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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

Thomas Gardner - Simmons & Co.

Scott Hanold - RBC Capitals

Brian Singer - Goldman Sachs

David Tameron - Wells Fargo

Andrew Coleman - UBS

Ray Deacon - Richard Capital

Ken Carroll - Johnson Rice

Forest Oil Corp. (FST) Q2 2009 Earnings Call August 4, 2009 1:00 PM ET

Operator

Good afternoon. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Corp’s second quarter 2009 earnings conference call. (Operator Instructions).

I would now like to turn the call over to Patrick Redmond, Director of Investor Relations. Mr. Redmond, you may begin your conference.

Patrick Redmond

Thank you and good afternoon. I want to thank you all for participating in our second quarter 2009 earnings conference call. I will also note that a replay of this conference call will be available through August 18, 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 or anticipates and other similar expressions 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 David Keyte. Thank you.

David Keyte

Thanks Pat, and thanks to all for listening in what is finally a steamy week in Denver, with the Rockies leading the race for a wildcard spot.

Second quarter results for Forest were inline with what we had expected relative to production volumes, and better than expected from a cost perspective. Operating cost containment efforts continue to show positive results and price differentials improved, which kept sequential EBITDA and cash flow flat despite the lower production.

In the second quarter EBITDA was $200 million, with discretionary cash flow of $158 million or $1.56 per share; adjusted earning of $54 million or $0.52 per share; and during the quarter, we generated $68 million of free cash flow. In doing so, we only spent about $90 million of capital expenditures.

The generation of significant free cash flow is forecasted to continue throughout the remainder of the year. We continue to be cautious on drill bit spending as drilling and service costs continue to fall, and visibility to recovery in natural gas prices continues to elude us. Production for the second quarter was $521 million equivalents a day, up 3% compared to the second quarter of last year. Unhedged realizations were $3.83 per Mcfe, compared to $11.21 last year.

Notably, the hedging program had a realized gain in the quarter of $85 million which lifted the quarter’s realizations to about $5.62 per Mcfe. Price differentials also continued to show improvement, averaging on the gas side about $0.60 this quarter compared to $1.26 last quarter. This improvement was primarily due to a significant move in tightening in the Mid Continent region.

Cash cost per units were $2.32 this quarter, down 6% from the second quarter of last year. A $0.30 per unit reduction in production expense and a $0.07 per unit reduction in G&A expense was offset somewhat by $0.30 per unit increase in interest expense. We continue to be a top performer in the industry in this metric, and in particular, the results on the lease operating spend side have been great. DD&A fell $2.44 per unit as the effects of the prior two quarters ceiling test impairments are now fully reflected on that rate.

As to liquidity as of June 30, we believe we have now completed our working capital investment that was required by the significant reduction in capital spending. Investment in working capital totaled approximately $108 million over the last six months, including $100 million in the last three months.

Obviously when we increase capital activity, working capital would be a source of funds not a use of funds. Overall, liquidity is in great shape with approximately $932 million available on our credit facility. Our operations are now in free cash flow mode and there is no significant working capital investment required in the near term.

Year-to-date we have raised about $850 million in the capital markets to improve our liquidity’s position, we raised 600 million in the high-yield market back in the first quarter and we are swamping that back to a floating rate. At present, we have completed swaps on $425 million of that debt, as a result of the swaps we are now paying about 6.2% on that high yield portion.

In addition, we have completed our base program for gas hedges for 2010, somewhat earlier than normal. We have a $160 million, our day hedge is about $6.34, and about $180 million day basis hedges at differentials which average about $0.68 per unit. This is our normal base level of hedging. If things happen to improve we may increase that position.

Finally some comments on the A&D market. We are seeing trades at much lower discount rates on PDP versus the first quarter. This is a good sign, but certainly nowhere close to what we are seeing year ago, and in the case of these particular property trades that we are seeing, these have been primarily oil properties. The market for conventional gas assets is still very weak. We expect this market to remain relatively shallow until we see some more significant supply side response in natural gas.

We continue to target significant asset sales to improve our asset quality and delever the balance sheet. If successful, these targeted assets sales, the current free cash flow generation we are now enjoying should enable us to reduce that to normal levels and allow for a more robust capital program in 2010.

