical issue, it's a price issue. So what we guided was a blend of Conway and Mont Belvieu, even though we've had more Mont Belvieu barrels today than we had last year. And the percentages, Mike?

Michael N. Kennedy

Right now, I think we're about 2/3 Conway and 1/3 Belvieu.

H. Craig Clark

The short answer is, we didn't assume any Mont Belvieu release when we guided the percentage of NGL barrel in our guidance.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. I guess the other one for me then, as I'm looking in the Eagle Ford, now you've done some of these updip tests and kind of more delineation type activity, are you at a point now where you can start focusing in on where you've had the best results and kind of hammering out your sweet spots at this point or kind of how should we think about that?

John C. Ridens

Yes. And that's the short answer. With the updip testing that we've done, I think that clearly, as we've said, we're down in the more downdip portion. And we have drilled the latest series of wells, if you will, probably the last 3 or 4 wells have been in a so-called fairway that goes pretty much through the heart of the acreage and that's where we're concentrating our activity for the time being because it is delivering consistent results.

H. Craig Clark

And to emphasize that we have not, Mike, we have not offset either the early good wells or the current good wells and that's because of pad drilling, not being done yet, It didn't hold any land. And secondly, I think the initial spacing, some people thought at least in the old side it was going to be 100 acres and you're already seeing some people discuss at the Railroad Commission, as small as 65 acres. It made no sense to us to do offset laterals when you didn't know how far apart they were going to be.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay, that makes sense. And then are you choking back at all or going straight to pump or how are you kind of producing these wells, remind me?

John C. Ridens

No, we don't flow them wide open in any circumstance during the flow back. I wouldn't say that we have put the same restricted rate program in place that we have put in place in the Haynesville. But we are controlling the rates so that they're not wide open, and then flow them until such time as the flow rate has decreased to almost loading status or loading rates, at which point we go ahead and fill the well and then run a pump in it.

H. Craig Clark

And we are big believers in restricted rate, which is still in the minority for the Haynesville, I think. I'm not aware of any restricted rate going on in the Eagle Ford that would probably be more applicables, inherently because the pump has a limited capacity to the pump. You are restricting the right because of the pump capacity though. So, I guess you may be accidentally doing restricted rate. I should emphasize that we have a Lantern workover rig, so when we say we put it on pump, it's almost happens immediately at the point that we need it because the rig is down there even though I did not count that in my rig count in my earlier comments.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. Last one for me, the Uteland acreage, is that 80,000 net or gross? And if it's gross, do you have net count?

H. Craig Clark

I'll have to get back with you on that. It's the old Houston Ex acreage.

Operator

Your next question is coming from the line of David Tameron from Wells Fargo.

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

Let me run through a list here. Craig, in the Uinta, did you say your partner was or do you care to share that?

H. Craig Clark

Just rather not say I don't know what their status is. So I was trying to reconcile our rig count in terms of the nets and the grosses, because I think we have half interest in the well. It's a material one, capital ones.

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

All right. Eagle Rock, the situation last night, does that -- do you have any more color on that, does that impact you?

John C. Ridens

Yes. It impacts us, Dave, and that gas we're looking for a separate outlook for that because we have not gotten a time frame for how long Eagle Rock could be down. But that's not a material amount of our gas. I would say it's probably in the range of about 7 million cubic feet per day that we're looking to offload.

H. Craig Clark

And that is up. They're our smallest purchaser in the Panhandle and that's a legacy contract. But that actually, I believe, picks up only Mendota production, which is, in for our case, only Roberts County, which is our smallest of the 4 producing counties.

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

All right. Jumping over, so are you are done with Wolfcamp for the year, is that what I'm hearing?

H. Craig Clark

Yes.

John C. Ridens

Well, we're done with the horizontal Wolfcamp for the year. There may be some testing that we want to do at other zones in the vertical microseismic wells that we drilled. And our intent all along was to get some production history off of these initial wells and calibrate that back to all the science that we already collected and then look at to how it gets capital allocated in 2013.

H. Craig Clark

What we put in our capital budget was to evaluate them then go make sure all the zones are contributing. But remember, we did drill 2 vertical wells out there for monitoring, which we do intend to complete test the other zone.

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

All right. And what are you guys looking for -- as what are you looking for in the Wolfbone, as far as what -- can you give us any estimation of well cost? On a run rate, like what do you need to get this to be economic out there?

