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Executives

Patrick Redmond - Vice President of Corporate Planning and Investor Relations

John Ridens - Chief Operating Officer and Executive Vice President

Michael Kennedy - Chief Financial Officer and Executive Vice President

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

Analysts

Jeffrey Robertson - Barclays Capital

Brian Singer - Goldman Sachs Group Inc.

Scott Hanold - RBC Capital Markets, LLC

Dan McSpirit - BMO Capital Markets U.S.

Joseph Magner - Macquarie Research

Biju Perincheril - Jefferies & Company, Inc.

David Tameron - Wells Fargo Securities, LLC

John Herrlin - Societe Generale Cross Asset Research

Gil Yang - BofA Merrill Lynch

Pearce Hammond - Simmons & Company International

Unknown Analyst -

Forest Oil (FST) Q2 2011 Earnings Call August 2, 2011 2:00 PM ET

Operator

Good afternoon, my name is Kristen, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Second Quarter 2011 Earnings Call. [Operator Instructions]

[Audio Gap]

Michael Kennedy

At or around September 30, 2011, on a highlight that we consolidate Lone Pine's results into our financials as we own 82%. However, we also presented our financial results as if the spin-off of Lone Pine had already occurred, which we described as Forest Remainco. There is also few onetime items in our Q2 results that pertain to the Lone Pine transaction. We have provided these as adjustments to our earnings cash flow and EBITDA.

I will first provide a high-level review of our consolidated results and then follow with a more detailed review of Forest Remainco results.

On a consolidated basis, Forest produced 429 million per day, with liquids comprising 26%. This represents a 1% sequential growth in Q1 in total production and 14% sequential growth in liquids or 2,100 barrels per day. Adjusted earnings for the quarter were $41 million or $0.36 per share, with adjusted EBITDA of $176 million and adjusted cash flow $140 million.

The remainder of my remarks will pertain to Forest Remainco only. Forest Remainco produced 335 million a day, with liquids comprising 28% of total production. Adjusted earnings were $33 million or $0.29 per diluted share, with adjusted EBITDA of $142 million and adjusted cash low of $107 million.

Differentials are better than expected this quarter from natural gas at $0.32 per Mcfe, and we actually had a positive differential in the oil side of about $0.79 per barrel. NGL pricing was in line with realizations, 44% of NYMEX.

Production expense for the quarter was $1.30 per Mcfe, with cash G&A expense of $0.33 per Mcfe. G&A remained in line despite the administrative cost related to the Lone Pine transaction. DD&A increased during the quarter to $1.72, as our capital program is focused on oil and NGL projects and those projects have higher F&D costs in our current DD&A rates.

Our E&D capital expenditures were $193 million. We also invested $52 million in leasehold acquisitions in Q2, adding acreage in the Eagle Ford Shale and Gonzales County and in the Granite Wash. This investment was more than offset by the sales of approximately 11,000 net acres in the Eagle Ford Shale and Wilson County for $110 million.

Forest Remainco's balance sheet was strengthened during the quarter as net debt was reduced by approximately $300 million to $1.4 billion. This was accomplished through the repayment of our intercompany note with Lone Pine and the previously mentioned Wilson County acreage sale.

We entered into a new credit facility during Q2, which matures in June of 2016, with an initial borrowing base of $1.25 billion. There are no amounts outstanding on this facility, and we had cash of $474 million as of June 30, 2011. The undrawn facility and cash on hand results from liquidity in excess of $1.7 billion.

We are well-hedged for the remainder of 2011 and 2012. As a reminder, all the hedges I will discuss relate to Forest Remainco. Lone Pine has a separate hedge portfolio that they put in place subsequent to the IPO date. So for Forest Remainco, on the natural gas side, we have 150 million a day or approximately 64% of guided production hedged at $5.48 for the remainder of 2011 and 105 million a day hedged at $5.30 for 2012.

So to summarize. Q2 2011 saw a steady increase on our liquids volume. We have a strong balance sheet and have the capital required to develop our significant acreage positions in our liquids plays in the Granite Wash, Eagle Ford and Wolfcamp Shale.

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

John Ridens

Thanks, Mike. In terms of Q2 E&D CapEx, we spent $193 million in the U.S., drilling a total of 39 wells, most of which were horizontal, with a 100% success rate.

In the Granite Wash, we completely 4 horizontal wells that had averaged 24-hour IPs of over 9 million cubic feet equivalents per day, of which approximately 46% or 700 barrels per day was liquids. With the areas that we are drilling and the results and costs, these are good IPs, but are obviously not as good as our 2010 average, which was exceeding 20 million cubic feet equivalent per day.

The results in the Granite Wash were being affected by the following items: One, our drilling in 2010 was focused in the much deeper Southern area or Wheeler County and comprised only 2 zones, both of which were extremely prolific. In 2011 we dedicated about 1/2 of our rig fleet to Wheeler and half to Hemphill, and you can see that in the mix of Q2 wells as only one well was drilled in the Wheeler County, with the other 3 being in Hemphill County. During this time last year, we had no wells being drilled in Hemphill County.

Number two, we're seeing more activity in tightness in services due to increased levels of activity in the area. Things are pretty tight in this market.

Number three, high line pressure and third-party infrastructure downtime, including liquids extraction, has been a much larger issue this year than last. The result of this on our production was approximately 4 million cubic feet equivalent per day for the second quarter. This has caused us to move drilling activity around to abate some of these issues. And with this problem not being solved in a timely manner, we're now considering gathering alternatives, both from laying our own pipe, which we've already done somewhat in Wheeler County, to bringing in a new midstream partner. Other companies in the area have been seeing this issue as well as we compete for the available infrastructure.

Lastly, the mix of wells being drilled in the second half of 2012 is focused on testing zones with new oil concepts. We've now tested 6 different zones horizontally in the Panhandle and have 2 more new zone tests currently underway. This is just on the wells we operates and doesn't include a couple of additional zones tested by other operators.

We continue to look for ways to optimize, not just raw rate on an Mcf or BOE basis, but also the value of the combined stream from these wells as liquids content, specifically oil, rules the day in terms of value. Other completion services are extremely tight in this area. Our completion costs are coming down here solely due to changes in practice zones. We aren't getting any price reductions from service providers, but our overall completion cost is about $700,000 less per well than in 2010. This has been achieved through changes in profit, job sizes and treatment rates.

