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Executives

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

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

Daniel Braziller

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

Gil Yang - BofA Merrill Lynch, Research Division

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

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

John P. Herrlin - Societe Generale Cross Asset Research

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

Joseph Patrick Magner - Macquarie Research

Jeffrey W. Robertson - Barclays Capital, Research Division

Forest Oil (FST) Q4 2011 Earnings Call February 22, 2012 2:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2011 Forest Oil Corporation Earnings Conference Call. My name is Derek, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I will now like to turn the conference over to Mr. Patrick Redmond, Vice President, Corporate Planning and Investor Relations. You may proceed.

Patrick J. Redmond

Thank you, and good afternoon. I want to thank you for participating in our fourth quarter and year-end 2011 earnings conference call. I will note that the replay of this conference call will be available through March 7, as discussed and 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 comparable financial measure calculated in accordance with GAAP, are available on our website and can be viewed by clicking the Investor Relations tab, then Non-GAAP at www.forestoil.com.

In addition, I'd like to caution you about our forward-looking statements. All statements other than statements of historical facts that address activities and outcomes that Forest expects, assumes, plans, believes, budgets, forecasts, projects, estimates, anticipates, et cetera about what will, should or may occur in the future are forward-looking statements. Please carefully review our cautionary language regarding forward-looking statements that is contained at the end of our press release.

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

Michael N. Kennedy

Thanks, Pat, and thanks to everyone joining us today. Let me first begin by saying that our remarks today relate only to the retained operations of Forest and exclude the operations of Lone Pine from the current and historical periods. We have accounted for Lone Pine during the year as discontinued ops in our financial statements. We also provided our results excluding Lone Pine from Q4 in comparable periods in this press release.

Fourth quarter 2011 production organically increased 6% to $342 million per day from the third quarter and fell within the upper end of our guidance range. Notably, the organic growth was mainly attributable to liquids production as we were able to increase liquids for the fourth quarter to approximately 17.3000 barrels a day, which is a sequential increase of 20% or over 2,800 barrels per day compared to the third quarter. We are able to achieve our goal of exiting 2011 with a production mix comprised of 30% liquids.

Adjusted net earnings came in at $20 million or $0.18 per share, with adjusted EBITDA of $139 million and adjusted cash flow of $104 million. Differentials for natural gas were $0.36 per Mcfe, and oil maintained a positive differential this quarter at $3.56 per barrel.

NGL pricing was approximately 43% of NYMEX. NGL pricing has softened recently due to the depressed FA price environment we are currently experiencing. However, our assumption of NGL pricing has generally been around 40% to 45% of WTI, so we're not surprised by the current pricing environment.

Production expense for the quarter came in at $1.29 per Mcfe due to additional water disposal cost associated with the oil development in the Texas Panhandle and the Eagle Ford Shale. We intend to address the incremental cost by drilling new water disposal wells in the early part of 2012.

Cash G&A cost remained in line at $12 million for the quarter, and total cash cost for the fourth quarter came in flat from the third quarter. Fourth quarter DD&A increased to $2.05 per Mcfe as a result of higher finding and development costs associated with our oil and liquid-focused projects.

Our E&D capital expenditures remained essentially flat in the fourth quarter to $178 million compared to Q3. For the year, we had E&D capital expenditures of $683 million with significant science capital to assist in the development of the Eagle Ford and Wolfcamp Shale plays, and those will not be replicated in 2012.

We invested $22 million in the fourth quarter and $205 million for the year on leasehold acquisitions of approximately 196,000 net acres in the Permian Basin, Eagle Ford Shale, Texas Panhandle and other prospective liquids areas. The significant amount of acreage we acquired in 2011 for $100,000 and $0.50 -- and $50 per acre bolsters our inventory of potential liquids drilling prospects and provides us with the portfolio to be successful in diverse commodity price environments. We don't anticipate any further material undeveloped leasehold acquisitions going forward in 2012.

Despite the additional capital we spent on science and leasehold acquisitions, our year-end net debt remained flat at $1.7 billion with only approximately $100 million borrowed on our $1.25 billion borrowing base credit facility. I know a lot of people will be monitoring the redetermination of borrowing bases this year due to lower natural gas prices. However, our liquidity of over $1 billion make this a nonissue with respect to Forest.

In light of the depressed natural gas environment, we added to our natural gas hedge position for 2012 and 2003 (sic) [2013], we added $50 million a day of swaps in the April to December 2012 time frame to cover off the downside of puts we sold in 2011. We also commenced our 2013 natural gas hedge program by entering $100 million a day of swaps at $4.02.

In addition to the natural gas swaps, we have 5,000 barrels per day of oil swapped at around $98 per barrel, and about 2,000 barrels per day of NGL swapped at around $45 per barrel for 2012.

In total, this represents approximately 41% of total production hedged in 2012 based on the midpoint of our production guidance at a price of $7.64 per Mcfe.

