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Forest Oil Corp. (NYSE:FST)

Q1 FY08 Earnings Call

May 6, 2008, 11:00 AM

Executives

Patrick J. Redmond - Director of IR

David H. Keyte - EVP and CFO

J.C. Ridens - EVP and COO

H. Craig Clark - President and CEO

Analysts

Brian Singer - Goldman Sachs

Gil Yang - Citigroup

David Tameron - Wachovia

Andrew Coleman - UBS

Operator

Good morning, my name is Heather and I'll be your conference operator today. At this time I would welcome everyone to the Forest Oil First Quarter 2008 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be question-and-answer session. [Operator Instructions]. Thank you Mr. Redmond you may began your conference.

Patrick J. Redmond - Director of Investor Relations

Thank you. Good morning. I want to thank you for participating in our first quarter 2008 earning conference call. We have joining us today Craig Clark, President and CEO; David Keyte, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and Chief Operating Officer.

Before we get started I would like to take a moment to advise you about our forward-looking statements within the meaning of Section 27A, of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. All statements other than statements of historical fact that address activities and outcomes that Forest expects, assumes, plans, believes, budgets, forecast, projects, estimates, or anticipates and other similar expression will, should, or may occur in the future are forward-looking statements. These forward-looking statements are based on the current belief and assumptions of management using currently available information as to the outcome and timing of future events and are subjected to all the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and natural gas. These risks made many of which are difficult to predict and many of which are beyond our control include but are not limited to price volatility, the uncertainty inherent in estimating future oil and gas reserves and future oil and natural gas production, cash flows and the timing of development expenditures, the lack of availability of drilling and production equipment and services, the risks incident to drilling oil and gas wells and other operating risks, environmental risks, regulatory changes, foreign currency exchange rates, and other risks described in reports that Forest files with the Securities and Exchange Commission including its annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K. Any of these factors could cause Forest's actual results and plans to differ materially from those expressed in any forward-looking statements. I will now turn the call over to Dave Keyte. Thank you.

David H. Keyte - Executive Vice President and Chief Financial Officer

Thanks Pat. Good morning and thanks to all for listening in on this blistering trading day in the E&P and commodity sectors. The first quarter came in about as expected at Forest with positive surprises and prize realizations reigned better than expected earning and cash flows. In the first quarter we posted a new record of adjusted earnings of $93 million or $1.06 a share, posted new record adjusted EBITDA of $294 million as well as a new record for discretionary cash flow of $265 million or $3.04 a share.

With increased prices and an anticipated 5% to 6.5% production increase sequentially in the second quarter, we seem to be on pace to post new records again in Q2. In the first quarter we produced $478 million equivalent to today, the production mix was 74% natural gas, 15% crude, and 11% NGLs. Like last quarter, increased cash margins were the key to our record performance. Improved cash margins per Mcfe were driven by $1.95 increase per revenue... I am sorry, in revenue per unit and a $0.68 decrease in cash cost per unit compared to the corresponding period in 2007. That resulted in cash margins of $6.23 per unit in 2007 versus $3.60 in 2006... I am sorry, '08 versus '07 were 73% increase.

Despite the increase in NYMEX gas prices during the quarter, differentials remained tight across the board demonstrating strong physical markets. Our gas differentials averaged $0.78 per Mcf versus $0.80 per Mcf last year when NYMEX was a $1.27 lower. All categories of cash costs were improved over last year with per unit cash cost of $2.43 which is 22% below those recorded last year. The upgrade in our portfolio from 2007 replacing $450 million worth of Alaska offshore crude assets were $500 million of high quality Cotton Valley assets certainly helped here. DD&A was a bit lower than expected as drilling costs per unit in the first quarter were less than anticipated. We believe this reflects not only slightly lower costs to drill but slight improvements in expected recoveries as well.