John C. Ridens

I think the well cost numbers are going to be somewhere in the neighborhood of $4 million or our full development or even a little bit less than that. On the Wolfbone, the intent is to take the first 2 wells that we're drilling or one well is down and it'll be completed here in the next couple of weeks. The second well has just started drilling. And so by the time that we do all of the selective production tests, both the Wolfcamp and the Bone Springs members, it'll probably be end of the third quarter before we have full well results. And at that point, we'll look at how we allocate capital into that program in '13 as well.

H. Craig Clark

We did core those wells, Dave, starting from Avalon all the way through the Bone and the Wolf and even below it to the strong, and that's why it takes a little bit longer. The AFE that J.C. referenced assumes that we complete in only 2 Wolfcamp zones and 1/3 Bones Springs zones with no horizontal attempts. Just a straight up and down vertical well, although we did do the science. And I don't know of breakeven, but I believe when we bought that land, our assumption was those wells come in at couple hundred barrels a day and make a couple of thousand barrels, couple hundred thousand barrel of oil for about $4 million, but they're verticals. But we only assume that those 3 lobes [ph] will be contributing even though there's been competitor activity in the other zones.

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

All right, that's helpful. And then, and I apologize if I missed this, but CapEx, whoever wants to take that, could you talk about the run rate and reconciling that to the full year budget. And I missed the first couple of minutes of Mike's comments if that was in there?

H. Craig Clark

I did the CapEx. This is Craig. What we made an assumption there were in the run rate, which was higher is the $30 million in new ventures does not go for the second half of the year. The land as well, because we've got lots of land, obviously. The next one is you relieve the Haynesville rig, which saves you amazing -- I don't know why this is, you don't really drill any wells faster in the Cotton Valley and the Haynesville in terms of when putting them on. But, whatever, you save $3 million a well. So that goes from today. And then last but not least, we programmed this Eagle Ford rig in there, the one-rig program pending any JV, so there's your capital run rate reconciliation.

Operator

Your next question is coming from the line of Brian Lively from Tudor, Pickering, Holt.

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

In the Midland Basin, can you guys talk about what attracted you to the lower Wolfcamp being the initial target zone and then compare the upper and middle Wolfcamp to the lower, please?

H. Craig Clark

It's simple. When we started, our assumption is when we cored it, and we cored above and below it, the cores were 1,000 foot thick. We saw the cores, it's perspective, it's oil. I don't know if I want to speculate which is better or worse, but the reason when we said this publicly, Brian, we started from the bottom-up as we have the ability to sidetrack the well or add other zones later. But we cored the entire section and started from the bottom up. I've heard people say A, B, C, D, E, B client bench segments below which is the strong and the Alan Berger. Above is just the Clearfork and the San Andres. That's why we drilled the vertical wells so we could go tap those zones and those other verticals.

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

Okay. But no discussion on what you're seeing on the upper and middle in terms of at least the relative characteristics or quality versus the lower? Are you just going to have...

H. Craig Clark

I don't have an opinion on the quality. I think it's just perspective. And we said this publicly, you are never going to get this with one lateral, it's too thick. We targeted the thickness, the maturity and the porosity. I think our competitor out there next to us has said, you'll need 3. I'll tell you, you're not going to get it with one, but the reason we started at the bottom was simple, it looked as prospective as the upper and the middle. If you start at the bottom, you can always back up.

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

Great. On the Eagle Ford, the 468 barrels a day average 30-day rate for the upper lateral, what is your projected EUR on these wells on average?

John C. Ridens

Our type curve is 350 MBoe, and that's going to be comprised of about 90-percent plus oil.

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

Okay. And then you guys talked about the well that you completed in the updip area. What percentage of the total Eagle Ford position is? Would you consider that updip area versus where you're seeing the higher rates?

John C. Ridens

Well, one of the wells, as I've referenced, that we drilled in the updip area that was on strike with this well was one of the wells that has performed quite well. And at this point, I can only say that we have minimal acreage that is further on strike in the same updip position. I happen to put a pencil to it to try to figure the exact percentage, but it's not going to be a large percentage.

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

Okay, so that 350 MBoe, well, EUR, I guess, is you feel like that's a pretty good average across the entire 103 acre position?

John C. Ridens

Yes. Based on the thickness of the Eagle Ford that we have mapped and we've got vertical penetrations dating back into the 80s, testing other zones, that have shown us that, that thickness is consistent. We have seismic that backs that thickness up. So I don't see any reason that we see any great variations going across that acreage position.