During the second quarter, we completed 4 new horizontal Eagle Ford wells with an average IP of 747 barrels of oil equivalent per day. This increased our total number of producing wells in Gonzales County to 6, an additional 2 that were being completed and 2 that are in the drilling phase. We have 2 rigs running. We're using both the 1,500-horsepower rig and a smaller 1,000-horsepower rig.

Our super lateral was recently completed with 23 stages and achieved an IP of approximately 1,000 barrels oil equivalent per day, 95% of which was oil. This well is exceeding our type curve that we set for the Eagle Ford and has a shallower decline rate than the first wells we drilled during the time it has been on production.

Our new leasing activity has filled in holes in our lands, which allow for longer lateral lengths, as well as bad drilling. We recently replaced the rod pump in one of our previous completions with an ESP, electrical submersible pump, and this has resulted in a significant increase in the oil production. We did this because the well was flumping, that is the well was flowing while pumping, and it was clear the well was producing more liquid than the rod pump capacity. As we monitor the production from this well, we will consider installation of additional ESPs, as they serve to lower the flowing bottom hole pressure on these wells more so than a rod pump does.

Our completed cost per stage in the Eagle Ford has been reduced by approximately 47% since our first well in Wilson County. When I say completed cost per stage, I'm taking the total well cost and dividing it by the number of stages pumped. This methodology is used because we have reduced costs on both the drilling and completion phases. The drilling group has been drilling longer laterals for a lower overall well cost than our initial wells. For example, our first well in the play that did not have a pilot hole and core, cost $2 million to drill, with a lateral length of 3,800 feet. Our super lateral was drilled with a lateral length of 7,500 feet and only cost $2.5 million. So we basically got 2x the lateral length and only spent an incremental $500,000 to obtain it.

The cost of frac each stage have been declining as well due primarily to our design changes. We've been changing profit design, as well as treatment rates, which have resulted in significant savings. The bottom line is we are now preparing AFEs for 15 stage horizontals that are $1.5 million less than an equivalent well drilled in the first quarter of this year.

On the science front, we are currently drilling micro-seismic observation wells in the Eagle Ford, that after frac monitoring will be used for water supply for fracturing additional wells. This ensures a secure water supply for our future drilling program. This is especially good for the play as it removes any doubt that we will have water secured for future fracs, and we'll relieve the pressure on surface water usage during the drought conditions in Texas.

Our first science well in the Wolfcamp has started drilling with the extensive coring of the Wolfcamp completed. This well will then be used as a micro seismic observation well for the horizontal offset that will be drilled next. The Wolfcamp is attractive to us, given its average thickness of 700 feet on our leases. It produces oil in the area. It's at depth that allows us to utilize 1,000-horsepower lantern rigs. And finally, that it can be serviced out of the Permian Basin.

The Permian Basin has the largest concentration of pressure pumping services from 1 of our major suppliers. And while our activity levels were high, they are not as high as the Eagle Ford.

That concludes my comments on the second quarter operations, and I will now turn the call over to Craig.

H. Clark

Thanks, J.C. and for Mike for their good summary. I get the bring up the rear, and I will discuss a few points on the recent Lone Pine transaction followed by the plans for Forest for the rest of 2011 and a few comments on industry trends.

Many of us on the Forest management team have worked a long while on ensuring the successful launch of Lone Pine. We essentially had to do 2 quarter closes. It is noteworthy that we kept our G&A costs at Forest in line while doing this complicated transaction. It's also tougher when it's the first transaction of its kind in Canada. Certainly, it's innovative while being accretive for the Forest shareholders.

We view this transaction in the forecasted spin-out of the Lone Pine shares to the Forest shareholders to be extremely shareholder friendly, same with our Mariner offshore transaction about 5 years ago. After the Lone Pine spin-out, we will have given back dividends to the Forest shareholder of over $2 billion. Both Forest and Lone Pine shares are attractively priced, and I believe the overhanging concerns surrounding the spin-out of our Long Pine shares are unwarranted.

In addition to the Canadian IPO, which occupied most of my time in the second quarter, we had the following highlights: we again added significant acreage in the second quarter, including in the Eagle Ford; year-to-date, we have added 137,000 gross and 125,000 net acres for expenditures totaling of $106 million, for an average price of around $850 an acre, a great price considering the prices paid to us in Wilson County and by industry in recent deals, especially since all of the acreage that we've acquired is focused on oil plays.

The second quarter additions in acreage were higher per acre due to adding more Eagle Ford and about 5,000 net acres in the Panhandle. Another way to look at it, get it if we sold 11,000 acres and gained 125,000 acres after the sale while still using house money. It's a clear advantage to be on the front-end of these plays.

In the second quarter we achieved 2 milestones on our extensive Eagle Ford Shale position. First, the successful results to date caused us to increase CapEx in this play significantly from the previously allocated $50 million, as I refer to grubstake, at the beginning of 2011. Secondly, our gross in net acres position grew despite the sale to 126,000 gross and 116,000 net acres despite divesting the 11,000 acres for $110 million.

So we marked our market at approximately $10,000 an acre for an acreage bond that was quite frankly not contiguous to our large blocky Gonzales County position, plus about half of the positions sold was non-operating. We believe we have one of the few large contiguous positions remaining in the play. They are not currently under a JV arrangement. Our acreage and rig schedule will be positioned for the future lease capture.

We also were trying to position ourselves for the future, as J.C. noted in the Eagle Ford, Panhandle and Wolfcamp for things like science, I call it, cores and micro seismic and water handling. We look at these plays in 3 steps: lease capture, technology and resource capture, not skipping a step. Unfortunately, sometimes, the industry focuses only on lease capture without all of those things that come with it.

So post the Canadian IPO, we have moved forward 3 play initiatives, all focused BO, or barrel of oil, not BOE. And the Eagle Ford, we plan to run a 2-rig operated program for the remainder of the year continuum [ph], including the science, with a bias upwards for more activity following delineation success and the micro seismic work across our blocking acreage position that J.C. described. This area, we believe, is 90% crude by volume and we would hope to capture more margin and cash flow going forward from crude prices, as well as lower well cost.