With that, I will now turn it over to Craig.

Craig Clark

Thanks Dave, and thanks to those listening in on a busy week for earning calls. As Dave described, the second quarter of 2009 was pretty much down the middle with a beat on cost and net banks. We had margins improved, despite lagging natural gas prices in the second quarter. Yet again, we enhanced margins by cutting more cost across the board and also with more NGO extractions.

As we pointed out before, most of our natural gases recoverable liquids are under favorable contracts. We did most of our 2009 and 2010 hedging before 2009 began or in the first quarter. Even though we’ve talked about plays like the Granite Wash for several years, we’re seeing our ideas validated by us and others as Forest again continued mechanical and production success on our horizontal initiatives. J.C. will go in more detail on the Granite Wash specifically in his operations update following my words.

Let me first talk about the current industry environment and macro fundamentals. Gas prices continue to align with some water, while crude and liquids prices have recovered, including NGL prices. The liquid is rich, has pretty good economics, if and I do mean if, cost efficiencies have been restored. It’s our opinion that the current U.S. rig count is being buoyed by term rig contracts, some of which are for brand new rigs out today.

Leased expirations, particularly in places like Haynesville are also supporting a rig count. Forest is in good shape in both these areas. A lot of industry wells are not economic at today’s gas crisis. Current industry CapEx programs are certainly supported by the in the money hedges or overspending.

I’ve seen a number of producers on the second quarter calls adding 2010 hedges in the second quarter. We checked this box sometime ago with our 2010 gas hedges averaging as Dave mentioned 634. The current gas rig count and associated spending on oil worldwide cannot increase overall supply, and in the case of natural gas can’t even keep up with the U.S. supplier or kept it remotely flat. I wonder what gas supply will do when producers have unhedged cash flows.

Regardless, U.S. gas supply may see a $5 million per day or half a B per day declined each month for rest of 2009, solving the imbalance with demand by year end, rebounding in 2010. The May E.I. eight data seemed to confirm this assumption we’ve talked about for sometime now.

On the service cost side, most of that heavy lifting has been done, but we still believe there are still more discounts to come on certain services like, mud and hard commodities, specifically things like cement and proppant. Our 20% savings projection that we made in early January this year, which had a few kept calls from the audience kind of looked pretty conservative at this time.

Our CapEx spending in the second quarter reflect some of these savings, but also a further pull back of our rig count until more savings and efficiencies occur, while pushing through the sloppy gas prices in the shoulder months like summer and early fall.

Please be aware that our spending discipline is based on expected lower cost, and not accelerating gas production from hyperbolic decline wells into this price environment. We prefer this over drilling and not completing wells, our curtailing new wells or shutting in new wells, I don’t understand this one by some folks in the industry.

Our spending does not reflect any specific project economics, but reflects delineation in certain plays, not acceleration. In fact this is a good environment to be adding landholdings and build project inventories, the both of which we are involved in. We are in an enviable position with no term rig contract obligations, and mostly HBP acreage, again our objective is to make money.

Our plans are to stick to the CapEx guidance in ‘09, adding high rate horizontals in places Greater Buffalo Wallow, East Texas and North Louisiana, including the Haynesville, Horizontal oils in Canada and some ship CapEx to old properties in places like the Permian.

A few quick comments about our second quarter results before I turn it over to J.C.. We drilled 86 wells year-to-date with 94% success rate. Our operated rig count began the quarter at 15 operated rigs and ended the quarter at four. There are five additional non-operating rigs running today in addition to the three operated rigs currently, most of all of these are horizontal and there are other in the Texas Panhandle or East Texas and North Louisiana. Some of the rig decline in the second quarter was however due to the seasonal road bands which we always had in Canada.

On the cash cost side, we did very, very well again. We’ve come to expect this after five consecutive years of reducing costs. We compare favorably to peers as Dave mentioned, even though we’re not just a dry gas or offshore producer.

Our cost progress in the second quarter is even more impressive when you consider we’ve reduced cost per unit, even though production declined. This is consistent with our philosophy to increase margins, because we believe all costs are variable and therefore, can be controlled. I might be one of the few CEOs on these calls who are so focused on cost, that my pickup truck qualifies for the cash-for-clunkers program.