H. Craig Clark

We have seen some activity north of us in Lee in Fayette, from privates and even geo resources, which was in the news lately. And that maybe in the updip position, we're getting a bigger contribution from the chalk, but all laterals have been landed in the Eagle Ford.

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

Okay. And then last question for me, on the Cotton Valley liquids potential, what percentage of your Cotton Valley position do you think is prospective for liquids?

John C. Ridens

We've got about 15,000 acres so far that we have flagged as having this sort of potential that we're working on right now. And that is something that as well results go, we'll see if they can be expanded further.

H. Craig Clark

We have 150,000 acres roughly in East Texas in all but one of the fields, Gilmore, our currently Cotton Valley fields that make liquids to varying degree. Most of our acreage per in our Analyst Conference maps or whatever, is concentrated in Harrison, which is where one of the average wells was; Panola, which is where Anadarko made the Carthage announcement; and Rusk, which is where the other wells are. So the wells we've talked about to date which are greater than 15,000, J.C.'s referring to one field. But all of our acreage is basically held in East Texas by the Cotton Valley or the Cotton Valley Lime, and Gilmore is the lime producer, Western Upshur County.

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

Okay. So, I guess, the takeaway from that is that the liquids potential then should stress across most of the East Texas position that you guys have?

H. Craig Clark

All of the Cotton Valley liquids has processable gas, inside processing initiative in 2004. Some of it may be higher or lower in terms of the yield because of the depth. The wells J.C.'s quote before were in the Rusk County area, which is where the rig is currently. But I think, this year, we've done both Harrison and Rusk County. We've not been to Panola yet. But all of our Cotton Valley gas has to be stripped of liquids to varying degrees.

Operator

Your Next question is coming from the line of Joe Magner from Macquarie.

Joseph Patrick Magner - Macquarie Research

In the Hogshooter play, other industry participants have announced some results recently and talked about different horizons in that one zone. Can you talk about your thoughts around that, and where this latest well may have been located in terms of which zone?

John C. Ridens

That was located in what we would call the B section of this. We see 3 perspective loads, A, B and C. And so our high-rate wells were in B. This well was in the B. We had another very good well that we've released during the fourth quarter that tested to C. So we tested 2 out of the 3 loads. I think the other industry activity that you're seeing has been confined to the B.

H. Craig Clark

When we count locations up, Joe, we're just treating it as one zone for the roadshow slides.

Joseph Patrick Magner - Macquarie Research

Okay. And does this latest result change the, I guess, inventory? What was the latest inventory, was it 45...

H. Craig Clark

45 locations, Joe.

Joseph Patrick Magner - Macquarie Research

What was it, 45?

Michael N. Kennedy

45

John C. Ridens

No ,it does not, Joe. Because as I said, we were drilling this and knowing that we were drilling [indiscernible] sands, the 650 Boe rate that we got was darn near what we've ran for a risked pre-drill rate for the first wells that came in, in excess of 2,000 and then 4,000 barrels of oil per day. So this play is still meeting every expectation that we had and we've tested -- the well that we just drilled that, we referenced in the result this time, was drilled looking for the edge of the reservoir, and we've confirmed it.

Joseph Patrick Magner - Macquarie Research

Okay. In the switch between Haynesville to the Cotton Valley, can you discuss the trade-offs in terms of production, contribution? I understand the well costs are about $3 million less, but just in terms of overall production contribution, gas versus liquid -- I guess, Haynesville is mostly gas. But just some of the trade-offs you're expecting in terms of the outlook for the balance of the year?

John C. Ridens

Yes. In actuality, when we look at that program, I think that we're going to be neutral to slightly better on overall production, because the IPs out of Cotton Valley on just the gas are very similar to the IPs that we were getting out of the Haynesville. The Haynesville has got a so much shallower decline because of the restricted rate that we used there, while the Cotton Valley will show us somewhat more a hyperbolic trend. However, the liquids that we've produced there will more than make up for that in overall production, I think. So we ought to be neutral to slightly positive, but certainly, we will have a much larger economic impact given the liquids content.

H. Craig Clark

And that's assuming, Joe, that we pull restricted rates or stay on restricted a rate for the Haynesville. Obviously, our competitors and partners out there like in Cana that they would obviously have a bigger dramatic impact. Secondly, if you are pad drilling in the Haynesville and we were -- you bring all those wells on at onetime, this makes it less blocky. That's not our intent, but we were in the process of pad drilling and to get our cost down. That does make it a little more difficult to guide when you turning on 3 or 4 wells at once.