The second oil focus play is the Texas Panhandle, when I'm talking about liquids, I'm talking about oil. We plan to devote 3 operated rigs focused on new zones in the Panhandle. The zones targeted are the Hogshooter, Cottage Grove, Cleveland and another undisclosed Granite Wash zones for liquids-rich gas.

The third oil play is the Wolfcamp Shale that I'll elaborate on from our new ventures group and the acreage positions in Crockett County, Texas. We quietly amassed the position of 57,000 gross and 48,000 net acres per unit extensively. This position is primarily on 2 large contiguous private leases, which make it easy to hold and to drill the horizontal length of our choice. It's near competitor activity and includes the rights to deeper zones in both the Fusselman and Ellenberger that have produced out there, which are both secondary targets.

The Wolfcamp has a thickness across our lands, as J.C. mentioned, of about 700 feet, and we have currently cut a conventional core over that interval. We also have already obtained seismic over most of the acres. Our goal is to get 6 wells drilled this year, along with the cores and the micro seismic and the various science.

Our economics assumptions are similar to the competitors or the larger competitors in the area, where they have the same depths and shale thickness.

With the 5,000 to 7000-foot lateral, we have initial well costs, that's not our goal, but initial of $5 million to $7 million, $5 million for the 5,000-foot lateral and $7 million for the 7,000 lateral, with EURs ranging from around 300 to 400 MBOE, most of which is oil. The blocking nature of this acreage, like the Eagle Ford, allows for maximum optionality per lateral length. We only need a few wells to hold the land, in fact.

Our remaining 2011 CapEx guidance for the Forest U.S. portfolio of assets assumedly lead the Panhandle CapEx approximately the same at $150 million for the rest of the year, continue and increase the Eagle Ford spending by $120 million incrementally in 2011, add the new ventures Wolfcamp activity of $50 million and we've got $40 million for unspecified areas in East Texas late in the year.

East Texas, as we've said before, is more service-cost driven as costs come down as opposed to resource capture were all HBP there. Our goal with the remaining year's CapEx is to move forward some of the new potential liquids plays into production and reserves going into 2012. Remember, we will be primarily adding BOs, not just BOEs. Clearly the value of these acreage plays have been evident in recent Eagle Ford transactions near us and the Petrohawk transaction.

In terms of industry trends, obstacles or opportunities, overall, service costs have stabilized somewhat. And that's probably a shocking statement, but we have seen no increases in pumping services, which is the culprit for most of the cost increase this year, but it has not increased since the beginning of the year in terms of the prices paid. However, we have not seen decreases either in most areas with the exception being East Texas. Most of the savings have come from operator, from industry or mechanical efficiency, as J.C. referred to. Our big savings on the Eagle Ford frac stages that J.C. discussed comes from profit and design stages -- or design changes, not price books.

The biggest item for the industry from a cost standpoint is still the completion side, specifically, frac jobs. Early in 2011 guar polymer and new horsepower supply was a struggle. These 2 items, in our opinion, have been somewhat alleviated, certain type of coated or high-strength proppants are still an issue, as well as people are seeing high turnover with the people issues from the major pumping company personnel on the ground. So I'd say it's proppant and people that's the limiting factor.

New small-company entrants and Canadian fleets have helped somewhat. We have seen availability improve in East Texas but tighten in South Texas in the Panhandle. The rig in biggest demand is a 1,500-horsepower rig with the top drive capable of drilling most horizontal plays and, as you all know, we own some of those. We are trying out our 1,000-horsepower rigs, as J.C. talked about, in both the Eagle Ford, trying to get in the Eagle Ford for the first time, and Wolfcamp, which would provide savings but also a lot more rig options. Most of our activity in the Eagle Ford, Panhandle and Wolfcamp do not require high strength proppants due to the depths and lower closure stresses, so we have an advantage there.

We see trucking and we've contracted trucks, but we see trucking and water supplies, the issues going forward, particularly in the Eagle Ford. We have addressed both in our operations, including 2011 capital for the deeper water supply wells and disposal wells.

In a nutshell, current service cost in the industry are really reflecting oil economics and not gas economics. So we're being charged oil rates for gas wells, which is a bigger issue to us than gas prices themselves. However, we are seeing lower prices for conventional assets in terms of acquisitions and land prices in some areas. With the huge acreage positions that had been reported on these conference calls, acquired in some areas or in deals, top leasing in farm-ins are opportunities, particularly with Forest owning its own rigs.

So overall, we've got a large opportunity set to test, including mini zones we have not tested in the Panhandle. We seem to hear more zones out there every week or a new one a day. I'm asked when we finished -- when will we ever finish testing all the zones horizontally in the Panhandle and maybe in East Texas. And I've answered people, probably not my lifetime. But we will continue to focus on these, and the highest rate of return projects wins, no matter what the price.

Thanks for listening today and for your patience. Operator we are now ready for any questions.

Question-and-Answer Session

Operator

[Operator Instructions] You do have a question from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

So it sounds like you definitely feel good about the Eagle Ford in your -- you have a bias to upside in activity and a couple of things. One, are there any like logistical constraints if you ramped up activity in terms of getting some of the oil volumes out of there? And two, do you continue to look to bolt-on in additional acreage? I mean, what do you think you all can get up to in terms of size in the Eagle Ford in and around your own acreage?

H. Clark

Scott, let me see if I can answer them in order. In terms of the rig count, we're not in a development phase, as I would call it, because up to the point, I think the closest wells are 20 miles apart. So as we ramp up, it will be based on delineation success but also focused on lease capture because as we show on the pie graph, I think, on our road shows, we need to get after it before 2013 and '14 because that's when the bulk of the acreage explorations come. The logistical constraints, specifically with the certain services, but in this case, if you ask about getting the oil or liquids out of there, that has not been an issue, i.e. with the trucks. In fact, that's one of the advantages with an oil well, we don't have to mess with high-liquids gas, although we do sell some of it and burn it. But getting the oil truck down there has not been an issue.

