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Forest Oil Corp. (NYSE:FST)

Q3 2009 Earnings Call

November 3, 2009 2:00 pm ET

Executives

Craig Clark - President & Chief Executive Officer

Dave Keyte - Executive Vice President & Chief Financial Officer

J.C. Ridens - Executive Vice President & Chief Operating Officer

Patrick Redmond - Director of Investor Relations

Analysts

Dave Kistler - Simmons and Company

David Tameron - Wells Fargo

Brian Singer - Goldman Sachs

Brian Singer - Goldman Sachs

Jeff Robertson - Barclays

Scott Hanold - RBC Capitals Markets

Joe Magnor - MacQuarie

Andrew Coleman - UBS

Operator

Good afternoon ladies and gentlemen. My name is Tina and I will be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Corp.’s third quarter 2009 earnings conference call. (Operator Instructions). Mr. Redmond, you may begin.

Patrick Redmond

Thank you. Good afternoon. I want to thank you for participating in our third quarter 2009 earnings conference call. I will also note that the replay of this conference call will be available through November 17, as described in our press release issued yesterday. We have joining us today, Craig Clark, President and CEO; Dave Keyte, Executive Vice President & CFO; and J.C. Ridens, Executive Vice President and COO.

Some of the presenters today will reference certain non-GAAP financial measures, regularly used by Forest in measuring its financial performance. Reconciliations of such non-GAAP financial measures with the most comparable financial measures calculated in accordance with GAAP are available on our website and can be viewed by clicking the Investor Relation’s tab, then non-GAAP at www.forestoil.com.

In addition, I would 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 etc. 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 Dave Keyte. Thank you.

David Keyte

Thanks Pat, and welcome from Denver where we still snow on the ground from last week’s storm, we certainly have winter here in the Rockies. We appreciate your attention on a very busy earnings call day. The third quarter results were slightly under our expectations due primarily to shut in volumes caused by third party midstream issues. Cost containment continued to positively drive margins and predicted gas differentials improved once again.

Lower costs and tighter differentials kept EBITDA and discretionary cash flow virtually flat sequentially despite lower sales volumes. As Craig and J.C will get into later very positive drilling results should provide organic growth beginning in the fourth quarter. Therefore, despite very limit capital it appears that our production decline in 2009 has bottomed and growth has been reestablished.

In the third quarter, adjusted EBITDA was a $193 million with discretionary cash flow of a $152 million or $1.38 a share. Adjusted earnings were $54 million or $0.48 a share and in the third quarter we spend $77 million on CapEx which resulted in $74 million of free cash flow generation. Production in the quarter was $476 million to-date, down 9% compared to Q3 of last year. Unhedged realizations were $4.05 in Mcfe compared to $9.91 last year. Our hedging activity increased at $4.05 per Mcfe to almost $6 at $5.91 per Mcfe in the quarter.

Cash differentials continued to narrow to $0.51 this quarter compared to $0.60 last quarter narrowing across the portfolio but most dramatically in the Panhandle and East Texas and North Louisiana where we have most of our activity. Notably, even today those differentials continue to narrow further.

Cash costs were $2.42 a unit this quarter, down 3% from last year, has significantly decreased LOE was more than offset by increased interest expense per unit. During the quarter, Forest reduced its total debt by $232 million through free cash flow generation and asset sales. As a result, on September 30 we had approximately $1.16 billion of liquidity remaining on our recently reaffirmed line of credit.

With operations generating free cash flow in organic growth reestablished we are in great shape with respect to liquidity, we even cash flowed in September when NYMEX gas prices hit $2.84. With the recent operational success in our core areas and some signs of firming in the commodity markets, Forest has decided to increase horizontal drilling activity primarily in the Granite Wash and East Texas and North Louisiana.

In order to position for increased activity and to decrease our overall debt position, and as part of our previously announced divesture program, we will be marketing our remaining Permian basin assets which are predominately oil. Production from there assets is currently in excess of 7000 barrels equivalent a day, and we believe a transaction for all or part of these assets could close before the end of the first quarter of 2010.

In addition, we will be marketing a non-core Canadian asset package of almost 4000 barrel equivalents a day which also could close before the end of the first quarter. We believe that proceeds from the Permian asset package alone will completely pay off our credit facility and will return Forest to more normal historic debt levels.