So to summarize the quarter, we saw sequential organic production growth of 6% achieved through the sequential organic liquids production growth of 20% in the fourth quarter. The liquids-sponsored growth should continue in 2012 as our capital program is designed around these areas in which we've had recent success.

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

John C. Ridens

Thanks, Mike. I'll begin today with the Texas Panhandle results. We had a successful quarter in terms of increasing our oil production in this area. Net oil production increased by 51% in the fourth quarter compared to the third quarter of 2011. This increase was driven by testing of new oil zones, particularly the Missourian Wash also known as the Hogshooter. In addition to the oil increase, we also increased net NGL production by 8%, bringing our total liquids production in the Panhandle to approximately 9,500 barrels per day at year end.

The Missourian Wash continues to deliver strong well results with 2 wells drilled since the last update we provided. Those 2 wells achieved average IPs of 2,700 barrels of oil per day. That is just the oil rate. Only one of these wells was included in the oil percentage increase I mentioned earlier, as the second well came on after the first of the year. Our first Missourian Wash well has cumulative production of over 150,000 barrels of oil in its first 135 days of production. An average of 1,100 barrels per day, and continues to flow at a rate of about 500 barrels per day currently. With a well cost of approximately $8 million, this well has already achieved payout.

A combined production from the 3 Missourian Wash wells currently is in excess of 4,000 barrels of oil per day. We will continue to run one rig dedicated to further develop this interval.

In addition to the Missourian Wash, we have also established oil pay in a new interval in the Granite Wash, outside of Hemphill and Wheeler counties. This well, which was completed right at the end of the year, had an IP of over 800 barrels of oil per day, about 500 barrels of NGLs per day and a gas rate of approximately 4 million cubic feet per day. The total liquids content of this well's initial production was 65%.

We are testing another member of the Wash in this general area, which we also expect will have higher oil content than we have seen previously.

Our base program in the Granite Wash continues to perform well also. We completed 5 wells for an average IP of 14 million cubic feet equivalent per day, with total liquids content of 52%. The Granite Wash A formation yielded 3 wells with average initial rates of 16.8 million cubic feet equivalent per day, of which 50% was liquids.

With the work done to date in this area, we have now tested or are testing, either on our own or in participation with another operator, a total of 14 intervals horizontally. We have 4 rigs running and plan to add a fifth shortly.

Infrastructure downtime has decreased since the last update, but still is not where it needs to be. Our target, of course, is to have no downtime, but we still incurred a volume impact of almost 4 million cubic feet equivalent per day of total production during the quarter. Certainly, this is an improvement over the previous quarters.

Another improvement seen in the Panhandle, as well as in East Texas and North Louisiana has been a significant reduction in completion cost, namely hydraulic fracturing. Frac costs have come down by roughly 20%, which has an immediate effect on the present value of a well in these areas. With approximately 50% of our capital program dedicated to the Panhandle, the decrease in fracturing cost is significant due the number of stages that we pump on each horizontal well.

The other major play we are pursuing is the Eagle Ford major oil play, and our effort of raising the lateral landing zones higher in Eagle Ford continues to yield improved results over our first-generation wells. Since our last release, we completed 3 additional wells with an average IP of 530 barrels of oil equivalent per day. We did have one well that suffered ineffective completion due to a poor cement job, which is the first occurrence of this in our horizontal program. Not only are the IPs meeting our type curves in these wells, in which we have raised the lateral landing target, but the longer-term performance is holding up as well.

The 2 completions we discussed on the last call that had average IPs of 750 barrels of oil per day averaged 260 barrels of oil per day during their first 4 months of production. The performance of these wells is on our type curve. The most sub-deep well drilled in the play has been our second best well to date from a cumulative production standpoint, recovering 40,000 barrels of oil in 4 months.

With a premium contract negotiated last quarter, we are receiving 50% of the LLS premium on this oil relative to WTI, which boosts the economics of this oil play. We are testing another oil currently, which has not reached its maximum production rate, but is already producing almost 600 barrels of oil per day while flowing up the casing. Let me remind you this rate is consistent with our type curve. We will provide the maximum rate achieved from this well in our next update.

We continue to work to optimize the fracture stimulation designed for the Eagle Ford wells using the microseismic data gathered after we raise the lateral landing target. We have been changing not only the rates of which to fracture pump, but also the sizes of the jobs as well to optimize our initial rates and ultimate recovery.

Moving to East Texas, we completed 2 liquids-rich Cotton Valley horizontal wells. These wells had an initial rate of over 450 barrels of liquids per day with approximately 30% of that being oil. The second well was especially rich, with total liquids of about 700 barrels per day.

An offset to the well is underway and we will continue to focus on this portion of the Cotton Valley given its liquids-rich nature.

We continue to have one rig in the Haynesville and have added 2 new wells since the last update. The wells had average restricted rate IPs of 10.5 million cubic feet per day. As I mentioned earlier, service costs are down in East Texas and North Louisiana, so we are seeing frac cost reduced significantly on both the Cotton Valley and Haynesville wells.