Scott Hanold - RBC Capital Markets, LLC

What about adding acreage to your existing position? I mean, you have a pretty good size. Are you -- do you feel good about it right now? Or do you think you could add some more there?

H. Clark

Not significant. J.C. may want to comment. But clearly, we've been able to add some acreage, but the acreage we added was pretty much filling the holes in our doughnut that in some cases Marathon now has. But we filled in the holes pretty well so we can drill these longer laterals.

John Ridens

And to that end, Scott, I'd say that we're always still on the hunt to but the amount of bolt-on acreage that affects our position, it is limited at this point in time.

Scott Hanold - RBC Capital Markets, LLC

And in terms of like production, where it's turning right now, what are you all producing like in the Eagle Ford and the Granite Wash? I mean those obviously are 2 key areas for you going forward at least definitely in the next 6 months. Where are you running there now and where could those kind of get to by the end of the year?

H. Clark

Scott, we don't provide guidance or results on a play-specific. So we haven't disclosed that.

Operator

Your next question is from the line of Pearce Hammond with Simmons & Company.

Pearce Hammond - Simmons & Company International

Just curious if you could provide an update on the potential for an Eagle Ford JV.

John Ridens

At this point, Pearce, I would that we would still consider a JV if somebody came in with the right price. But having concluded a transaction at $10,000 per acre with the sale of Wilson County, I think that that's probably set some people back thinking about what price they'd be willing to pay because as Craig said, we said we have marked our market. I think that with the results that we're seeing, we're happy with the position we've got. And we would not be doing a joint venture other than for market cause.

H. Clark

Right, Pearce. And also I'd add, with $474 million of cash on the balance sheet in undrawn facility, we're not capital constrained so we have the ability to develop it ourselves.

Pearce Hammond - Simmons & Company International

Great. And then, would you ever consider a unit trust-type funding vehicle similar to someone -- some other producers have looked at in the Granite Wash?

H. Clark

Yes, we're looking at it. I mean, right now, I think the one that's being done, the population set of wells they put in has a level of certainty that we're trying to find in our own portfolio. And if we do find that, then we definitely entertain taking a look at that type of transaction.

Pearce Hammond - Simmons & Company International

Great. And then a final one, as we look at your liquids production, both oil and NGLs, it's about 6,500 a day in 2Q on oil and about 9,000 a day, and this is for Remainco, for 2Q, is this inflecting up as we proceed through second half of the year? And where do you think your exit rate might be?

H. Clark

Yes, I think we guided to 30% for the remainder. So I think every quarter, it ticks up a couple percentage points.

Pearce Hammond - Simmons & Company International

Do you care to take a stab at the year-end '12 exit rate?

H. Clark

No, I do not.

Operator

Your next question is from the line of Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Craig, are you flaring any gas in the Eagle Ford?

H. Clark

Yes, we are. It's not a lot, but we've had 3 options for our gas, and I think our best gas well -- associate gas was somewhere around 1 million a day. Of course, it's associated gas, so it's rich. In no way did that keep us from producing our oil. Number one, we used the gas for fuel, and we're even generating our own electricity on some sites for the pumping unit or the artificial lift and also for the gas-fired vessels heat. Number two, we have flared some. And number three, we have a midstreamer coming to pick that gas up, which will remove the liquids. And of course, any delay we had is because there's not a lot of infrastructure down there. And the other is, obviously, we've been drilling wells so far apart, it's probably not good for them to come up, pick up every little bitty well of gas. So as we start drilling more development wells, they'll come to us. But currently, that pipe is being for gassier wells.

Gil Yang - BofA Merrill Lynch

How much -- once you get to the point where you actually start developing or producing the gas, how much would that add to your EURs on an equivalent basis do you think?

John Ridens

It's not going to be a huge amount, Gil, because the property set that we've been developing has been in excess of 90% black oil. And so the gas is tail wagging the dog here.

H. Clark

We've seen some inconsistencies with the GOR, and I think people have coined it the volatile oil. But clearly, as you go down dip, you get more gas. We do have some acreage in the down dip areas on the gas condensate in the Wood County. It's HBP, so we haven't felt the need to get to that because we've really been drilling around the leases and around the seismic as opposed to trying to target gas condensate. But once we -- if we go down dip in those, you'll need a pipeline on those.

Gil Yang - BofA Merrill Lynch

Okay. And can you just remind me what the current Eagle Ford costs are and the EURs that you're thinking?

John Ridens

Yes, Gil, we've been running a type curve all along that's based on a 350 MBOE EUR. And our most recent wells have been AFE-ed for under $8 million.

H. Clark

We started -- Gil, this is Craig. We started on the wells and we drilled pilots as they are far apart. Even though we did have a seismic, we drilled pilots. We cored them, conventionally cored them in most cases. In fact, we long [ph] the lateral, and we've had one of the lightest wells got down for $7 million, but we're targeting somewhere in the $6 million, $6.5 million range based on the fracs coming around and also not doing all the science on all the offset wells.

John Ridens

The other thing I should note, Gil, is that in those AFEs, we've got approximately $0.5 million for tie-in to infrastructure when it gets laid, which will obviously be a future cost. But we are budgeting for that to reflect a full well stream economic.

H. Clark

And we are budgeting artificial lift and a battery on each one, specifically, either ESP on the half-load wells or pumping unit. We have not tried gas lift, which is popular with those because it's cheaper but doesn't provides for as efficient artificial lift. And then there has been some jet pumps, hydraulics pumps run, but we're targeting the more expensive artificial lift in that total.

Gil Yang - BofA Merrill Lynch

So the pumps actually get put into capital spending rather than operating costs?

H. Clark

That's correct.

Gil Yang - BofA Merrill Lynch

Okay. Just last question, just to clarify about your sales or your swap, if you will, of Eagle Ford acreage. Was it -- if I read it correctly, is it sort of an effort to divest non-operated and somewhat isolated acreage in Wilson County and the block up in Gonzales? Or was there any intent to high grade the acreage?

H. Clark

No, attempt to high grade. It was a non-op. It was the 50-50 wells we drilled first, I don't think it was any more or less prospected. But clearly, we weren't operating half of it. And secondly, it also marks the market on the value of the acreage because did receive some offers for acreage in general. So that's a good marker for us, although shortly thereafter, the Marathon/Hilcorp deal was announced which is a bigger marker.