This finishing touch to restoring our balance sheet coincides nicely with the recent drilling successes and our plan to invest more heavily in Granite Wash, East Texas and North Louisiana. In summary, the third quarter was unremarkable financially but extremely important operationally. It should mark the beginning of an organic growth pattern driven by increased horizontal drilling activity funded by our asset sales.

And with that, I’ll turn it over to Craig.

Craig Clark

Okay, thanks Dave and thanks to the folks listening in today. Let me first make a few remarks on the industry macro environment. As we’ve said earlier, we think most of the heavy lifting has been done on the service cost side, however cost savings for the industries is still being restrained by long-term contracts. In fact at the yard in Houston where we built our last 1500 horsepower rigs, I accounted seven new drilling rigs being built last week.

We still believe in an industry decline curve taking hold on gas but tracking a gas rig count may become quite frankly confusing. With more horizontals the rig count will be less relevant as these wells are more productive and certainly cost much, much more for the industry.

This isn’t necessarily cost deficiencies or rig efficiencies is just as much spending more per well. Industry CapEx will suffer in 2010 we believe, industry spending because of lower or lack of producer hedging or lower hedges from ‘09 to ‘10. We estimate that 2010 industry hedge portfolios will generate $5 to $6 billion less revenue than in 2009 hence the decline curve. We are thinking NYMEX gas process will have a six in front of them in 2010; we talked about that on the road although our simple well economics are being run at $5 NYMEX.

Basis differential, as Dave mentioned, have finally been restored to some normalcy, spend a long time accounting it for [Inaudible] in fact today Mid Continent Gas was trading higher than the Henry Hub. We are assuming $60 per barrel in NYMEX crude in 2010, all of our place have a liquids component with the exception of the Wilcox in South Texas and the shales.

In the third quarter the Forest was fairly quite since there was not much activity going on by choice in terms of lower capital spending and what we perceived and predicted to be the lowest quarter for gas margins and prices. This came from restraint on capital spending and large gains and margin creation to do more cost savings. We also, by design, had more gas hedged in the [Shaledermonts] in anticipation of low NYMEX gas prices; I think it was the most gas hedged percentage wise in our history.

Our low rig activity was voluntary as Forest simply chose not to drill wells at all as opposed to voluntary shut-ins, curtailments or deferred completion operations, which we think are not as good alternatives as opposed to not spending the money. The shut-ins noted in our release were all non operating.

With this said, our third quarter was not without highlights as we drill some of the best wells in our Cadillac glaze I guess I can call them. We recently put online a 30 million a day equivalent Buffalo Wallow well and a 21 and 15 million a day wells in Haynesville. The additions of these prolific wells will result in organic growth as Dave talked about. In addition, we now have all five of our Cadillac rigs they are the 1500 horsepower version working on these two horizontal prospects.

We ramped up drilling activity near the end of the quarter in anticipation of increased activity in 2010. We went from two rigs to seven operated currently. The breakdown of our rig deployment is currently three horizontal rigs in the Greater Buffalo Wallow area, one in the Louisiana Haynesville, two in Alberta basin, one in the Permian basin Sprayberry or Wolfberry. There is also five non-operated rigs, three of which are in Buffalo Wallow, one in East Texas and one in the Arkoma.

In the fourth quarter, around beginning of the year we will add three to four rigs which entails basically another Haynesville rig, a Buffalo Wallow rig and a couple more in Texas or Arkoma. This is due in part to improving industry conditions, but also due to the drilling success on the horizontals specifically in Buffalo Wallow and Haynesville.

We spent only $77 million in E&D spending in the third quarter. We drilled 97 wells year-to-date with 94% success rate. Our lower capital spending is reflected in our lower production for the quarter, again by choice. Our revised production guidance does not reflect the lower spending level, it’s simply was based solely on the announced divestitures and the involuntary curtailments or pipeline analogies and non-operated well shut-in or not completed by other operators in the Texas, Panhandle, Canada and Arkansas.

A pipeline analogy were mainly dominated in Arkansas about the [Borblau] pipeline repair and the Shell Waterton plant in Alberta which did not come up again this quarter. The recently announced good wills in Buffalo Wallow and the Haynesville will offset lower CapEx, in our opinion due to the higher production rates and we’ll provide organic growth in the fourth quarter even with the lower rig count than in previous quarters of last year.