Further, the use of pad drilling in the Haynesville is another cost reduction. And the rig moving system that we used in the Haynesville can also be used in the Eagle Ford when we implement pad drilling there.

Moving to the Permian. We have completed one horizontal well in the Wolfcamp with an initial rate of 250 barrels of oil per day. A second well is slowing back after fracture stimulation. The third well has been drilled and will be frac-ed later this quarter.

As mentioned on the last call, we're also utilizing microseismic to monitor the fracture stimulation on these wells. Our microseismic and subsequent production logging shows that only 10 of our frac stages were effective on the first well, so we have room to improve on these results. Results from the microseismic program will be used to optimize frac design on future wells, and the vertical monitoring wells can then be used to test the zones other than the Wolfcamp vertically.

Lastly, our first well to be drilled on our new Wolfbone acreage in the Permian is slated to start drilling in the next month. We have accumulated over 114,000 net acres in the Wolfcamp and Wolfbone plays, and we're excited about the potential of these oil-rich targets.

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

H. Craig Clark

Okay, thanks, J.C., for the details on the fourth quarter and the full year. Lots of new plays in the last half of 2011, as J.C. mentioned, with a shift particularly in the oil plays in the U.S. Forest sort of reacted last half of 2011, particularly in terms of these new plays but more importantly, grassroots leasing. Since Mike covered the production operating cost, I will discuss our 2011 CapEx and reserves, our new ventures, and Eagle Ford initiatives, along with some comments regarding our 2012 plans since we previously issued our guidance in late 2011.

For the fourth quarter of 2011, CapEx we spent was $178 million, as Mike mentioned, for the quarter on E&D activity in line with guided amounts. We spent $683 million on E&D CapEx for all of 2011.

We drilled 127 gross wells in 2011 with a 97% success rate. The well count was dominated by horizontal activity with 110 horizontal wells and only 17 vertical wells. I should note that most of the vertical wells were related to our microseismic monitoring supply wells or conventional coal work in the Eagle Ford and Wolfcamp. I should note that the primary non-operated component in our 2011 program. And going forward, in 2012, we'll be in the Texas and Oklahoma Panhandle where we have working interest in about 30 non-operated wells in 2011.

We are certainly seeing a lot of competitor activity offset to us, so we must be doing something right. I also should mention that the contribution from the new oil zones and the East Texas program that J.C. highlighted came primarily in the fourth quarter, which accounts for the nice sequential production bump in liquids are all for the fourth quarter of 2011.

We saw quite a bit of service cost inflation in 2011. We included some of this inflation in our future development costs going forward. We originally thought 2012 would see higher costs than 2011 -- should be 2012 will be higher than '11. But as J.C. mentioned, we are seeing some relief in frac cost across our operating area. Originally, we assumed East Texas will be the only area which would see lower cost in 2012, and we're certainly seeing that in East Texas. So we may get some relief in mid-2012, even though we originally thought we would have to wait to 2013, particularly in the frac side. All cost savings outside East Texas in 2011 were solely due to our technique and efficiency improvements, not due to discounts received.

Our 2011 capital included $200 million on new lease acquisitions and approximately $50 million on what we've called science for the new oil plays, which includes: 3D seismic, microseismic conventional cores, rock mechanics, pilot holes, monitor wells, water supply wells, open hole and production logging in the horizontal lateral section. In other words, everything and the kitchen sink. This preparatory work is critical to our future development success, particularly in the shales and it is as attractive to future JV partners as the potential resource itself.

The fractured treatment design in lateral placement are logical, technical step progressions for all of our plays and are directly related to the improvement in the Eagle Ford and even in the new Panhandle oil completions where we recently modified our frac designs there as well.

The same steps will be added to the Wolfcamp and then eventually, the Wolfbone which are in their infancy.

As I mentioned earlier, our 2011 capital included approximately $200 million of land leasing. This was the company's best year in terms of grassroots leasing by far and is a testament to our new ventures initiative.

We added 236,000 gross acres or 196,000 net acres in an attractive $1,050 per net acre average price. The acreage is broken down as follows: 7,500 net acres in the Panhandle; 24,000 net acres in the Eagle Ford, mainly to fill in holes; 88,500 net acres in the Wolfpack or Wolfbone Wolfcamp in 2011 only, I should note; 76,000 acres remain for the other new ventures undisclosed plays, that brings the total to 196,000 net acres for 2011.

All of these are black hole plays, and we are even starting to see a play-on-play concept developing like in the Panhandle and the Permian Basin with the multi-objectives. We chose this path as opposed to bidding for other's sellers data room locations at a much higher per average acre price in these same basins.

Our 2011 proven reserve grew by 2% from last year's to roughly 1.9 Tcfe. Our percentage of liquids to gas reserves increased from 20% to 24% in 2011, as 52% of the reserves booked in 2011 were from liquid or crude, although we've yet to book significant reserves from our new oil plays from new ventures in the Eagle Ford.