Joseph Patrick Magner - Macquarie Research

Okay. And in terms of the economic impact you see, you touched on it a little bit. Are the working interests mentioned for the 2 wells in the release representative of those 2 programs or can you give us a breakdown of kind of the average working interest and average net revenue interest between the 2?

John C. Ridens

The Cotton Valley program is going to be higher working interest overall than the Haynesville program, because we've got 90% working interest in the one well that we just released. I know we're drilling another well that's 100% right now. And then the Red River acreage, we had a 57% working interest in what we had drilled this quarter. Now the Red River acreage varies, but there is very little of it, it was 100%. So I think that overall, our working interest will be higher in the Cotton Valley well.

Joseph Patrick Magner - Macquarie Research

Okay. And maybe I'll try to follow up there. And what are your latest thoughts on whether you're seeing a contribution from the Austin Chalk or expect to see a contribution based on the latest lateral, location and completion designs?

John C. Ridens

I think that we are going to see contribution from the Austin Chalk simply because there has been vertical chalk producers drilled in areas across this acreage position, and so we know that chalk contributes. Our microseismic results taken from upper Eagle Ford completions, showed growth up into the chalk, so there's no reason for me not to expect that we're going to get a contribution there.

H. Craig Clark

What we know from the verticals, which is why we leased the land, like all, is the chalk wells vertically with minimal fracs were getting some contribution and being sourced from the Eagle Ford. The predicament, other than the laterals, are all in the Eagle Ford, so you really don't know, is unfortunately the oil looks the same where it comes out at one some in the other. But it could be that you're getting a contribution, but the Eagle Ford was sourced into the chalk for some of the statistics we showed a couple of years back. That's why we lease the land.

Joseph Patrick Magner - Macquarie Research

Okay. Last one for me. Mike, in light of the Italian ceiling cost write-down, can you give us an update on where the cushion is or where the domestic...

Michael N. Kennedy

Yes. Right now is, Joe, the cushion is about $300 million.

Operator

Your next question is coming from the line of Duane Grubert from Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes, Craig, could you walk me through how do you guide internally get from delineating to developing a very complex play like you've got in the Panhandle? And if you might talk to me about what kind of data are you hoping to get with your ongoing drilling work to make that more clear on sub-zone developments?

H. Craig Clark

I don't know if the Panhandle is complicated as the shales. But when we use the word test, some people think we're trying to delineate. Let's be very clear, with 600 or 700 verticals out there, we're not making a leap of faith to development. The zones are there and they've tested hydrocarbons. Where we're counting locations and where we're testing locations is we haven't considered the horizontal potential until we plugged one into it and watched it perform. And that, of course, means we're out there not drilling between vertical wells, but we're drilling in areas where the zones have been tested horizontally. However, assuming vertically, and we're counting it as horizontal. So I would probably tell you that the biggest challenge in the Panhandle is to communicate that there's numbers of zones and wells. Every time we refer to a zone, we're not counting any other zones adding with behind pipes. I think it's impossible to drill a dry hole, because you've got the behind pipes. I think it's the number of zones that may work on top of the zones that do work that creates some of the confusion. But it's pretty comforting for me, because we've got zones tested before us by others or by a vertical before we go horizontal. Secondly, in terms of the testing of the zones, we spent most of our career out here and now it looks like we've gotten everything in the Granite Wash tested horizontally, and so it going to be spread out. We did not do, and that served us to hold the acreage, a lot of shale oil testing and everything for the Missourian Wash to the Cleveland, Tonkawa. That's why we had such a conservative type curve and quite frankly, explain some of the over-performance on the oil in last year and early this year.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And along those lines, when you do decide to go horizontally, what kind of tweaks are you making at this point, if any?

John C. Ridens

What we're doing, Duane, is some of the tweaks that are occurring is in addition to taking the results that we've already obtained out of one area in the Granite Wash, for example. And looking at the productivity of that, then matching that to a net pay map or another zone in terms of thickness, looking for what type of flow unit we can land the horizontal in. We've gotten thinner, so we've been able to tweak some of the landing zones and yet still drill successful laterals in there. We have pretty much settled on a frac recipe in terms of spacing, perforations and clusters. But we're still experimenting with how much can we throttle back on the frac side and still make extremely economic wells. Some of the latest wells that we've been drilling have actually have smaller fracs than some of their predecessors and yet are still performing very well. So those are some of the tweaks that we're making in addition to every time we're drilling a well, we look at the results and say, how much further can we push through this play.