As noted, last quarter, the A and B market for producing properties has improved, you can see that was some of our sales, particularly on [Longlivedo] but even to a lesser extend on dry gas properties in the US and Canada. On the A and B side, we have closed or signed up a total of 200 million a day approximately year-to-date which affects about 18 million a day of net production which will either be close previously in the third quarter or in the fourth quarter.

On the cost side, our folks continue to exceed even my pro bono expectations on cost control across the board; this is the second time this year we’ve lowered of our cost guidance. As noted in the press release we’ve cut $22 million of cost out of the production expense of 30% in the past year. In other words costs were lowered; more than production went down, resulting in improved unit metrics.

This is no different than juicing the miles per gallon before we drive a long distance in our vehicles even in my pickup and this is a great leading for our reasons to fund our activity and growth going into 2010.

First, although in our opinions service cost have not been restored commensurate with the drop in commodity prices, i.e. gas, to 2004 levels, Forest has created good margin because our costs are down. Further our property divestitures throughout the year have significantly upgraded the asset base.

Second, our confidence in stabilized commodity prices following the historic economic downturn, in other words we are not trying to be controlled by any external factors. This was our goal all along this year including on the cost side and including avoiding term contracts, commitments or being consumed by acreage expirations.

Third, the portfolio shift has been successful, specifically we have validated our major place in terms of results. We especially have indicated not only by the continued confidence in the Granite Wash, but also by the fact that the Haynesville Bossier results that have been announced by us in industry are outside the previously believed Tier 1 Haynesville acreage including things called the East Texas Bossier.

We always said don’t sell Texas short including the serendipity zones like the Cotton Valley, Travis Peak and Petit, and I’m not talking about the football team. Before I turn over the call to J.C. for operations in detail, I should note that although drilling spending was lower year-to-date and in the third quarter, we would now hold back on adding undeveloped orient in this place, a total of 72, 000 gross and 57,000 net acres have been added year-to-date alone. J.C..

J.C. Ridens

Thanks Craig. We have excellent results to discuss in both Granite Wash and Haynesville today and I will start off with Granite Wash program. Our second horizontal well in the Camp South area was completed for 30 million cubic feet equivalent per day, per well cost of about $6.4 million. We believe this is the second highest rig reported for our horizontal well on the Panhandle.

And as you all saw in our press release 66% of this volume was in the form of liquids. The liquids alone would make this one of the best wells drilled on shore this year. So our Granite Wash programs like drilling high volume oil wells, except you get to make 10 million cubic feet of gas per day as a bonus.

Our latest well was completed in the Granite Wash for the 4300 foot lateral in 10 frac stages, in less than a month this well has already produced approximately three quarters of Bcfe and is currently still producing 25 million cubic feet equivalent per day. I should note that this well is approximately seven miles away from our first horizontal completion, so we aren’t just drilling offsets here we are proving that our expansive acreage position is high quality.

On our operated activity on the Granite Wash, we have another well preparing to be completed, one that is currently drilling and should reach TD in about the next 10 days or so and other that’s just put. We’ve moved to another one of our lantern in 1500 horsepower rigs up here so we can get another well underway.

So, as you can see we have increased and continue to increase further horizontal activity here since our last call. That will put us around on three 1500 horse power lantern rigs drill and operate at Granite Wash horizontal wells since we began this program.

In addition to the horizontal Granite Wash activity we also continue a horizontal Morrow program as well. Our latest well there had a 3,500 foot lateral completed with 15 stages of frac, this is longest lateral on most stages completed any well in this field today. The well is currently producing 7.5 million cubic feet per day and it costs $3.9 million. So you can see still an economic play even though we don’t get the liquids compounded of the Morrow.

We have a one rig program continuing with this Morrow development and we will continue that throughout the year and to finish off in the Panhandle we have continued participation in an outside operated at Atoka horizontal program.

Since last call an additional two non-operated wells have been completed and they had combined IPs of 26 million cubic feet per day. There are currently three additional non-op wells that are either in the drilling or completion phase of this Atoka horizontal program.

While this area butts our operated acreage that we believe is also perspective for the Atoka we plan to continue to focus our efforts on high liquids content Granite Wash wells initially.

Moving onto the Haynesville program, we completed two additional wells with a combined IP of 36 million cubic feet per day. One of the wells was in our Woodardville field and we also completed our first well in Sabine Parish as well. Both of these wells had 3600 foot laterals.