As we promised in our analyst presentation on April 1st, we plan on increasing our capital spending in 2008 to a range surrounding $1.2 billion. This implies a quarterly spending rate of about $300 million to $325 million per quarter each for the next 3 quarters up 20% to 30% over our first quarter spend rate. This drilling program should allow us to grow production organically at an annualized rate of 15% beginning in the second quarter. Production will also receive a boost from our Ark-La-Tex acquisition and the associated 3 rig program on these assets.

As a result of the increased CapEx and our acquisition we expect production will grow sequentially 5% to 6.5% in the second quarter off of the $478 million a day Q1 base, 5% to 6.5% sequentially once again in the third quarter, and then 3% to 4% sequentially in the fourth quarter resulting in a range of $545 million to $560 million equivalents a day average in the fourth quarter. These estimates do not consider any loss of production from our western business unit property package. This property package is expected to be approximately $35 million to $40 million equivalents a day. We hope to close it by late third quarter. When that transaction closes we'll once again adjust our guidance to reflect those sales due to their significance.

In summary we had a first quarter where year-over-year production units were up 58% and margin per units were up 73%. Production is still trending up as is our margin per unit. Our CapEx program is targeted to deliver 15% organic growth without considering acquisitions or contributions from our frontier program and will easily be financed internally. And finally the company has ample liquidity to make further bolt on acquisitions should they present themselves. I would say that's pretty well positioned. I will now turn it over to J.C Ridens who will review first quarter operational highlights and more detail on the increased CapEx plan.

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

Thanks Dave. Since we did an extensive review of our assets at the New York City Analyst Conference I am going to focus the operational comments primarily on the areas where we are going to increase capital this year. Western business unit, in Buffalo Wallow field we increased our rig count to 6 rigs in line with our stated goal of increasing activity in our growth assets. Production from the field did a new record of 51 million cubic feet per day in the first quarter with 17 new wells drilled. The rates from these wells range from 1.6 million cubic feed to 7.5 million cubic feet per day with the average being about 4.4 million a day. We are yet to drill a dry hole in this field and importantly we have had success in two new sections in the extensional area.

We drilled 3 wells in these sections and achieved IP's between 5.6 million and 6.5 million cubic feet per day. We haven't drilled the horizontal well in this field yet due to the rates achieved from commingling the Granite Wash and Atoka intervals which have in cases exceeded the horizontal rates achieved by other operators. Although we have added a 6th rig, we are planning on further increasing drilling activity in the field based on our successful program here. In the Vermejo/Haley Area we successfully reentered and completed a well with an IP of 2 million a day. We have a second reentry planned for the second quarter.

With the completion of our extensive seismic evaluation of the area we are also mobilizing a rig to drill a new well to be Atoka Morrow formations. After the drilling of this well we have got a second one planned in 2008 as well. Our acreage position in this place over 40,000 acres and as we have pointed out at the analyst conference in New York this one of the on tour [ph] place where you can really move the needle with a successful well.

Moving over to the eastern business unit, our success in the horizontal program in the Cotton Valley continues with the third well completed achieving an IP of 5.5 million cubic feet per day. We have two more drills getting ready for completion. Production in this area reached a new record of 55 million cubic feet per day in the quarter with 15 new wells drilled. We currently run at 5 rigs with two dedicated to the horizontal program. The business unit is ready to take down the new acquisition, utilizing an initial two wells... two rig program with plans to ramp the rig count up to as many as five by the end of the year. Our plans will include evaluation of the Haynesville Shale as well as continued exploitation of the Cotton Valley and Travis Peak formations.

Part of this exploitation may very well involve horizontal drilling based on our success with our current programs. We going to add a fourth rig in the Arkoma Basin to increase the pace of development. We drilled 17 wells in this area during the first quarter with IP ranging from 1.1 million to 3.7 million cubic feet per day. Our thermal production averaged to about 39 million cubic feet per day during the quarter. We been participating in a horizontal program and our joint venture area here are more encouraged by the results of some of the latest wells. We have also stepped up activity in the Barnett Shale, adding a second rig to deploy so we have one running in Hill County and now one also running in Erath. In Hill County our IPS remains in a 1.5 million to 2 million a day range.