Our production volume in the second quarter was down due to the $30 million of the divestitures closed year-to-date. We also had planned for the Shell Waterton plant in Southern Alberto come back online in the second quarter, that’s about $5 million a day; this did not happen. We are seeing few pipeline analogies and plans turn around in the summer, but we hopefully dodged the big Arkansas interstate pipeline outage noted by some competitors.

Our high rated horizontal wells in East Texas, North Louisianan and the Texas Panhandle will drive volumes primarily for the rest of ’09, plus the aforementioned Canada volumes. As Dave mentioned, the property filled market is coming around, both in the US and Canada. We’ve divested $30 million year-to-date I believe in the second quarter and that included an exit from Mississippi in the second quarter.

Again this quarter, we had some of our play concepts validated by others and competitors. Our other competitors, specifically more good Haynesville Shale data points in Texas and of course good Haynesville data points in the Louisiana. Folks need to begin the see Forest delineate itself in terms of well cost, mechanical execution and in the case of some of our Haynesville Wells right per foot a lateral.

Even though, we announced our Granite Wash horizontal wells several months ago, new industry announcements have really drawn attention to this play we’ve been talking about and making acquisitions in for several years. I should note that we are one of the largest operators in the Granite Wash trend, maybe the largest operator on the Texas side.

Even though most folks have down spaced to around 40 acres, our average spacing in the outlying areas is of less than 160 or more than 160 acres per well, so we’ve got a lot running room and this is mainly HBP lease.

This is a good lead into J.C. discussion on the Granite Wash, I’ll turn it over J. C.

J.C. Ridens

Thanks Craig. As I said in our last conference call, if we only had two places in which to build the company, the Texas Panhandle in East Texas North of Louisianan would be as good as any. This is holding true as we look at the results of the horizontal drilling achieved in both these areas. To further describe how we continue to focus on horizontal drilling in the Panhandle, I would like to talk about the geology of the Granite Wash in greater detail than we have in the past.

The overall Granite Wash producing trend was setup by a mountain front originated from north west to south east. The Wichita mountain front became the source of deposition as the erosion of the mountains occurred and these granitic sediments were deposited in a direction primarily southwest to northeast, and lobes coming off of the mountains, thus the term Granite Wash.

A very basic way to view to this depositional environment is to lay your hand on the table, viewing you knuckles as the mountain front and your fingers as the lobes that were subsequently deposited. Much like your fingers, the lobes of the Granite Wash are fairly straight, do not exhibit the serpentine nature of mature stream channels, thus making the geology fairly predictable.

There are eight pay intervals in the wash section, the number of pay intervals does vary across the area, however, virtually all of our acreage has at least three productive members present.

Our acreage begins with Mendota Ranch in the northwest portion of the play, then to the centrally located Buffalo Wallow, down to the southeast which we call, Camp South and Frye Ranch. The naming convention varies amongst operators, as what we call Camp South and Pyre Ranch has been called Stiles Ranch by others. Ignore these three field names, it’s all the same area.

In this area alone, which has resulted in the most prolific horizontal wells to-date, we have about 32,000 gross acres. Across the entire Panhandle position, we have 120,000 gross and 91,000 net acres. Only our Buffalo Wallow proper acreage which lies on the border of Hemphill and Wheeler county, and covers about 10,000 acres gross has been significantly down spaced.

Our average density of development on the remainder of our acreage is about 160 acre spacing unlike other operators. This leaves to a significant room for horizontal development. In fact as we began stepping out to our southeast acreage, we typically drilled the corners of the sections leaving the interior available for horizontal wells.

Horizontal development works in this play, because it’s an effective tool to allow for more volume of reservoir rock to be contacted with the single well bore. Drilling a 3600 to 4000 foot lateral into only one member of the reservoir and then performing 8 to 10 frac stages, provides much more rock volume to be contacted than when you drill a vertical well and perform multiple stage fracs on several intervals. It basically allows us to concentrate the fracs into the best portion of the lateral, which has shown a significant increase in IPs and projected EURs.