We are drawing another well in Woodardville and we’ll continue to run a one rig program in that field. In addition to the operated activity we anticipate also participating in non-op wells in this area to the tune of two or three wells in the next six months based on AFEs received from other operators.

We are not limited in takeaway capacity for this area so this will not be an impediment to our development. We’ll be drilling our next well in the Sabine area starting late in the fourth quarter, we are currently curtailed on Sabine well due to pipe line capacity and the delay in drilling the next well is to allow the pipeline company time to cure that capacity issue. Our plan will be to run a one rig program in this area as well once we move back in on the fourth quarter.

On the Texas side of the play, we’re participating in a non-operated well that further confirm prospectivity for some of the Haynesville Bossier in Harrison County Texas. Don’t be confused by the names as different operators call the middle section of the shale different names like Haynesville and Bossier.

While the IPs of this portion of the play have been less than in Northern Louisiana or in the southern extension down through Shelby County and our Sabine Haynesville area, the production declines have also been shallower thus we feel this area will still be profitable, but in the meantime, we need to focus our capital on the high rate area. Needless to say the entire Haynesville Bossier Play continues to evolve especially as more data becomes available on Texas.

Lastly, we have added oil activity in the Permian with the one rig program in the Sprayberry drilling Wolfberry wells, with oil prices at higher levels we have also accelerated our work over and recompletion activity in the Permian and while we are on the oil side of the business, we also recommenced our drilling program of horizontal wells in the EB fields in Canada.

Today, our total operated rig count has increased to seven, we are participating in five non-op wells for total company rig count of 12. In summary, our horizontal program in both the Granite Wash and Haynesville continue to deliver high rate wells and we’ve increased activity in capital spending in both areas.

And of course no call would be completed without the reminder we remain 100% successful on our horizontal drilling program with no wells lost in any horizon to this point. This is a testament to our drilling and completion teams and we’re extremely proud of their record.

Operator, at this time we’re ready for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Dave Kistler - Simmons and Company.

Dave Kistler - Simmons and Company

Real quickly both kind on Haynesville, well Haynesville and Buffalo Wallow, can you talk through little bit about the science that you are still doing there, I guess 3600 foot laterals, we experimenting with going longer on laterals with the well results that you had what kind of chokes were you running, is that kind of optimal in terms of how you want to flow these out of the gates and kind of where are we on the learning curve for your experience in those place?

J.C. Ridens

I would say that in the Woodardville areas, we will look at longer horizontals there. We’ve got several under our belt now, successful at 3600 feet. One of the things we have been toeing with is how many stages of frac we are pumping that lateral to try to optimize the contact volume of reservoir rock.

In terms of the flow back, yes, we think that we’ve got pretty well nailed, because what we are doing there is allowing the wells to draw down until reach an optimal draw down bound and at that point we could open in the choke and just let the wells ride from there.

In Sabina I thank that we’re probably still on the learning curve in terms of what the optimal length and frac stages will be, we’ll see that evolve just as we have in Woodardville.

Granite Wash we’ve already move that along pretty substantially, because as I mentioned we’ve got a 4300 foot lateral, basically that’s as long a lateral as you can drill on the sections still on the 467 foot offsets that are bound to us Texas Railroad Commission. To increase the number of frac stages there as well, and also changed a little profit type up so that we limited the amount of sand fall back from that multiple stage horizontal completion.

Craig Clark

Dave, this is Craig, we are still using higher strength propp within the Haynesville and targeting lower cost and some because of the rigs and our efficiencies that we gleaned thus far, but we did use higher strength propp.

Dave Kistler - Simmons and Company

That’s helpful. I appreciate the clarification there. When I kind of look at your hedge profile for 2010 obviously gas a little less hedge that we’ve seen in the past, can you walk through a little bit with your comments of kind of a $6 gas handle as your expectation for 2010. Do you anticipate laying on more hedges to maintain the capital budget and keep within cash flow?

J.C. Ridens

I think that our position for 2010 is exactly where we have been historically. 2009 was high for us, 40% is generally exit rule of thumb. However, we will be selling substantial amount of properties although it’s focused on oil we will have a lot of gas production going away in those property sales as well. So by virtue of those property sales our percentage will increase into 2010 above what you’re currently forecasting probably.