Operator

Your next question is from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

In the Granite Wash, can you add a little more color around the deeper Atoka and Marmaton zone as you were drilling in the past, whether and when we should expect you to get back to drilling those zones and what commodity prices that would entail? And then maybe with that, add some color on when we should expect specific additional tests of 3 wells per section?

H. Clark

Well, I'll answer them in order, Brian. The Atoka, we still view as being challenged simply because the bulk of the Atoka is very dry gas and we don't see that as being economically viable at probably $6 gas. In terms of testing 3 zones or 3 wells per section rather, I think that's we have tested 3 wells per section in areas already, and we are monitoring other areas to see what the production trend over a longer period of time is because there's only so much gas in one of these sections, and if we can capture it with 2 instead for 3, that make sense but that will play out over time as we watch the longer term decline of these wells.

Brian Singer - Goldman Sachs Group Inc.

Got it. Okay, and then shifting to the Permian. Just really taking a step back, given that you'd sold some Permian properties a couple of years back, you've added Permian acreage here. Obviously, the acreage is in different places, but can you comment on what you're seeing and then perhaps just the horizontal potential that's gotten you back to the basin?

H. Clark

Sure, I'll answer that one. But first, remember, you asked about the Marmaton. The Marmaton is above the Granite Wash. So that's a Zone 2 test, not a Zone that [indiscernible]. And the Atoka, the economics as J.C. assumes, there's no co-mingling that goes on. Just simply, it's deeper and drier and, therefore, less liquids. In the Permian, we did sell our mature properties in the Permian, but we didn't get completely out is the short answer. I like it for 2 reasons. It's not just to get back in, obviously, clearly, more mature in terms of being drilled up, a lot more down spacing, but also the 2 things that has going for is there hasn't been a lot of horizontal wells drilled relative to the areas, particularly in the case of the Wolfcamp, which is thicker and it could even require more than one zone in it to drain. It's quite frankly, the second thickest only to Haynesville. And then in addition to that, service costs have not misbehaved as badly there because they were already there and the wells were shallower. So it's an attractive area from a margin standpoint. But clearly, if you're in Permian, you're probably chasing oil. It's the Permian. But you're also probably -- if you're going to be in there, you're probably chasing a new rock.

Brian Singer - Goldman Sachs Group Inc.

Got it. And if I could just add one more follow-up on the first question on the Granite Wash, with regards to oils that you are now testing, how long would you think it would take for you to have greater confidence about ultimate potential in the shallower zones and about the economics and how they stack up?

John Ridens

Well, Brian, now that we're drilling our first wells, and I might say that we got to get a statistically meaningful number of wells drilled, I can't base that on just 1 or 2 or 3 wells. So that's something that's going to continue to play out over time. But obviously, as we focus on these oil zones, just as you saw us do with the higher gas rate zones in the Granite Wash, even though there were still pretty liquids prolific, we looked at that over a period of time before really got ramping up on activity or discussing a lot of EUR potential. So I think that short answer, you're going to see that evolve over the next few quarters.

Operator

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

David Tameron - Wells Fargo Securities, LLC

A couple of questions and, Mike, you referred to with the cash on the balance sheet, any -- how should we be thinking about 2012 CapEx? If you can't give us a number, can you get us at least a ballpark outspending cash flow? Can you give us anything there?

Michael Kennedy

I would think about it as in and around cash flow.

David Tameron - Wells Fargo Securities, LLC

Okay.

H. Clark

Except for the new ventures, which is new generating activity, which to date has been mostly laying.

Michael Kennedy

Yes, I'm talking E&D capital.

H. Clark

Just E&D.

David Tameron - Wells Fargo Securities, LLC

All right. And there's a lot of questions about what the go forward for production rate and what a good rate to use as going forward given the transition? Craig, I realize you can't give us a production number or maybe you can, but can you give us any way we should be thinking about 2012? That seems to be one of the biggest issues surrounding the story right now.

H. Clark

Yes, the issues we guided pretty much flattish here, but we -- I mean, clearly, the issue that the growth would be at this point from the oil side. It's not BOE, just BOs. And clearly, the contribution would rely on the oil plays that we've discussed, including the Wolfcamp. That's why we're trying get that stuff out of the way sooner. We would look to let oil drive the growth all in liquids, but particularly the oil. And of course, as you ramp up in the Eagle Ford, it becomes a bigger player, but I mean, clearly, the growth is going to come on the oil side from the plays we've already assembled. And our goal with all this turning around with the land and the science is to get them ready to tee off in January without having to do what I would call the one-year technology delay like we had in the Haynesville and we had in the Eagle Ford. Right or wrong, we did Q3 seismic in the Eagle Ford. We were only 1 of 3 or 4 companies that have that, but get the technology out of the way so we can start the growth almost on the calendar.

David Tameron - Wells Fargo Securities, LLC

All right. And then one more, can you talk about -- I guess, given the fact that Eagle Ford is a an important component going forward, can you talk about how those wells are holding up? From what you've seen now that you've had -- I guess you don't have that much production history, but can you just talk about what they look like as compared to a type curve?

John Ridens

Yes, we've got wells that are above and below the type curve but, in aggregate, are on the type curve so far, Dave. As you said, we've got pretty short production histories on those, but that is something that we update continuously to see what the performance has been. And then also with the change in artificial lift, we look for what else we can do to boost recoveries there because we are seeing that these wells are maintaining in a high fluid level and in some cases flowing while pumping.

H. Clark

And, Dave, this is Craig. We have seen variations, not only by us, by industry in terms of the wells. I don't know if that's people staying in zone, the way they frac them or maybe even in some cases, the Austin Chalk is contributing. You have seen some water. But you're going to have to let the type curves play out a little bit because in several cases, the wells made more than they initially flowed on pump, per J.C.'s discussion of ESP, which makes the type curve look kind of weird because it starts out better -- less than it actually starts out. So you're going to have to see how they perform. Good thing about the pumps is they stabilize the rate pretty dramatically as opposed to the liquids plays, which may either have retrograde concerns or loading up concerns. Once you get them on pump and line them out, that's the reason we went with the type of pump we went, albeit expensive, so we can line them out and figure out the type curve by year end.