Our first operated well in the Granite Wash has held up well. We discussed the IP of this well, which was 17 million cubic feet equivalent per day at our last call. It is averaged 7.8 million cubic feet equivalent per day since April, including being restricted early on to prevent sand flow back.

Further, there is a significant liquids component associated with this gas, and about 30% of the total productions from liquids. This significantly increases the value of this production strength. Please note that this well is trending towards our upside case on the type curve we show in our Buffalo Wallow presentation on our website, indicating an approximate 50% rate of return, using $3.50 gas and $55 oil.

The wells declining is forecasted and gives us further confidence in the huge potential that this play has to offer. We estimate that a horizontal well here will recover about 6.5 bcfe, compared to about 1.5 bcfe for a vertical well. This means we are getting about four times the reserves for a little over twice the cost comparing a horizontal to a vertical well.

My estimated cost per completed horizontal is about $5.5 million on average. This is less expensive than the Atoka horizontals due to shallower depths being drilled. We are drilling an additional horizontal well to further delineate the upper Granite Wash on our acreage position in the South Camp for our ranch area. We are also participating in two other Atoka horizontals as well, and more horizontal at this time.

In summary, our total horizontal activity is four wells, testing three different horizons in the Panhandle. We will focus our operated activity on horizontals in the liquid-rich Granite Wash, with one length of the rig running here for the remainder of 2009.

Moving to the Haynesville in East Texas and North Louisiana, our most recent completion had an IP of 20.3 Mcfe per day and has average 14.6 Mcfe day since being placed on production in early July. The cost of this well was approximately $9 million, for a 3500 flip horizontal with ten stages of frac.

This is less expensive than our first well on the Louisiana side of the play, as we continue to improve our drilling and completion techniques, with our target cost being $8 million per well. We are currently drilling an offset to this well with plans to labor rig in this portion of the play for the remainder of the year, and once again it’s a lantern rig.

Another horizontal Haynesville well, we drilled in Central Harrison County had an IP of 5 Mcfe per day, and average 3.2 Mcfe during the first 30 days of production. Although, not as good as our results in Louisiana, we found good reservoir quality in this 3500 foot lateral, but also got five out of nine frac stages fully placed. After changing over to smaller providence, the fracs were more effectively pumped.

With East Texas still being less developed than Louisiana, we don’t feel that this result is unusual for a play that is still maturing. Recent offset activity to some of our acreage in Harrison county has yielded IPs as high of 11.4 Mcfe per day, indicating the play is still progressing on the Texas side, especially in central Harrison County and further south. We’ve seen IPs reported as high as 9 Mcfe per day Panola County and Haynesville play has really new activity in the Shelby, St. Augustine and Nacogdoches counties, where we hold acreage as well.

As cost continue to decrease for these wells and techniques improve, we feel we can apply these benefits to the acreage that has yielded less prolific results. We are targeting a $6.5 million total well cost in Texas, with our overall average target now being $7.3 million per well for the whole play.

In conclusion, we continue our program with horizontal drilling in both the Panhandle and the East Texas, North Louisiana areas. Our program continues to show lower drilling cost as we progress, and we have 100% mechanical success with no well bores lost during either drilling or completion.

Operator we’re now ready to take questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Tom Gardner - Simmons & Co.

Thomas Gardner - Simmons & Co.

Following up on your comments on targeted asset sales in your 2010 capital allocation plans, assuming the M&A goes through sometime around year end, what does your program look like going forward? What are your focus areas beyond the horizontals and the Haynesville and Granite Wash, are there some other areas you would be focused on beyond those two?

Craig Clark

Yes, and of course our guided assumptions for 2009 didn’t occur to asset sales and it looks like we are going to make some more progress in ‘09 or make some hay, but clearly embedded within East Texas, North Louisiana is not just for Haynesville, it’s the general overall program verticals and horizontals, specifically to Cotton Valley and Travis Peak.

So, you get the four or five multi zone. You’ll have the same thing going on with all the other zones, like in the Morrow, the Cleveland and in the Texas Panhandle on the top of the Granite Wash. So you’ll be kind of doubled up in those areas, you’ll just probably hear about the higher rig drills in the Haynesville below the Granite Wash.