Our 12-month average price used in our SEC database was $4.12 for natural gas, and $96.08 for WTI crude oil. We added 301 Bcfe in extensions and discoveries or 148% reserve replacement at an all-sources F&D of $3.77 per Mcfe. Since it was mostly all -- equates to $22.60 per BOE finding cost on an oil conversion.

Without considering revisions, our drill bit replacement was 247% at an F&D cost of 227 per Mcfe when it convert to all $13.60 per BOE. There were minimal divestitures in 2011 and no producing property acquisitions.

Our PUD percentage grew slightly and would've remained essentially the same as last year, except for the reclassification of Italy [ph] from PDNP to PUD even though the wells are drilled, completed and tested. The revisions totaled 120 Bcfe and these are broken out in our release, and are primarily due to 47 Bcfe for the 5-year PUD rule on primarily vertical gas wells in East Texas. 23 Bcfe was due to a gas well and mechanical problems in South Louisiana that we've chosen not to redrill. A 50 Bcfe remainder was due to performance and converting vertical locations to horizontal locations. As a reminder from last year, when we drop a vertical location that is replaced by horizontal well, we take the revision for the vertical at that time.

We had minimal price revisions for the year, although increasing well cost and therefore, future development cost caused a few vertical gas locations to fall out. We may get some future help from our previous comments on the development cost side, as the aforementioned cost trends hold true. This affected our DD&A rate for the quarter as well.

So our 2012 plan is simply to exploit the plays that will result from the successful test that J.C. covered this quarter and last quarter. All but one rig is devoted to liquids or crude-related activity. Our Panhandle asset is a common anomaly in terms of the liquids curing in the economics, even though we get material gas volumes along with the crude or condensate.

We're using $4 gas, now flat, and $90 WTI oil price flat in our planned pricing going forward. There is minimal production contribution for the new ventures initiatives in our guidance, even though we're moving forward with tests in the Wolfcamp and now the Wolfbone. The capital associated with our tests, including our new Wolfbone acreage was already included in the capital guidance.

The Eagle Ford data room process continues to go on schedule and is active. Low natural gas prices have made oil prospects more desirable across the board and the oil window of the Eagle Ford is no exception. Based on EOGs and others' announcements, Gonzales County seems to be one of the best producing oil parts of the trend thus far.

Our Gonzales land position was made more blocky, if I can use that word, with the addition of 24,000 net acres in 2011 to attempt -- solely to attempt to fill in the holes in our holdings to add potential horizontal locations. In others words, we can drill horizontals unabated. The land we released in Lee County was not contiguous and is not part of the JV process. Our last few wells cost around $6 million, no science to drill and complete. And that's before we employed pad drilling, which is take us down hopefully to around $5.5 million.

It looks like we've settled on a target completion in the Eagle Ford after all the science we did in 2011 and a little bit in 2010. As J.C. discussed in his comments, the initial production rates are in line at 600 barrels a day with our assumptions and our past statements across the large acreage block in Gonzales County. With the lower cost and virtually all premium price crude coming from this completion, this area may have a better returns than even the deeper higher cost gas condensate area of the trend. I keep reminding our business units and new ventures that finding a 600-barrel a day oil well is like making a $25 million a day gas well in today's commodity price environment.

Now to new ventures. In terms of their activity, they added 190,000 net acres, including the Wolfbone we added last week. They doubled the amount of acreage in the original plan. Great job here. All of the capital was spent prior to 2011. So the acreage purchase last week, all the capital announced in the Wolfbone was spent -- the capital part in 2011. So our guidance does not change for that regard.

Most notable is 126,000 gross acres, 115,000 net acres in the Permian Basin Wolfcamp and Wolfbone play. I already started calling this thing the Wolfpack since there are so many names with the word wolf these days. I should note that these are all big ranches that have been held by our drilling thus far or have 3- to 5-year primary term leases, so as to not overlap our Eagle Ford land explorations. That was our plan. We have excess to all depths on these leases, which is good considering we have additional objectives in both basins, the Delaware and the Midland, specifically in the Delaware Basin stack pays in the Bone Springs and Wolfcamp. But more importantly, we have the Delaware Sands, Avalon Shale and lower Wolfcamp to add to this.

We've seen the third pretty well as company when we have multi-pay objectives like the Texas Panhandle. Let me emphasize that our assumptions in the Wolfbone are based on a vertical well co-mingled Wolfcamp and Bone Springs Sands with 5 to 6 frac stages. That's it. The Wolfcamp, Avalon, Bone Springs, Delaware Sands are potential -- have not been considered at this time. The other zones.

The recent test on our first Wolfcamp horizontal was certainly influenced by the number of frac stages, but is a logical first step so that we can obtain the microseismic pulses. The second and third completions in the Wolfcamp are designed for 15 to 20 frac stages.

Please note that even though we have seen some Sprayberry dean sand above the Wolfcamp and call someone on Ellenburg zones, as well on our vertical pilot well logs, remember the monitor wells were drillers put vertical producers. The Wolfcamp Shale is our primary objective at a projected 700-foot thickness, I guess, may have multiple lateral targets to evaluate in the Wolfcamp alone. We are encouraged by our first well out issued.