David Tameron - Wells Fargo Securities, LLC

Okay. All right. So I mean, obviously, there's some variability across the entire play?

H. Clark

Yes, I think that is for everybody, in the gas that we referred to. But the biggest issue is you got to -- I think 3 of our wells are still flowing in various degrees. You got to get them all pumped, you got to get them lined out. And it's just fluid, so it pumps pretty well.

David Tameron - Wells Fargo Securities, LLC

Yes, all right. I don't know you told us, but how many total wells do you have down in Eagle Ford now?

John Ridens

We got 6 wells that are currently on production and then we have 2 that are completing and 2 others that are in drilling.

H. Clark

I will tell you that they're drilling much faster than they used to. So because of that, we have to wait up. We've got our frac dates scheduled, so the faster we drill them, the more we wait. But we hopefully get the frac dates up. We're not under any take-or-pay contracts, so we can change frac companies. But they are drilling pretty quick. I think -- what was the quickest well, J.C.?

John Ridens

18 days out to a measured depth of about 11,500, 12,000 feet?

David Tameron - Wells Fargo Securities, LLC

Craig, so why is it drilling so much faster now? I mean...

H. Clark

We're getting better at it.

John Ridens

The first wells, Dave, we had vertical pilots and cores taken. And then on subsequent wells, we've been able to just go in there and drill right into the lateral sections, skipping that. And as Craig said, we've made some improvements in design and eliminated some intermediate casing. And the guys are doing a very, very good job of drilling those wells.

H. Clark

The biggest thing though is, other than to get better at it, Dave, and we hope to use a 1000-horse [horsepower] rig, which would be innovative. I don't think that's been tried. That's just for cost and availability, but the biggest thing is the 3D seismic, we can debate out. Then the issue is [ph] in terms of identifying the good spots, one thing it did help is to stay in zone. But on the first wells, we had to pilot, so we stayed in zone using the seismic, which is an art. And then once we got pretty good at that, we became more aggressive with our penetration rates. But we're still steering all the wells through our Internet system, I guess you could call it. But yes, we're steering all the well. But it gets easier to steer them as we can get more aggressive on the P rates.

Operator

Your next question is from the line of John Herrlin with Societe Generale.

John Herrlin - Societe Generale Cross Asset Research

Some quick ones. Craig, you mentioned that the Wolfcamp was pretty thick. How thick and do you have TOC or total organic content on it?

H. Clark

John, I'll have to get that for you. It fares pretty well. I have it from the competitor activity in the cuttings, the core is on the ground, so like reserve just when, I guess, I see the core. We took -- we cored the entire interval, it's 700-foot thick. It's one reason we selected it. It's uniformly thick. Over on the East side, it gets thinner and shallower, so there's a little difference of where we are, which is Petrohawk, Conoco, El Paso, EOG, and us. It's pretty uniformly thick. That's why we selected the land, but we cored the entire interval. I'm sure the TOC changes, but I don't know the number. I have to get it for you.

John Herrlin - Societe Generale Cross Asset Research

Okay, that's super. With the Eagle Ford, are you going to sand proppants rather than artificial ones? Or what are you doing there?

John Ridens

Yes, John, it's J.C. We've been using white sand on the latest tranche of wells. And we started off using some resin coated proppant. We have not gone to ceramic proppants. The resin coated was more than sufficient for closure stress at the depths we're treating. And so we went ahead and so that we can cut back and go even further to white sand. The only reason we were doing resin coated was it was all that was available at that time.

H. Clark

There is some high strength being pumped, John, in gas condensate winter window and the deeper, I just don't think we need it.

John Herrlin - Societe Generale Cross Asset Research

Got it. With the ESPs, how much do they run the actual pump itself?

H. Clark

For the first one, we've just got it on a rental basis, John, until we can see that this test is meaningful, and that we want to purchase the pump. So you can look for us to rent these on the initial installations.

John Ridens

They are $200,000 a piece.

John Herrlin - Societe Generale Cross Asset Research

Last one for me for me is on the Granite Wash. I mean, you mentioned that you were going for a different interval at different rates. Is there anything going on, one, structurally; two, diagenetically, to give you some of this variability?

H. Clark

Structurally, no. The central portion of the Granite Wash is shallower, so we've got a slightly lesser pressure. That's one driver. The second thing is you are getting more distill in the depositional environment and so the rock is a little bit tighter.

Operator

Our next question is from Howard Flinker [ph] with Flinker & Company.[ph]

Unknown Analyst -

Is that balance sheet in the release the Remainco or the combined entities?

H. Clark

We presented both ways. But at the end of the release, that is the combined. But we also presented that picture on Remainco and a total company basis.

Unknown Analyst -

In the release, you got it combined. I didn't see that. I just saw it now...

H. Clark

I thinks it's approximately Page 13 or 12 or 14.

Unknown Analyst -

Yes, the one I'm looking at is on Page 12, I think it is, or 13.

H. Clark

Yes, that would be a consolidated basis.

Operator

Your next question is from Jeff Robertson with Barclays.

Jeffrey Robertson - Barclays Capital

Craig, I apologize if you've mentioned this earlier, but can you all talk about how much of your Eagle Ford acreage has been delineated with the horizontal wells at this point?

H. Clark

Well, let's see. If we put 6 on production, we got 2 more completing, that's 8. And the spacing units for those with the -- probably, at most, I see a couple of hundred acres of well. But that didn't delineate, that's the spacing unit. But clearly, that would have delineated some leases where you could back and do development wells, including pad drilling. And of course, we've been skipping from lease to lease because of any explorations that might occur in the future years, but not much.

John Ridens

It would be less than 1%.

Jeffrey Robertson - Barclays Capital

Have you drilled around -- I mean, I guess the other question is in terms of distance between the wells, have you all drilled very far apart at this point to have control over your more of your roughly 113,000 acres?

John Ridens

No, Jeff, we're stepping out. But we started in kind of the west portion of our acreage and are gradually working our way east. As Craig said, when we first started our program, the first wells were 20 miles apart. Now, we're getting those down to 1 mile, 1.5 mile apart, but they're still not anywhere close to having delineated across the width of that position in Gonzales County.