Then the Permian which is getting some more capital now, which is oil and some gas, but mainly oil and then the Canada would be your, I’m going to call it conventional oil, because we are not heavy oil players in Canada, the Foothills and down in South Texas, a little bit, most notably Katie which would be Wilcox. Right now everybody is giving money to western and eastern, and you would probably double up in those areas and then add something to a lesser amounts in Canada and the Foothills and in South Texas and the Wilcox.

Thomas Gardner - Simmons & Co.

That’s helpful and jumping over to the Haynesville, how much of your acreage on the Texas side of the border do you view as currently perspective in the play?

David Keyte

I would say that we’re probably at least 80% of our acreage on the Texas side as perspective. I think that we had some disappointing results on the Northern portion of acreage, and we’ve moved further away from that. However, I think that one of the things that remains to be same on the Texas side of the play is four other members of the Haynesville are going to ultimately be productive. In that, some of the Bossier section has not been fully tested yet.

I think all the efforts so far have been focused on the lower portion of the Haynesville, and certainly we’ve seen over in Louisiana, bossier tests as well as the lower Haynesville members. So, at this point, I think we’re probably still quite perspective on the bulk of our acreage.

Craig Clark

We did Tom, exclude the reason that our Haynesville acreage varies from our total, our East Texas North Louisiana acreage, is we excluded some outline acreage that might be way west or way south. Clearly what’s going on in Texas is there’s been better data points and obviously there’s a lot of discussion about what’s going on down south, both in Louisiana and Texas right now.

Thomas Gardner - Simmons & Co.

One last question for you may on the Granite Wash; specifically do you have any immediate plans to pursue your twin horizontal idea to the Granite Wash in Atoka in the Panhandle?

David Keyte

No, not really Tom, because of what our focus is going to be. It’s really driving home on the liquids-rich Granite Wash. I’d like to see gas prices improve further before we tackle the dry Atoka. So we are going to be gathering data points off of the OBO Atoka activity and then look for rebounding and gas prices before we go after just the dry Atoka.

Craig Clark

You’re talking about where you have drilled, two separate horizontals on the same pad, right Tom?

Thomas Gardner - Simmons & Co.

Yes, however you are planning on configuring. That was a little unclear going through the presentation?

David Keyte

We do have a picture for it in one of our website slides, but there is a chance that this is not as difficult as the shales that you could do a stack horizontally, which is actually been done in Texas where you would have two horizontals coming up the same single well bore, but that’s not what our slide showed at this time, but you have the opportunity here with component rock more so than you have in the shale section.

Operator

Your next question comes from Scott Hanold - RBC.

Scott Hanold - RBC Capitals

Craig, you all have been pretty good about being good stewards to capital here in this gas price downturn. I mean what does it take for you to get a little bit more excited about drilling again and given the great rigs you can still get in the Granite Wash, why not just put a few more rigs up there and start drilling a little bit more?

Craig Clark

We’ve been trying to delineate our acreage. We are not under the gun and really any place with expirations, that’s probably what’s driving some of the activity even up there. We’d like to build a larger acreage position as well as we delineate, and see a little bit of help from gas price.

I mean these are hyperbolic decline wells. It looks like they are not severely declined as maybe a shale well would be, but clearly you are accelerating all that production almost into a 350 environment. So gas prices help and a little on the service cost side but most of the heavy lifting on the service cost side discount but little help on gas price.

Scott Hanold - RBC Capitals

Okay. Is there a sort of a gas price number that you feel better about to see being sustained?

Craig Clark

We sell the economics of various gas prices. In fact we ran the whole company at the analyst conference over a year ago at six Nymex, but clearly you are looking for an overall help. You’re not trying to focus on a specific project economics, you’re looking for overall help from gas prices in general to your cash flow not just whether one project would be economic and a certain gas price would not. I hope I’m being clear.

Scott Hanold - RBC Capitals

When can we see more activity up in Utica shale, would now be not a bad time to kind of test that given the gas prices are weak to sort of spent some money up there, is that going to be a little bit further out?