So in closing, let's tally up the play counts that we plan to test during the summer of 2011, and we were ahead of schedule. In the Panhandle and Missourian Wash, oil play, check the box. Cleveland, oil play, check the box. Two more Granite Wash, liquid zones, check the box. Two more that J.C. has alluded to in the Panhandle that we've tested oil in, check that box. Prior to 2011, Forest themselves operated as first mover in the horizontal portion of this play, tested 5 zones by itself, mostly in the Granite Wash.

We originally projected 4 horizontal zone tests in the last half of 2011. But we ended up with 6 more, bringing our total to 11 different horizontally tested intervals by us, as an operator, alone. J.C. referred to 3 more, which brings it to 14 and those are in non-operated wells we have an interest in.

We now see 16 potential targets in the Panhandle based on our vertical work and work of offset operators. It is clear from recent transactions announced in the Panhandle that we have a lot more to count in terms of zones and potential locations on our Panhandle asset base.

These intervals and the inventory, along with our Eagle Ford, Wolfpack and even East Texas offer excellent prospects for future organic growth. Specifically, our inventory that has to do with future oil growth for many years to come.

Thanks for listening, and for waiting on our science work to deliver. Operator, or Derek, we're now ready to take questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will be coming from the line of Anne Cameron from BNP Paribas.

Daniel Braziller

This is Dan Braziller for Anne. I was wondering if you could provide an update on the Cleveland play. I didn't see anything in your release?

John C. Ridens

Yes, sure Dan. We have drilled 4 Cleveland wells, I think now, and we have been achieving good IPs. The longer-term performance of a couple of the wells has been not as strong as our type curve had projected. So we continue to run one operated rig and one OBO rig, further delineating that play. But with the addition of the new oil zones that we're finding, we may be shifting that Cleveland rig over to test some other zones because they're coming in at higher rates than were projected even on to the Cleveland type curve.

[

:p id="A15" name="Daniel Braziller" type="A" />

Got it. And then...

H. Craig Clark

I'm sorry, Dan, this is Craig. We should note that the non-operated rig is not insignificant in the case of the non-op well we have between 60 and 70 [ph] reached an interest in that well.

Daniel Braziller

Okay. And then on your negative 50 -- your 50 Bcfe reserve revision, how much of that was the Granite Wash? Can you tell us that?

H. Craig Clark

Well, I don't know how much it was across the company, but it wasn't concentrated in one area. And a lot of it had to do from when we drill a vertical and -- excuse me, drill a horizontal and relive the vertical. That mostly was the Granite Wash because that's where most of the horizontal wells were drilling in 2011.

Daniel Braziller

Okay. So we should still be using the type curve, the central and south fairway type curves for that play?

H. Craig Clark

Yes, for a typical Granite Wash, that's true.

Operator

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

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

Craig, kind of a tough question. But what is the -- for the Eagle Ford JV or potential Eagle Ford JV, what is the sort of dollar per acre price at which you wouldn't do a JV? What -- in your mind, kind of what that's bottom level or the minimum amount of value that you want to achieve to go forward with the JV?

H. Craig Clark

With my attorney sitting to my left, I can't answer that. I'll let the comps and the activity down there stand for themselves. And I really don't know that number myself, but I shouldn't talk about any numbers because there's no certainty you'll get one done. I just can confirm the data room is open and active.

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

And then, Michael, you mentioned the bank redetermination. You expressed that you didn't think that, that was not big a deal. Can you provide a little more color as to why that might be the case, especially as they've put in a lower gas price day?

Michael N. Kennedy

Yes, it's not a big deal because we've only got $100 million drawn on it, Pearce, and we're close to cash flow and CapEx for 2012. And also, we paid down some senior notes in December of '11, which also helps you. So for Forest, it's just not going to be really any issue at all.

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

Great. And then lastly, tremendous success with the Hogshooter wells. How should we think about the total number of locations there?

John C. Ridens

Pearce, I think that on the last call, we referenced a potential location count for that, somewhere in the 30 range. And certainly, what we're seeing so far is with the first 3 wells drilled and completed, there is no reason for us to change that at this point in time.

Operator

Your next question would come from the line of Gil Yang from Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

Mike, just to follow-up on that liquidity question. I understand you're saying that there shouldn't be an issue. But does that imply that you expect the borrowing base to be not changed? Or if it’s changed downward, that it wouldn't create any significant liquidity crunch?

Michael N. Kennedy

Yes, I mean, obviously I can't control it. It's up to the banks for the actual redetermination. And with the lower gas prices, I'm assuming across the board people have slight borrowing base reductions. But I'm really just saying, it's not an issue for us because we have so much liquidity and so much cushion underneath -- within the borrowing base.

H. Craig Clark

And when we retired the term debt that matured in December, we did not opt to take the mathematical upsize on that bank facility. We opted out.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So there was a little bit of a headroom that you didn't put on to the borrowing base?