H. Clark

Jeff, that's a little vague. But clearly, everybody's -- I think Marathon said 80 acres spacing. I think everybody's thinking that it won't that. I've heard between 100 and 160 acres. In fact, in Eagle, Wheeler, I think they're using between 100 and 120 acres. However, we've got some 5,000-acre leases, where there's not going to be one close it because that one well held it. However we have offset activity on the west and south edge, and we've offset on the South edge as well. So we've probably delineated more than just 200 acres per well. In fact, that would be turned or equal to 1 mile of 2 miles apart because that would be like a section, but we really have to spread them out for lease capture purposes only.

Jeffrey Robertson - Barclays Capital

There nobody to the north you, is there, Craig?

H. Clark

On the north, I'm not aware of any. There is actually some in the Chalk to the north. It's on the west, south and northeast and southeast, it's all sides but the very north.

Jeffrey Robertson - Barclays Capital

Okay.

H. Clark

The land is leased but there's not activity. And then if you look at our maps, they need to be updated. There are some holes in our doughnut, but we filled those in so we can drill the longer laterals and not have to bust up the unit. That is very attractive to blocky acreage. Really the blockiness of this in the Wolfcamp is a huge advantage. But here are still some holes and those holes, I guess, will now owned by Marathon.

Jeffrey Robertson - Barclays Capital

And, Craig, can you tell yet whether or not you're getting contributions from the Chalk?

H. Clark

No, I can't. In fact I am going to tell you based on -- starting in the bottom and moving up and down it, I would chance to say we've yet to get any contribution from that. My comments about industry is I think you may have that contribution already from out of the Chalk or the Buda, and that may explain some of the well variability other than the fact that people got out of the zones accidentally. We have not yet been in the Chalk though based on our steering.

Operator

Your next question is from Joe Magner with Macquarie Capital.

Joseph Magner - Macquarie Research

Just curious what the mix of Wheeler versus Hemphill County wells waiting on completion is at this point?

H. Clark

We'll get back to you on that, Joe. I don't have that handy.

Joseph Magner - Macquarie Research

Okay. Do you guys happen to have the breakdown of the sort of formations that were included in your inventory counts when you breakout south, central and north, which formations were included in each of those areas and sort of well spacing and any other detail you can provide?

John Ridens

I'll have to go back and get that information for you. I can't quote that off that top of my head. I will tell you, Joe, that at the time we probably had 4 or 5 different zones included in that inventory count. But I can't tell you for sure what that breakdown was, but you can call us back and we'll follow up.

H. Clark

Based on what we have tested, though, it was mostly Granite Wash and probably only about 2, 3, 4 of those. And then Atoka, which was us in the south, not the Atoka Wash, but the Atoka, and then we had a couple of Morrows in there to the North. Our convention, if we had a vertical there but no horizontal, we counted the location as a vertical offset. And we if had a horizontal, we count it as a horizontal. And we never ever got more than 3 wells per section in any of those counts.

Joseph Magner - Macquarie Research

Okay, I'll follow-up on that.

H. Clark

And the verticals were based on currently allowed regulatory spacing, we decided 20 or 40 depending on what zone you are in. But the verticals converting to the horizontals are because we drilled the horizontal and relieve the verticals or we found a new zone. None of these shallow old zones like Cleveland, Hogshooter, Cottage Grove are in those counties.

Joseph Magner - Macquarie Research

Okay. So is it, if I'm counting right, is it 6 different intervals that have been tested today horizontally with more to come? Or is it -- have others been tapped at this point?

H. Clark

That's about right, nothing uphold from us. I'm not counting industry, and then we had Atoka early on and Morrow. So it's probably 3 or 4 Granite Washes in those.

Joseph Magner - Macquarie Research

Can you remind me what your proved versus undeveloped reserve count in the Granite Wash was at the end of 2010? Do you guys have that or could you provide that breakdown?

John Ridens

I don't think we've provided that breakdown. I don't think we've provided PD versus PUD by area.

H. Clark

But we -- the Canada PUD percentages after, you can see that in the breakout for Long Pine. So pretty much most I've already said, except for South Texas, probably have the same PUD percentages as the company.

John Ridens

Yes, very similar to the corporate level.

Joseph Magner - Macquarie Research

But you didn't provide it.

H. Clark

No, we didn't provide it, but there's is one. It's not out of line.

Joseph Magner - Macquarie Research

Okay. And is there any potential impact to those reserve bookings in the Granite Wash with the shift to capital and reallocation away from that towards the Eagle Ford and Permian and other areas?

H. Clark

In terms of timing, you're talking about the 5-year rule?

Joseph Magner - Macquarie Research

Yes.

H. Clark

No, we don't have a whole lot on the 5-year rule because of our low PUD percentage. And we've -- I guess not most of the PUDs, but the existing PUDs, primarily are things like East Texas and the Panhandle, and we drill a few of those every year. They're a few but we drilled appropriate percentage year-over-year, so we've got them spread out over 5 years in our reserves.

Joseph Magner - Macquarie Research

Okay. And you touched on sort of difference in the geology in the Granite Wash, different parts of the play there. What's your understanding with all the wells you drilled of the oil, the shallower oil opportunities, and how those are situated across your acreage?

John Ridens

Well we've got oil potential going all the way down to Southern Wheeler up into Central Hemphill. So it's spread out over a pretty good geographic basis, actually, all the way up into the Lipscomb County for some of this. So we see a pretty good geographic spread. It will vary by area because, obviously, you're not going to see Cottage Grove, all the way up in Lipscomb. And you're not going to see Cleveland all the way down at Southeast Wheeler. But I think that we see it in a potential in all areas.

H. Clark

The main non-Granite Wash zones are going to be more prevalent in central and north, although we saw a nice Cottage Grove test in the south today. That's not too far from us and others. The biggest issue that we've had is obviously we do not test the shallower zones vertically. We tested the Granite Wash, co-mingled it with the Atoka early on. That served 2 purpose. We did co-mingle those and make economic vertical wells. And secondly, we held all our lands through the Morrow. If you're only drilling the Cleveland or the Marmaton zone or the whatever zone, you may have a play underneath you. So early on, we tested the bottom co-mingle opportunities vertically, co-mingled them and held our land at the same time. And now we got to test them both vertically and horizontal based on what we've seen.