Craig Clark

Well, we have ten year leases up there, what we are doing there is we took all the rocks and the data, and did a frac rock mechanics work including with BJ in Houston and that was supposed to come out this summer and of course summer time is better than when we frac those wells.

Up to this point, we were the only company who had done horizontals, and I understand there have been two announcements publicly, one private firm in Cavalry, where we’ll have interest in I believe J.C. and then also Talisman has announced several horizontals, so we’d be interested in seeing how those come out on the drilling and the completion. Although, others have had trouble on the drilling, we have not. It would be the completion and basically what we are talking is about redoing it on the frac jobs and trying it again.

Scott Hanold - RBC Capitals

Would that be an ‘10 event?

Craig Clark

It depends on when we get the stuff out, we are not in a hurry, but we want to get the stuff out of the rock lab and probably go school and the other stuff little bit. So it would be a stretch to get it in ‘09. It’s possible, but it all depends when we get the rocks out of the labs and they are all backed up, because of the things like the Haynesville.

Scott Hanold - RBC Capitals

Okay, got it and one last question. What’s happening in Italy, has the earthquake which have been about four or five months ago, has that impacted the timeline on that at all. What’s sort of progress over there?

Craig Clark

We’re waiting on the production license, the only impact it had was it distracted some of the politicians and we were unaffected by it and precedence in the towns and pipelines that we would flow into for our first discovery were unaffected by this well. That may have delayed it, but we’re still hopeful we can get production licenses. We’ve submitted the paper work to start hopefully this year, and that would hold true with South Africa’s well, but the biggest delay was it distracted the politicians.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

Thanks for the color on the Granite Wash and going through some of the fields, and you mentioned that you are continuing to delineate here, can you talk a little bit more about what portions of your Granite Wash acreage, you are currently delineating and where you expect to be at the end of the third quarter, at the end of this year and at the end of 2010?

David Keyte

Currently, our delineation effort continues down in the South Camp and Frye Ranch area and what I really expect for the remainder of the year is that our activity will be focused on that and the upper members of the Granite Wash.

Then as I look forward into 2010, I could see us spreading that technology a little bit over more of the play getting up into some of the central portions of the play as well, certainly not on our most actively down spaced area at Buffalo Wallow but on some of the extensional acreage that we picked up from Cordillera, we think that that’s perspective for this as well.

Brian Singer - Goldman Sachs

Great. So if I understood that correct do you expect to have the bulk of your acreage but maybe the exception of the down space of Buffalo Wallow portion delineated by the end of 2010?

David Keyte

No, if I’d say fully delineated I’m saying we will spread that activity out with a 120,000 gross acres and 91,000 net acres I think it would be a stretch to say that we have that position fully delineated in a year, and that would be for Horizon’s brand.

We have over 400 wells spread throughout our acreage that we have data on, and as you know several years ago we began to test individual zones, including the Granite Wash and the Atoka, and it’s that data that we’ve been sort of sitting on before we started the Horizon.

So you’ve got delineation in some regards to vertical, and when we showed our average for the area of 8 million with eight wells, that’s eight wells all over the area, although the attention’s been focused down south, with names like Frye, Mills, Brid and Stiles Ranch, and ignore the field names that’s just the Arbitrary Railway Commission designation.

Brian Singer - Goldman Sachs

Okay. And then going back to Scott’s earlier question, when you look at more of your conventional assets the ones that are for sale or some of the ones you want to plan to keep in the U.S. and Canada, what gas price do you think you do need to increase activity or at least for those who are considering purchasing the assets you have for sale, what gas price do you think they are looking for on their end to give you a requisite value?

Craig Clark

Well, I think on terms of asset divestitures obviously you want to see the strip, which that’s helped asset strides or whatever that is, what you really want to see on asset divestitures that cost you to pull back is for people to pay you for the full proven and not just some ridiculous discount rate on the PDP. That’s like giving it away.

We’ve seen actually that change for where you’re getting those offers now, particularly on old properties in the Permian for example, and some regards in Canada. You saw a trade if there with Bonavista in Canada, that was representative, so it’s the strip.