So, as a long way of saying we don’t have any plans at this time to increase the hedged volumes, but I think our hedge percentage will come up with the sales of our properties.

Dave Kistler - Simmons and Company

That’s fair and that’s actually exactly your outlining high head model. So I appreciate that. Last thing, CapEx anticipated to be within cash flow for 2010?

Dave Keyte

We’ve not provided guidance on that that we’ve historically done that.

Operator

Your next question comes from David Tameron – Wells Fargo.

David Tameron - Wells Fargo

I missed the opening comments about the asset package, I think I heard 4000 barrels a day in Canada, is that correct?

J.C. Ridens

That’s correct.

Craig Clark

Barrel equivalent.

J.C. Ridens

Barrel Equivalent.

Craig Clark

It’s gassy and there is some, and that’s a lot of the non-operated properties, we call them non-core. In fact I think this package will be out of the non-operating business in Canada entirely.

J.C. Ridens

Then the Permian package was 7000 barrels plus Dave.

David Tameron - Wells Fargo

So, 7000 and that’s what 75% oil.

J.C. Ridens

That’s probably two thirds.

Craig Clark

That’s just under 70 and Dave is quoting BOE of course.

J.C. Ridens

Yes.

David Tameron - Wells Fargo

Okay. So, if I do the math 11,000 barrels a day that’s a big number on the backend.

J.C. Ridens

That is it.

David Tameron - Wells Fargo

And you said that you are confident you are going to get these number by first quarter 2010?

J.C. Ridens

I said that our target date will be before the end of the first quarter 2010. In the case of the Permian package there potentially we may pull some properties out, but I think that our goal right now is to move forward with all 11,000 barrels.

Craig Clark

And as a reminder this was when we talked about $4 or $5 million property divestitures even like last year, many of these properties specifically even the Canadian ones were already identified.

David Tameron - Wells Fargo

Then Dave, if I think about the cash flow, you get that cash flow on the door tomorrow what do you do with it, and on the revolver or what do you do?

Dave Keyte

Yes, stay off the revolver and then put the rest on the balance sheet to help fund what we’re going to be doing over the next year or two.

David Tameron - Wells Fargo

As I think about 2010, do you plan to spend, you guess stay within cash flow or what do you supplement that with asset sale proceeds?

Dave Keyte

Again we haven’t given them guidance on CapEx, but historically we’ve been within cash flow.

David Tameron - Wells Fargo

Okay. Another one question for J.C. I’ll let somebody jump on. You mentioned, I think its seven miles from the existing from the first well?

J.C. Ridens

Yes.

David Tameron - Wells Fargo

In layman’s term what does that mean to us?

J.C. Ridens

What that means to us is that, we’re not just taking the first well that I would repeat at 17 million cubic feet per day and drawn on immediate offset, what we have seen was some of the development out here David is that people have drilled multiple wells in the same section knowing that that’s a sweetheart section, our point here is we’re seven miles away from that first well and have made aware that was almost two times as good, and so, what it should mean to you is that we’re testing and delineating our acreage position not just staying in the sweetest part of this plan and touting to repeat results as though we have discovered something there.

Dave Keyte

That’s seven sections away.

J.C. Ridens

It also means Dave that it’s not going to be just in one county and it also means that field names are irrelevant.

Operator

(Operator Instructions) Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

I don’t know whether you touched on this before, but can you talk a little bit more about liquids content in Granite Wash, it look like a very high liquids content rates in the particular well, latest well and wanted to see what your thoughts are on any volatility and liquids content as you look across your acreage?

J.C. Ridens

The liquids content that we had, IP on that well was almost 1300 barrels of oil a day and 2000 barrels of NGO, and the content is quite high which is why we like to play to begin with. It’s what we liked in even the vertical was, because how rich this gas is 1300 BTU gas, we do see a little bit of variance and different members of the Granite Wash as you go deeper.

However we do not see that variant as you stand the same arisen across this place, it’s only as you start going deeper that you see segregation on it. So I’m confident that what we are seeing here is not an operation because it confirms pretty much with what we have been doing all along.

Brian Singer - Goldman Sachs

I mean the bulk of the wells that have been announced in the Granite Wash had had high liquid content and it does seem that this particular one has one of the higher liquids content, I guess is the particular horizon you feel like you drilled in or I guess is there anything that you could add?