H. Craig Clark

Duane, I know you’re a Reservoir Engineer, you can appreciate that we do -- we did the reservoir simulation on the verticals, and now the horizontal using Merlin Software, we modeled the horizontal versus vertical. Clearly we've beaten that 3 or 4:1 ratio that we used initially. And the explanation is we're getting a better completion in the horizontal and a better extraction with it because, quite frankly, back in the old days, we weren't getting out as far on a fracture half length from the verticals than most people thought. But we do reservoir stimulation where we have verticals before we drill the horizontal.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay, very good. And kind of related, in the JV process for the Eagle Ford, is the data room exclusively Eagle Ford, or are any of your other plays represented in that data room?

H. Craig Clark

No, it's exclusively Eagle Ford. That's all Jeffries has been engaged.

Operator

Your next question is coming from the line of Biju Perincheril from Jefferies.

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

A couple of questions. First on your liquids mix. Obviously, you're off to a strong start in the first quarter. But maintaining guidance, I think at 30%, but how should we think about it going forward especially with success you had with some of the liquids plays?

Michael N. Kennedy

Well, I think that as we said already, Biju, we are exceeding that guidance already with the additional zones that we've tested that are still showing to be very strong liquids rates. We continue this pace and we'll look to increase our guidance, because right now we've had, frankly, some just below well results in zones that we've tested in the Panhandle.

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

Okay. And in the Panhandle, when you see the decline rates, do you -- is the condensate declining, and the content in gas, are they both declining at the same rate or do you see a shallower decline in one versus the other?

John C. Ridens

The condensate rates in the Granite Wash will decline over time. The yield will decline over time as we produce those wells. So we start off with a model that has one yield, gradually decreasing over the life of the well. NGL stays consistent with that yield throughout the life of the well. So that's the way that we model that. On the oil reservoirs, of course, it's a totally different story because we don't see the oil rate changing until such time as you reach bubble point pressure.

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

All right. So maybe you can you give me some numbers there if you'd -- kind of what'll it be like the initial condensate yield and what will be like that maybe end of year 1 or year 2?

John C. Ridens

I can't give you that just off of the top of my head. And part of this is the variability that we see in various members, because as I pointed out to you in the past this gradually gets drier as you get down deeper in the section some time here to the Tonkawa there's very few liquids to be achieved at all. So we model this by zone with a different yield for each and I can't tell you what that is just off the top of my head.

H. Craig Clark

This is Craig. When he said -- sorry to interrupt, when he said, when he was talking about the over-performance, he was talking about the oil wells who don't change because that is crude oil.

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

Okay, got it. And in the Cleveland play, have you drilled anymore wells there since the last update? And I don't know, I think you previously said you had about 90 well inventory, any changes to that?

John C. Ridens

No, we drilled some additional wells into Cleveland. We've had results as high as 300, 400 barrels a day out of the lightest batch. And it's a nice little program for us, but it just wasn't notable compared to some of the other things, so we didn't even talk about it at this time.

H. Craig Clark

The 5 to 6 rigs that we alluded to in our comments, we have a non-op rig that's actually in the Cleveland. In some occasions, we operate. In one occasion, we have as much as 60% of that well and don't operate. So my 5 to 6 are my big non-op net rig is pretty much a Cleveland rig that's currently not operated by Forest. Cleveland activity, but even though we have a material interest because of our predecessor, we don't operate.

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

And that 90 well inventory, that's still a good number?

John C. Ridens

Yes.

Operator

Your next question is coming from the line of Dan Morrison from Global Hunter.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

And they're a long couple of quickies. The horizontal Wolfcamp wells, could you elaborate a little bit on how those were completed as far as link to laterals, the number of stages?

H. Craig Clark

First, they were all about 4,500 to 5,000 footers. All in the lower, the first one was frac 10x, the second one was about 15x and the third one was about 20 or 22x. The first 2 were frac lesser to be conservative, but also those were the ones that were monitored seismically. And then we increased the stages on the third well. We have not gone into check to see if they're all contributing with production logs or drilling that was part of the evaluation process we alluded to earlier.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Great. And over to the Haynesville, you've mentioned your advocates of the restricted program on bringing on new wells. Are you all otherwise restricting or reducing rates or limiting rates for economic reasons beyond the reservoir performance enhancement?