The southern business units, we increased the rig count fire bricks [ph] in the business units early in the year as our seismic evaluations increased our inventory. We have seen production come back after we predicted it would with the increase in activity. We drilled 10 wells during the quarter with IP's as high as 7.5 million cubic feet per day. We have rigs running in Charco, Rincon, and TCB fields now and have had success in all three. Notably our first Vicksburg well drilled in Rincon this year IP'd for over 5 million cubic feet per day.

We continue our string of success with Katy field as well, having drilled another infill low cost well for over 2 million cubic feet per day and are looking to increase the capital of this field to execute another multi well program later in the year. Moving up to Canada, the big story here this quarter was the successful application of horizontal drilling technology at the EV oilfield. We drilled 2 horizontal wells that had IP's of approximately 300 barrels of oil per day. This is about 5 times what the 11 vertical wells that were drilled in the quarter averaged. With the success achieved here, we plan on increasing the capital program for this field with additional horizontals to be drilled later in the year.

We reached a new record for production of 46 million cubic feet per day in the deep basin based upon drilling 18 wells in the quarter primarily at Wild River. IP's from the winter drilling program were as high as 5 million cubic feet per day and our re-completion program of behind pipe zones has resulted in plans to drill a horizontal well in this field as well. After break up, we'll resume another drilling program and you can bet on increased capital here also.

New ventures, this group as you would expect is highly focused on getting the horizontal wells permitted and drilled in the Utica Shale during the summer of 2008. Permits have been filed and we have a contract for the rig with plans to get three horizontals done. Two will be grassroots wells and one will be a re-entry. Our pile up program conducted last winter showed, we can successfully fracture stimulate the shale and it contains high quality gas. The next step is to determine how much we can increase the productivity with the horizontal well bore in multi stage frac job. With 339,000 gross acres here, we have a lot of running in the success case. And with that I will turn it over to Craig for concluding remarks.

H. Craig Clark - President and Chief Executive Officer

Thanks J.C and thanks to those listening today. I would be remiss without starting my comments with a big thank you for Forrest Hoglund who is retiring this week as our non-Executive Chairman. He was the catalyst for change four years ago and his foot prints were all over this company. Thank you Mr. Hoglund. Although we beat First Call estimates on earnings as Dave covered in detail, the first quarter was pretty much as we had forecasted. We had some notable records across the board but the records I want to highlight are the production records that J.C. talk about in Buffalo Wallow, East Texas deep basin, which are primarily the areas we are going to increase capital spending. We found success. This is the main reason we designed a portfolio in this manner until our capital reallocation or acceleration are having these legacy assets to drive our future results for many years to come.

At our recent analyst conference which by the way we received much positive feedback, we highlighted over 15,000 unbooked potential build sites most of which are over 2/3rds claim from our tight gas areas. It was nice also during the quarter since many of our plays and prospect quality validated by offset competitor, this came from both vertical and horizontal completions. The offset activity included Granite Wash and Atoka and the Texas Panhandle, Haynesville, Bossier in East Texas and North Louisiana including near our recent acquisition and the Cotton Valley Travis Peak in East Texas. And we helped ourselves by validating horizontal success in East Texas, Arkoma Basin, and the Canadian oil EV and also in our Barnett Shale play in the first quarter.

We'll add horizontal activity in several areas in the second quarter which will include the Travis Peak, the Bossier, Atoka, and Canada's deep basin, and the Utica Shale that J.C. talked about. Again as I a said repeatedly, at the conference this portfolio has as much upside as any company; some of our plays are key plays for companies a lot bigger than Forest. We will also be drilling exploration projects in the second and third quarters. We highlighted some of those at the conference, that includes the South Texas Wilcox, South Louisiana Deep, East Texas Deep Chalk and Hailey/Vermejo. This upside or exploration piece was not tabulated in the potential Tcfe we showed at the analyst conference slide.