J.C. Ridens

No, I think that although we’re making a little bit more oil than perhaps some of the other have. When you look at NGO yields compared to BTUs, I don’t think that there is any variance there. So, I think that that’s what all we would about at this point is we’re very pleased with the high liquids content that we’re seeing particular old phase.

Craig Clark

Brain, this is Craig. We should note that when we drill, I think almost 400 wells, the gas BTU content of the commingled stream varied from 1050 BTU to 1300 BTU as we tested zones differently. The reason it’s higher is because we are probably in one of the different lobes that has a higher BTU on its own. However, we’ve had high liquids content it’s relative, the Atoka for example is dry, but dry is not dry, it’s 1050 gas, it’s the lobe we’ve chosen to go in as opposed to the variability across the field.

J.C. Ridens

Our liquids yield barrel per or gallons per Mcfe on the NGOs. We’re not hugely dissimilar on these first two wells, so it’s not like one of them was just really, really different.

Brian Singer - Goldman Sachs

Then just separately is there any update, and perhaps I missed it on Quebec?

J.C. Ridens

No, except there is offset activity, we have a small interest in verticals that had been announced publicly and I believe there are planned horizontals by both Talisman and another operator we’ve an interest in one on the small ones. So we will get a look to see, but I believe there is at least one or two rigs drilling up there currently and we have a small interest in one. So we are in the observation phase including how to change the fracs, but we have no activity plan like this year, probably the end of next year.

Operator

Your next question comes from Jeff Robertson - Barclays.

Jeff Robertson - Barclays

Dave, can you talk a little about the impact that the asset sales could have on LOE in 2010 and also within that just the mix of drilling for Granite Wash and Haynesville type assets and what that may do to you LOEs?

Dave Keyte

Yes, if you will permit me just to be, to give you general guidance rather than specific. Certainly these are going to be the higher LOE properties, and so, once again we should be driving down at least operating expense cost in total and per unit. In terms of the drilling activity there will be a much higher proportion of our drilling dollars going into the horizontal drilling activity and as you might gather the wells that we are producing with that program are very low, at least operating expense was well.

So, the sales will not only drive down or help the balance sheet but it’s going to increase the quality of the drilling results and the qualitative assets remaining in the company substantially.

Jeff Robertson - Barclays

Thanks. Dave, can you talk at all about the impacts that the sales would have on your borrowing base and what you want to do with the borrowing base just given that you have so much undrawn and I assume pay a commitment fee on that?

Dave Keyte

Yes, I think once we get done, I’d like to have the cash in fist. Then we’ll re-examine that entire piece in our debt structure and figure out what to do with it. It’s unlikely that we would carry a substantial which is a $1.6 billion piece on our borrowing base; it will be reduced obviously with these sales, but it’s unlikely we would carry a very, very large open facility.

Jeff Robertson - Barclays

Thanks and then secondly, Craig, can you talk a little bit about the acreage that you mentioned that you all have added this year? I believe you said it was 70,000 gross and 57,000 net. In terms of which place you all are trying to build acreage positions in?

Craig Clark

Without being released in competitive, it’s pretty much in the basins that we’ve talked about; it’s pretty evenly broken out between Arkoma Tex or really East Texas, North Louisiana, Canada Deep Basin and the Texas Panhandle. It’s almost broken out almost evenly between those three areas.

Jeff Robertson - Barclays

Craig, in those areas it’s ground floor leasing, it’s not acquiring production to get as a way to pick up acreage?

Craig Clark

Yes, you are correct, it is good old fashioned land towards leasing or farmings.

Operator

Your next question comes from Scott Hanold - RBC Capitals Markets.

Scott Hanold - RBC Capitals Markets

Going back to that Granite Wash, did you all ever say which zone you did drill that in?

J.C. Ridens

No, just Granite Wash.

Scott Hanold - RBC Capitals Markets

Okay, you are not going to be specific to which one.

J.C. Ridens

No.

Craig Clark

We have got a total of 7 to choose from, so we picked one.

Scott Hanold - RBC Capitals Markets

Yes, they are 10% in terms of both being right. On that, well, it cost a $6.4 million, what do you is average well cost coming to this area, is there any more room to sort of improve that?