Michael N. Kennedy

Yes, we left at 1.250, left at flat for quite some time.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, great. And could you, Craig, you mentioned Wolfcamp was encouraging on the buy side, maybe I missed it, but could you just comment on what you've seen there for the first -- I know you drilled one well and have slowed it, but I think you have a second well down and maybe slowed it. Could you just give us an idea of what you've seen?

H. Craig Clark

The first well we frac-ed it 10 out of 14 times. Didn't want to get too many fracs going because we determined that from our microseismic endeavors in the Eagle Ford, that we if we get too far away from it, we can't see the points anyway. So we didn't opt to go to 25 fracs rather to shoot, even though other competitors, at least, one is doing that many. Tangible disappointing, but the frac hurt. The rate per stage seems to be consistent with competitors. The biggest issue in that play, in my personal opinion, will be since it is so thick and we did core 700 foot of Wolfcamp, is which zone to target. And as usual, we started at the bottom. The second well will be frac-ed, I believe -- is frac-ed -- what is holding back the second well was, I think, 15 stages. So we're going to go 15 to 20 stages on these next 2. And we're monitoring those microseismically as well.

Gil Yang - BofA Merrill Lynch, Research Division

You said the rate was comparable per stage, what are those rates?

H. Craig Clark

I believe we've seen from competitor, and I don't have all the information because only the public lands in this play. Only the University of Texas public lands have the database that's out there. But we see 20 to 30 barrels per day, per stage. Not per lateral, because there's some big and long and short laterals. It seems to be that the per stage number is consistent. Although I can't comment about strict competitor fracs themselves other than the per stages itself because that's all they report.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, great. And could you just also comment on the type curves, just remind us what the type curve that you're shooting for in the Eagle Ford that you said that those wells fall?

John C. Ridens

Yes, Gil, it's J.C. Our type curve is based on an initial production rate of about 500 barrels of oil per day with a EUR of approximately 300,000 barrels of oil. Of course, there'll be some gas and NGLs with that. So that would equate to a 350-MBoe type curve.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And you're saying that just those -- the 2 wells that produce 600 on average were on the type curve or were all 3 of those wells on the type curve?

John C. Ridens

No, I was referencing the 2 wells that we have the longest production data on in order to ensure that we could quote something that had months of type curve data rather than weeks or a month of type curve data.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So the first one -- one of those is the 9 -- the one that IP-ed at 951 in November, right?

John C. Ridens

Right.

Gil Yang - BofA Merrill Lynch, Research Division

And which is the second well?

John C. Ridens

The second well was the one that we talked about on the call last time as well. And the combined average IP of those 2 wells was 750 barrels of oil per day as an instantaneous, not monthly production rate.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Can you comment on the other wells that you’ve started to produce in the quarter, how -- whether or not those are fitting the type curve?

John C. Ridens

Yes, we've got one well that's testing right now at 600 barrels a day, flowing up the casing. So it has not reached its maximum rate yet. It has only been on production for a few days. And we will give the maximum rate achieved on that on the next update. But so far, looks good.

Operator

Your next question will be coming from the line of Michael Hall from Robert W. Baird.

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

I guess, just on the Eagle Ford JV, I'm curious in terms of when -- how long are you going to keep that open? And when do you think you'll close that process?

H. Craig Clark

We -- well, obviously, with the interest we've got, we'll be doing it for a while longer. But we've said in terms of trying to wrap it up, when we first announced it, would be a second quarter event. We'll act [ph] later and obviously close before this, so people can have time to be it. But -- so it started in January and it still remains active.

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

Okay. So that's still the plan, by end of the second quarter?

H. Craig Clark

Yes.

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

Okay. And I was just curious, how many additional wells are you looking to have, I guess, within the data room to help set around that type curve during that time frame?

H. Craig Clark

I'll emphasize because there's been some confusion with the type curve and I don't know why, but the wells in the type curve -- because there were wells better than worse than type curve previously, but the last batch of wells with the lower cost, the new frac targeting the middle to the upper of the type curve and are hitting that. And we'll continue to stay across the acreage, not just in one spot, with that rig and I think you add a well a month.

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

A well a month. Okay. And then I'm curious on just moving up to the Panhandle on those Hogshooter wells, any indications or thoughts around EUR at this point? And also curious if you're seeing kind of variation in the liquid splits over time or are they remaining pretty constant?

John C. Ridens

Our type curve for the Hogshooter wells was based on 350,000 barrels of oil. And we have not revised that since we only have 3 wells that are currently on production. But I would remind you that one of those wells has already reached half of that type curve EUR in a short period of time. Liquids rates had been amazingly consistent on that, with about 75% of the total productivity of those wells being in oil.

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

Okay. And then last one for me, I'm just curious on LOE. I'm thinking about that it sounds like maybe some improvement with some water disposal wells, kind of what's the timing on that? How should I think about maybe per-unit LOE throughout the course of the year?