Joseph Magner - Macquarie Research

Okay. And then when might we start to hear about some of those result? Any sort of time?

John Ridens

No timeframe, just your normal quarterly results.

Michael Kennedy

And make the shift in the second quarter, the shallow or early zones, at least with those rigs in the Panhandle?

Operator

[Operator Instructions] And you have a question from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

You stated at the top of the call 2 operated rig program in South Texas, that is in the Eagle Ford, with the bias for more activity. What are your thoughts about adding a third rig this year and the timing involved?

H. Clark

I said 2 rigs, I misspoke, in South Texas. That's actually 2 rigs in Eagle Ford. And we've had some activity in the Vicksburg off-and-on. But it's really, I'm talking, the Eagle Ford. And then you would start to ramp up into the 3 layer this year and then go to 4, 5 and 6. As you go to development phase, which is what the board wants to see, as well as you're heavily focused on your rig schedule and lease capture and so you don't get into a pinch in 2013, '14. But we've got the rig. In fact, we had the -- this is the same kind of rig if we're able to do this 1,000 horse rig, it's the same kind of rig that we're using in the Wolfcamp, so we'll have to wait using our rigs versus others. But the 1,000 horse will have a greater opportunity, that's why we're doing it so we can ramp up easily faster in both those plays as opposed to waiting in line for 1,500 because all of our 1,500s are being used by us in Panhandle and the Eagle Ford right now.

Dan McSpirit - BMO Capital Markets U.S.

Okay, and if you If you were to add a third rig this year to the Eagle Ford, how many wells would that mean? How many additional wells?

H. Clark

I don't think it -- if we do it late in the year, I don't think it would be that material. My hope is that I can do that with this 1,000 horsepower rig test, keep our fingers crossed and be able to pick up a rig on a moment's notice.

Dan McSpirit - BMO Capital Markets U.S.

Got it, Okay. Question #2 then, what does the leasehold under the new ventures group today total, that is leasehold that's with a location yet to be disclosed?

H. Clark

Well, I'm going to -- they report to me. So I'm going to try and get the tally the best I can. Of the acreage that we added this year, which is I think about 130,000 -- excuse me, 116,000 net acres, 126,000 gross, I believe 20 of that was Eagle Ford land.

John Ridens

I think that new ventures is currently about 85,000 acres in that.

Dan McSpirit - BMO Capital Markets U.S.

Okay. Okay, great. And then lastly, how common is the use...

H. Clark

Dan, I'm sorry, let me correct. I think the new ventures -- because I'm doing some rough math, I think they would be -- if you took mainly the Eagle Ford additions out and a little in the Panhandle, they would be roughly, year-to-date, 96,000 net acres. And half of that is in the Wolfcamp and the other half in [indiscernible].

Dan McSpirit - BMO Capital Markets U.S.

Got it. Okay, perfect. And then lastly here, how common is the use of an ESP in the Eagle Ford? And then the second part of that question, I guess, what are the expectations for additional recoveries, I guess, to justify the changes or the extra cost involved?

John Ridens

I don't think that the use of ESPs has been tried widely in the Eagle Ford to date, I think that we're probably in the second or third company that's tried that. I think that in terms of what the additional recoveries are going to be, it's too soon for me to predict that right now, Dan, because we've only had this well on ESP for about 10 days. So we don't have a long production history on it. Based on the initial rates that we're seeing, it about doubled the amount of oil that we were producing, so that's clearly going to pay for the installation of the ESP, as well as -- as Craig said, we're regenerating are own electricity on site. So, it isn't costing us any additional to run it.

Michael Kennedy

But, Dan, we have proven that we can move more fluid with it than we could even gas lift, like gassy gas we're using, our pumping unit. And when I say recovering fluid, I'm talking about the low waters well and we make a lot of fluid off those wells initially. And I don't know if maybe you're late and the lack of well but you need that kind of lift and you could change it out. But certainly, we've proven that it's higher fluid production per lift mechanism early in the life of the well.

Operator

Your next question is from Biju Perincheril with Jefferies.

Biju Perincheril - Jefferies & Company, Inc.

I don't know if you mentioned this already, but your total rig count in Texas Panhandle and can you break that down by how many you're targeting the various Granite Wash zones and how many are targeting the shallower oil zones?

H. Clark

I said, about 6 rigs and it's half and half, 3 rigs, the traditional and 3, the new oil zones.

Biju Perincheril - Jefferies & Company, Inc.

Okay. And off the 3 Granite Wash, are they now primarily in the central region?

H. Clark

That's a mix again between Wheeler and Hemphill County.

John Ridens

There are central ones.

Biju Perincheril - Jefferies & Company, Inc.

Okay. And help me understand, I think your horizontal locations you had given out was something like you still have 200-plus locations in the south, which clearly is superior. The rig count, running more rigs in the central location, is that sort of the main infrastructure constraint that you mentioned earlier? Or are you still delineating within the Granite Wash?

John Ridens

Certainly, a portion of it was the infrastructure issues that we described earlier. And the second thing is, last year we did a lot of delineation in the southern part. And we have said all along, we needed to get up to the northern part and do the delineation there as well.

Biju Perincheril - Jefferies & Company, Inc.

So do see that switching at some point? Or at what point do you think you will have the central region sort of delineated? And again, I'm just talking within the Granite Wash zones.

John Ridens

Well, we've only tested 2 intervals in the Granite Wash up in the central area. And so we have not tested that nearly as extensively as we have in the southern, so there's still delineation that needs to occur, both geographically as well as vertically in that central area.

H. Clark

We've tested it vertically for the most part, but that's 2 of the 7 zones apparently.

Biju Perincheril - Jefferies & Company, Inc.

So this is something that will go into 2012 as far as delineating -- and beyond. Okay. That's helpful.

Operator

At this time, I would like to turn the call back to Mr. Patrick Redmond for any closing remarks.

Patrick Redmond

Thank you. This concludes our earnings 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

Thank you. That does conclude today's conference call. You may now disconnect.

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