J.C. Ridens

Yes, there is. Because to be frank we had about $0.5 million worth of trouble cost on that well. We had some top drive issues that slowed us down for a few days and a couple of other minor things. So there is still room to move on that. I still think that our target cost of 5.5 is readily achievable number and there is a guy sitting next to me who says Yes you will get to that cost.

Dave Keyte

The variability out there is probably one or two factors. One would be unlike it’s not about the fracs, it’s that other operators are maybe doing more fracs per well or the fact that there is a term contract that has a substantially higher rig rate than we enjoy.

Scott Hanold - RBC Capitals Markets

How much does depth play into the cost, is that very meaningful based on the different distances between the formation?

J.C. Ridens

It’s not as much on the vertical well, it’s almost surrounding here, but on the horizontal it plays some. So your deeper wells might be, it is not like the Haynesville, but it’s going to play a difference because you’ve got the mechanics of it, but it’s not a different pressure regime or we have to set type or anything, so it’s not.

Dave Keyte

I think any of the members of the Granite Wash would probably be fairly close to each other. I think the tipping point will be frankly when you get into the Atoka.

Scott Hanold - RBC Capitals Markets

When you look at sort of year end reserves, maybe it’s kind of early to think about that, but kind of on this Granite Wash horizontal program, how are the engineers going to treat adding reserves in a play like this?

J.C. Ridens

Well, that’s just basically the same as the verticals since we’ve got a whole lot of decline curves out here about 400 just for us you’ll do the same analysis with it that you do right time you wont do volumetrics, but you’ve got a lot of history out here for tight curves, remember you’re in the same zones you were producing vertically either singly or co-mingled by themselves for many years. So, it won’t be exciting I guess evaluating new shale.

Scott Hanold - RBC Capitals Markets

One last question on that the Haynesville well and the one you drilled Sabine, what formation was that well drilled and was that drill in Haynesville shale, I think that one you basically went all the way down to the smack over and kind of take a look at every thing, is that correct?

Craig Clark

We actually drilled it to the line and Paolo did it, and did a lot of what I am going to call science and technology, but we’ll call it a Haynesville well. When you get to the Texas side they’ll probably call it something different, but I think it’s probably Haynesville.

Operator

Your next question comes from Joe Magnor - MacQuarie.

Joe Magnor - MacQuarie

I just wanted to circle back on the East Texas Granite Wash acreage 91,000 net, how much of that do you think you have tested at this point in time?

Dave Keyte

Yes, in vertical wells we have tested probably 80% of that acreage, if not more. Horizontally, we’ve only got two wells down and completed right now with another one waiting information and, another that is drilling and those are going to open up, each of those I am g to view as opening up a new section for the horizontal. So, horizontally probably about 10% of the acreage and in a vertical sense greater than 8.

Joe Magnor - MacQuarie

Okay.

J.C. Ridens

In terms of adding sub surface information we got around an 80%.

Joe Magnor - MacQuarie

Even carrying an inventory of horizontal locations around 170 for some time, has that changed at all?

Craig Clark

It is evolving even as we speak. That was focused only in the southern area that didn’t include anything we’ve had going on in the North, that’s just horizontals around mostly current activity for us an industry.

Joe Magnor - MacQuarie

That was only about 20,000 or 25,000 acreage in that southern area?

Craig Clark

As a reminder using the diagram Joe that we show on the road, that’s one well or one zone that you target. So if you had an Atoka and a Granite Wash right next to each other then you would have to double that.

Operator

(Operator Instruction) Your next question comes from Andrew Coleman – UBS.

Andrew Coleman - UBS

My question on the, just going back to the asset sales again. Is it fair to assume that the hedges that are in place right now would all tie to the Permian?

Craig Clark

No, it is not fair.

Dave Keyte

We are getting substantial oil, for instance just out of the Granite Wash, and so, the oil that’s in our portfolio or adding to as we sell these other assets it’s just not as growth.

Andrew Coleman - UBS

Okay and on a quick math it would look like you would be, you are going to about 85% gas if all those assets would be sold, that’s probably in the ballpark, yes?

Dave Keyte

Haven’t done the math but that sounds directionally correct.

Operator

We have no further questions at this time Mr. Redmond. Do you have any closing remarks?

Patrick Redmond

Yes, 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 this does conclude today’s teleconference. You may all disconnect.

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Source: Forest Oil Corp. Q3 2009 Earnings Call Transcript
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