In terms of our board, we started the year running everything at 4.50 and 5. The catch what was based on the gas price declined from that, I can’t guess and I accept that obviously since we ran everything at six, you would like to see that on the long-term later this year as you ramp up activity going into the next year. That’s kind of where our heads at except we are not running our economics assuming that you can tell that from the fact that our hedges average around $6.40.

Brian Singer - Goldman Sachs

Beyond keeping CapEx inline with cash flow, did the conventional assets at current well cost, can you get attractive returns at current gas prices or do you need something six or higher?

Craig Clark

We are not conventional, you talking about non-shale or just old fashion Permian Basin?

Brian Singer - Goldman Sachs

Yes, let’s just say if we exclude the Haynesville, exclude Granite Wash and exclude an oilier well that would have otherwise have and oilier mix?

Craig Clark

Yes, I think you would need some more gas price that help out places like South Texas or Canada, but embedded in those would be like our Cotton Valley horizontal or a Morrow horizontal, that would still be okay. So, I think what you are going to see us be is almost pure horizontal into 2010.

Operator

Your next question comes from David Tameron - Wells Fargo.

David Tameron - Wells Fargo

A couple of question Craig and you started to talk about it, but can you talk about what gas price would you have to see given you gas position in the back half of the year before you would add additional rigs, given more cost are at, assuming they kind of flatten out from here?

Craig Clark

Well, I would like to see it not just manifest this up on the front line, obviously you want to see a come back up and it even it’s been tangled now and what you would like to see it’s a 350 I can’t make any projections, but just the start of the year added five with the higher rig count, you would probably like to see something like that in terms of NYMEX was south without some outrages basis differentials. And again, we are hedged substantially above that, but we don’t run the hedges in our economics, we run those in our cash flow.

David Tameron - Wells Fargo

Okay. All right and then Canada deal that you just referenced you said, you thought it was representative or what exactly did you say about that?

Craig Clark

That was more or less I’m going to call it conventionally assets, gas assets in Canada and that’s been the last couple of deals there have been priced fairly, I’m not counting heavy old stuff, because we’re not in that. It would indicate to me that there are deals happening in places like Permian and well, we saw Mississippi and in Canada they would indicate the fall in the A&D markets specifically, the D market that would represent fair value per proven reserves in a given area. And that Bonavista slash in Canada it would like it was pretty decent metrics for the seller.

David Tameron - Wells Fargo

Okay, all right. Let me ask about 2009 production guidance, just one call I get a lot of people are saying with the reduced rig count you won’t be able to hit the numbers, kind of lower guidance it’s inevitable, anything you care to comment on that for 2009 production guidance?

Craig Clark

It is right now with that over spending cash flow and of course it’s because of the high rigs rows are drilling in places like Haynesville and Buffalo Wallow, but obviously seeing some people ramp up CapEx that’s not what we are doing here.

Operator

Your next question comes from Andrew Coleman - UBS.

Andrew Coleman - UBS

I had a question, do you have a target that you think you would be happy with on a debt-to-cap basis are we shooting for the mid-50s or is it still too early to tell?

Craig Clark

I think it’s too early to tell at this point certainly, I think one of our goals we’ve stated publicly is to be out of the credit facility. So that would be in the $2 billion range of debt given the asset base we own today. That feels comfortable to us. In terms of setting long-term targets we have not readjusted those give our decrease in book equity.

Andrew Coleman - UBS

Okay. One thing on modeling question is well as looking at deferred tax with the lower spend rate is it fair to assume that if I differ less than a 100% of the cash portion of taxes?

Craig Clark

No I think that our loss carry forwards are helping us out here and we’re in fine shape in terms of our tax horizon I still feel that we can safely project 1% or less cash tax.

Andrew Coleman - UBS

Okay. And then stepping back to the operation side here. Assuming you have plenty of capacity in the Granite Wash and do you decide the ramp up activities is that true?

David Keyte

Pipeline capacity

Andrew Coleman - UBS

Yes.

David Keyte

Yes it is we’ve got five different purchasers in the Granite Wash area, and all of them have excess takeaway capacity, all of them currently have underutilized plan capacity as all five purchasers due process liquids and we own most of our own gathering system.