John C. Ridens

In the Haynesville?

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Yes, sir.

H. Craig Clark

No, it was not to drill wells to curtail them or shut them in. The best way, if you're going to cut back on our opinion, is just don't drill them if you're HBP. And we are blessed with that, at least in the Haynesville. The restricted rate was there as we said early on to baby the prop or use lesser prop, saved us a lot of money a year ago. And then as J.C. has alluded to, we make more production in the first year and therefore, have higher EURs based on early work that Petrohawk did. But it's not a gas price arbitrage now.

Operator

Your next question is coming from the line of Richard Dearnley from Longport Partners.

Richard Dearnley

I'm just trying to understand the Missourian Wash. You had one excellent well and one poor one where modest to grow at [ph] the first that you reported in the fourth quarter. And then you have the 650 that you talked about now where you were testing the limits. So we have on a 5,700 or 1,900 and the 650, is that all -- have you just drilled the 3? And what do we -- do we have any conclusions here?

John C. Ridens

Yes, we do have conclusions. And the conclusions are we have drilled 4 wells in total. Those 4 wells at an average are still going to be somewhere in the neighborhood of 2,000 barrels per day. Yes, we've got one that was 650 barrels per day. The conclusion to be drawn there is that, as I said earlier, we were testing the limits of reservoir. So we had drilled out in an area that we had mapped as a thin. Why would do that? To determine is this really the edge of the play or can it be pushed further? We got to know where the edge is. We can't always just come in and drill the [indiscernible]. And so those are the conclusions that one can take away. The other thing that we can take away is that one of the moderate wells that we had released previously was drilled into a separate bench of the Missourian Wash, once again pointing out that this play has more potential than we originally identified when we thought, okay, we're going to drill a B test, we see the other benches, we don't know if they are as productive. We have established productivity out of another bench pointing to additional inventory that we can go out and harvest.

Richard Dearnley

So the 1,900 IP well was the different bench?

John C. Ridens

I can't tell you which one that was specifically. I think that, that is correct simply because I know that in bench A or the first bench that we tested, we've got 2 wells that combined flowed about 8,000 barrels of oil per day.

H. Craig Clark

I think what we know is that our original type curve, which was 600 barrels a day was too conservative. So all the wells have exceeded that, even the thin one that J.C. referred to this quarter. Secondly, it's crude oil productive in the multiple benches. And please remember, we're not guiding that we make only the best well, we are trying to hit the middle. Our middle was probably a little conservative. But we've also had some reports from this zone called Hogshooter over in Western Oklahoma. We've also had a number of competitors that got to offset either our medium or our highest rate well and use some have seen their rates vary from 1,000 to 2,000 Boe per day. It’s certainly an attractive oil target. In fact, I would tell you it's probably our most attractive oil target in the south in the Panhandle, and I'm sure others will agree. The thing is we did not have a lot of vertical extraction from that, so our type curve was too conservative. But I think it's important as we spread out, including to the areas J.C. described, that we try and use the midpoint of the type curve and not the best well or the worst well.

John C. Ridens

And previously, one of those wells that we released on the last call, which had an IP of almost 5,000 barrels a day has come to 176,000 barrels of oil, 62,000 barrels of NGLs and 417 million cubic feet of gas and still continues produce an excess of 600 barrels of oil per day, while flowing. Yes, when we started out of the 350,000-barrel tight curve and here in a period of about 2.5 months, we're over half of that recovery.

Operator

Your next question is coming from the line of Michael Hall from Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Sort of to follow-up just quickly, I was curious on the horizontal Cotton Valley well, the liquids, how much of that was the oil and condensate versus NGL?

John C. Ridens

On a percentage basis, we have about 25% to 30% condensate. The remainder would be NGLs.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Is that of the total or of the -- just of the liquids ?

John C. Ridens

662 barrels. That's just the liquids.

H. Craig Clark

That's not too far off from what Anadarko reported in Panola and Rusk and Harrison. The only difference that makes when the yield is, if you go west, you get a little deeper, you get a little higher condensate rate.

Operator

At this time, I'm showing no further questions in queue. I would like to turn the call back to over to Mr. Larry Busnardo for any closing remarks.

Larry C. Busnardo

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

Operator

Ladies and gentlemen, that concludes today's conference. We thank you for your participation. You may now disconnect. Have a great day.

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