H. Craig Clark

Well we -- other than sometimes we get some seasonal but we do pretty good on LOE, leaving our guidance the same. The not saltwater, but frac water disposal really impacted us in the Panhandle. We've done several disposal wells there. And part of that frac cost water disposal increase has been because of the increased water from particularly the Mississippian. So we've done our own disposal wells. Some of which will be done last year and this year in the Panhandle that should remedy that. Same way in the Eagle Ford, which is obviously a very active play. We'll do -- if disposal wells are there for us this year, which should lower our costs. We've only done supply wells, just now getting to the disposal wells. So we're leaving our guidance on cost the same.

Operator

[Operator Instructions] Your next question will be coming from the line of Biju Perincheril from Jefferies & Company.

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

Couple of questions. In East Texas, given the success that you're having in Texas Panhandle, is there any thought given to moving either the Haynesville or the Cotton Valley rig to Panhandle?

H. Craig Clark

No. Well, the first thing on the East Texas rig because somebody I saw think had it confused that we have 2 Haynesville rig. That's not correct. The East Texas, we're looking for liquids, taking advantage of the cost, trying to have a portfolio. We're not going to concentrate all the rigs in the Panhandle because that hurt us a little bit, particularly with the infrastructure early in 2011. So spread it out. The East Texas rig, no. If you can't get the Haynesville cost down, that rig's a candidate. And also, depending on the outcome of the Eagle Ford JV, we have access to both of those rigs to move in, depending upon what the partner and us agree with, if we get that JV consummated.

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

Okay. And then on the Eagle Ford, the plan is still keep one rig until you have a JV completed?

H. Craig Clark

Yes, there's actually more than that down there now. As a remainder, we have 15 rigs. But one's drilling -- one's drilling a disposable well for someone else, hence the disposal comment I made earlier. And the other rig is being used as a workover rig currently. Getting the rigs to move down there and the advantage that we would have with a partner, if that's happened, would be to take advantage of our fleet and redeploy the rigs, particularly from East Texas.

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

And I missed it, if you mentioned earlier, the latest well in Haynesville, what was the cost on that?

Michael N. Kennedy

Those well costs on Haynesville are under $10 million. We're running about $9.5 million. And I think that we can gain another $0.5 million or so from the higher discounts that we're seeing with fracture services. So we're shooting to get them down to about $9 million before we implement pad drilling.

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

Okay. And at those cost, what gas price do you want to see to keep that rig there?

Michael N. Kennedy

Well, at the current strip and running the $9 million gas price, we are still in double-digit rates of return. So as long as we're seeing that, and looking for further improvements with pad drilling, I think that will -- our intent is to keep the rig there. If we saw gas prices continue to soften, obviously, we would rethink that.

H. Craig Clark

But we're running $4 on the gas price, that's not the breakeven, that's what we're running flat. And secondly, we anticipate a well cost reduction. As J.C. discussed, if we don't see that, we'll move the rig.

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

Got it. And then one last question on the Hogshooter, obviously, you have a very nice strike there. So when you look at your 30-well inventory, are these sort of your average you would expect from that or are these to the -- some of your better wells or do you think there will be even better areas there?

Michael N. Kennedy

Well, I would say that we have started off in an area that we obviously think is going to be one of the better areas. There are multiple benches of the Hogshooter, so we will be testing additional benches, not just one. The variability of those other benches could be as good as what we've seen now are the productivity or they could be less. We won't know until we get in and get some of those tests done. I think one of the things that we're really encouraged about is frankly that there are multiple benches here because every time that we have seen a multiple bench pay, it just yields further opportunities for us to get in and apply the tricks of the trade and see how we can do with them.

H. Craig Clark

And those are not in our zone count that J.C. and I saw put up earlier. Secondly, our location camp that J.C. quoted on the last call is around the location in the same bench that we talked about in the third quarter. Clearly, with the recent transaction in the Texas Panhandle of the size and the number of locations quoted, we need to expand our location count and opportunity set.

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

Okay. And those -- and these 3 wells you've drilled so far, are they all on the same bench or do you test at different benches?

John C. Ridens

Two of them are in the same bench. Another well was in a different bench.

Operator

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

John P. Herrlin - Societe Generale Cross Asset Research

Two quick ones. For your budget this year, how much of it is geared towards lease retention, Craig?

H. Craig Clark

I believe it's about $20 million, John, when I say -- you talking about extensions or new acreage?

John P. Herrlin - Societe Generale Cross Asset Research

Yes.

H. Craig Clark

It's $20 million.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me, what was your ceiling test cushion this quarter?

Michael N. Kennedy

$750 million.

Operator

Your next question will come from the line of Andrew Coleman from Raymond James.

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

I had a question for you on looking at, I guess, guidance for production for the year, so at 70% natural gas, 15% for oil and NGLs. That's relatively similar to, I guess, what you guys had put out early last year. What sort of, I guess, upside for that -- those liquids numbers have as you continue to drill on in primary liquids plays this year?