Andrew Coleman - UBS

Okay. And then do you think, and since there is nothing disclosed here, if I think about reserve bookings in the first half of the year, is it probably a first statement that most of the reserve bookings that you would have bought will come from revisions and performance due to lower costs or should I think about reserve bookings being entirely back and loaded for the year?

Craig Clark

No, some guided reserves, but this year you’ll get some reserves back on the revision side from prices to year end, but specifically you give some help on cost which is back in, you’ll get some help on future development cost, and I’m assuming the old rules, and we’ve been pretty conservative with that going forward.

Then this year it will be the first year you will have the influx of things like your Buffalo horizontal and Haynesville wells, which we noted at year end were not significant or material at that time. So the drilling program will carry the mail for the big wells. Year-to-date we are still down on prices, and so those numbers will be down, but the drill bit is what’s contributing all the reserves this year.

Craig Clark

You’ll get some revisions on your performance, and we’ll see what year end holds. Right now you’ll get a little help on all of the above, except the gas price.

Andrew Coleman - UBS

Last question, and as you move into the Hawaii, I guess since you are cataloging the Granite Wash play at the moment, as you move into 2010, would you see any need to bring in a JV partner to develop that 90,000 acre position?

Craig Clark

Not for the Granite Wash, because it’s not that expensive compared to something like the Haynesville.

Operator

Your next question comes from Ray Deacon - Richard Capital.

Ray Deacon - Richard Capital

I was wondering, can you just tell me the non-operated activity in the Granite Wash, what counties are those. Then I guess I know you feel like the EURs are 6 Bcf on these horizontals. What kind of data set is that based of off. I think this is my question?

David Keyte

Activity on the OBO side has been scattered throughout the play. So we’ve been able to see OBOs from Mendota Ranch to north of Buffalo Wallow, down into the Southeast accentual acreage, so it covers it down. We have participated in eight horizontals to date that we have all the production information on, so the decline curve is based on a compilation of our own vertical wells and 7 OBO wells, one operated well.

Craig Clark

Ray, this is Craig on the decline curve. We took the vertical decline curves and paralleled them as we noted in East Texas Cotton Valley, the jury still I don’t know whether singling one’s own horizontal shells will decline curve up, which is what happened in East Texas. Our tight curve does not assume that improvement at this time. So basically we took a vertical well decline curve as our type curve which I think is probably a little pessimistic compared to some.

Operator

(Operator Instructions). Your next question comes from Ken Carroll - Johnson Rice.

Ken Carroll - Johnson Rice

Just a quick question up in Canada; any thought at putting a rig back to work at the play point and working some of the projects out there?

Craig Clark

That’s what EV is Ken. The horizontal that we tried vertically and then horizontal, that is actually EV and yes, when starting back up as we speak after break up the curve in June.

Ken Carroll - Johnson Rice

What are your plans for [Inaudible] in terms of the number of wells?

David Keyte

We’re looking at either one or two rig program for EV, we haven’t finalized that yet, so it would be somewhere between probably five to ten wells.

Craig Clark

Maybe all be horizontal in this case. We did a mixture two years ago, but these are all horizontal.

Ken Carroll - Johnson Rice

To refresh my memory, I think the last time you were looking at is getting approval for down spacing 80 acres, has that happened yet or are you still waiting for that?

David Keyte

No I don’t think that we’ve got 80 acre down spacing for EVS, so what we would be doing is drilling on the expanded spacing at the current time.

Craig Clark

Actually there is a offset operator that actually have down space verticals to even less than that at EV, you are not confusing that with Wild River where we got approval to go past 160 in the first quarter, are you?

Ken Carroll - Johnson Rice

No, I’m thinking back under there was I guess at the last analyst meeting, some discussion that the down spacing application have been submitted?

Craig Clark

There is actually I believe some 40 acre folks out there, but we are not near down space and we added some acreage to it so our acreage is pretty thinly drilled, and I think we frilled for horizontals at this point.

Operator

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

Patrick Redmond

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

Operator

This concludes today’s conference call. Thank you for your participation, you may now disconnect.

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Source: Forest Oil Corp. Q2 2009 Earnings Call Transcript
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