Michael N. Kennedy

Andrew, this is Mike. Right now, we're obviously sticking with the same guidance. If we have continued success in these oil plays, maybe we'll revise it. But right now, that's our best estimate.

H. Craig Clark

And for the fourth quarter, Andrew, the zones in the Panhandle are clearly knocking our type curves out of the water into our assumptions in the Panhandle, which leads to that in for new ventures, the output minimal or no contribution in there from their activity, particularly in the Wolfpack.

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

Okay. And then from a modeling standpoint, I guess, how should we be thinking about, I guess, modeling the water cut for these, I guess, Permian and I guess, Panhandle wells? And I guess, what would be the split between the frac flowback and just regular in situ water being produced?

John C. Ridens

Andrew, it's highly variable on the Panhandle because in the traditional Granite Wash, we've always produced some formation water. But the biggest thing that we look at is with the volumes of water that we use for hydraulic fracturing treatment. If we're pumping 100,000 barrels of water, the biggest component that we are going to see coming back from that treatment is recovery of the frac load water. And that's why we want to implement additional saltwater disposal wells to handle that big, initial surge of water and get it disposed off in the most cost-effective manner. Because if we are in a remote area -- remote area meaning that we are 10 miles away from our nearest saltwater disposal well, we could be looking at $3.50 of disposal cost because of primarily trucking. That's the big reason that we're pushing to put some additional saltwater disposal wells in right now and limit the distance that, that water has to be trucked. In terms of the oil zones, time will tell. But right now, we are not seeing in the Panhandle a significant amount of water being produced with the oil. It has been more out of our traditional Granite Wash program where we've seen water.

Operator

Your next question will come from the line of Joe Magner from Macquarie.

Joseph Patrick Magner - Macquarie Research

Sorry if I missed this, but the expiration of 15,000 acres in Lee County, can you run through what kind of expiration exposure you have in Gonzales and Wilson this year and over the next couple of years?

H. Craig Clark

I believe we put that down on our roadshow slide, but most of the acreage expirations are in '13, '14 and '15. I think, at this point, we're in pretty good shape for '12 actually. And of course, we held the '11 acreage is not contiguous. It's way up north. It is not part of that big blocky land, so we pretty much traded -- the land that's north of us for the blocks that we purchased to fill in the holes in the land because of the horizontal opportunities. So our net acreage went up a little bit throughout the year. But our acreage at the block that's in the data room, which that Gonzales County blob, if I can call it that, is right at 100,000 acres. And that's the acreage expirations I've referred to and the topic of our JV data room.

Joseph Patrick Magner - Macquarie Research

And I guess with only one rig running now, what would drilling activity has to pick up to in order to keep that block together?

H. Craig Clark

If we get to 5 rigs sometime this year.

Operator

Your next question will come from the line from Jeff Robertson from Barclays Capital.

Jeffrey W. Robertson - Barclays Capital, Research Division

Craig, I apologize if I missed this, but can you -- you talked about acreages and new plays, can you talk a little bit about the plans to test that and as part of this year's capital program? And also, the flexibility to accelerate in the Wolfbone and Wolfcamp if you decide the results warrant?

H. Craig Clark

Okay. The acreage expiration and some people ask about that in the release, they are 3- to 5-year leases, most of them under General Land Office format in Texas, although they are not public lands nor lands from the University. You hold them with -- basically we're held on the Delaware Basin side already after the piloting term. The commitments are basically 2 wells a year. So they're minimum commitments. So we don't have any expirations occurring. We have the flexibility to move back and forth from the Wolfcamp to the Wolfbone. Our budget included money and therefore, the Wolfbone and Wolfcamp in 2012, so we'll be testing that following the Wolfcamp. And also the other new ventures land that I have yet to disclose had some capital in it. So basically our capital guidance remains the same. Flexibility to move rigs in and out since we have lantern drilling headquartered in Midland. We have rigs for the Wolfbone almost at will because of those rigs are still there if they are not being rented to other folks. And of course, we could shift rigs at round. That's the advantage of having the rigs without having a term contract. But right now, it's the same 1,000-horse rig that's going to the Wolfbone that just finished with the Wolfcamp. As we've explained to you and others, the 1,000-horse rig or smaller is available. It's the 1,500-horse rigs that we used in the Panhandle and to a lesser extent in the Eagle Ford better scarce. So we protect those rigs in those plays and shift the 1,000 horses around.

Jeffrey W. Robertson - Barclays Capital, Research Division

To follow up, in terms of the new acreage, I think Mike said that you all don't anticipate any big leasing dollars in the 2012 spending. But -- so when do you think you'll have -- you'll be able to talk about where those plays are and any kind of results?

H. Craig Clark

Yes. Well, we get $20 million in there, the bench for the previous color for extension/new leases, the other plays would be -- would finish getting some acreage. Our goal in the play is to have 80,000 to 100,000 acres in each play. So it's material to us and a lease schedule that we can hold it due to use of the size of the lease or the lease terms. It'll be some time this year.

Operator

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

Patrick J. Redmond

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

Operator

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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