For the first quarter of 2008, the highlights were summarized as follows; financial operating records that Dave covered earlier, net production records at Buffalo Wallow East Texas, Canada Deep Basin, Katy, etcetera. Horizontal success that was well above our expectations in East Texas, well above our economic slide in the Cotton Valley and in Canada's EV oil field. We also made and closed an attractive acquisition in the Ark-La-Tex area, in fact we closed it early, last Friday on May 2nd, taking over operations immediately. This acquisition added 69,000 gross and roughly 49,000 net acres. We also made a smaller acquisition of 3000 gross acres in our core East Texas Cotton Valley play during the quarter. We continued to consolidate this year where our total acreage is now risen to a 147,000 gross acres as much as some companies here.

We are prepared to go to the data room in our western property divestiture as Dave said in June, closings expected in the third quarter. We've got off to head start in April on the divestitures with about 30 million signed to date. We reallocated capital and ramped up drilling activity already starting in April being still able to enforce capital efficiency in our program. We ramped up drilling used in exploration properties specifically South Texas with early success that J.C. noted. We showed a plot of the Charco field response at the analyst conference. There is not really much left in integration on the Houston exploration acquisition and as we show this acquisition, look back looks pretty well. We held the line on cost down from a year ago despite the pressure imposed by winter and commodity related taxes in fuel.

We forget sometimes but our NGL volumes which was a corporate initiative a few years ago are now at a record. This helped narrow the differentials somewhat due to increased recoveries and better contracts. We have now developed an extensive inventory of over 15,000 unbooked locations with 10 Tcf of un-risked potential mostly on the development side and mostly in our main focus areas. We reached a new stock price side during the quarter at over 62 a share and last but not least affected this week we will have new non-Executive Chairman, Jim Lightner who along with Mr. Hoglund was instrumental in the design of this company and the aforementioned inventory.

I will go through the operating results very briefly, refer to our outlook and guidance for the rest of '08 which is included in the guidance that we used, as well as some future industry trends. On CapEx spending we spend $243 million on the E&D activity during the first quarter which was on a pace consistent with our prior budget and guidance. Again good capital discipline here. We build 118 gross wells at 99% success rate. I am still looking for that one, that was dry. This is the highest success rate we have had in one quarter. It reflected a rig count of about 27 operated rigs and 9 non-operated rigs. We have added rigs to our focus areas already with the exception of Canada where road bans in the spring limits second quarter activities year-over-year.

So we are good ways down the road and increasing the activity associated with the higher capital budget. On the cost side related to this CapEx we did our big services tangible and intangible for all of 2008 except rig day rates. We may see some pressure to increase day rates later this year or I believe it will be mostly in the lower 48 North Canada. We do forecast however, and our capital budget includes this what I would call higher booked commodities in 2008. We may see some increases on steel, frac platform, and cement [ph] which may dent some of our savings. We included these cost projections in our guidance.

Our guidance on capital also includes the Ark-La-Tex acquisition which adds approximately $50 million in capital for 2008. On the production side we average 478 million equivalents for the quarter, the volume includes a full quarter of Shell Waterton plant shut in and the South Texas Rincon reversion our interest. Our guidance was increased to reflect the new CapEx spending plan and also includes the $30 million of property sold today. So in depth with an annualized organic growth rate of around 15% although its up 58% from 2007 along with the transactions. Dave detailed each quarters so there is no confusion.

It is refreshing to see our CapEx versus our organic growth, however, growing 3 ways. First, when we increased CapEx we increased production of the guidance or vice versa. Secondly, with only slightly over spending cash flow we get to 15% organic growth, not bad. And third, we are just now at the combine 2006 to 2007 capital spending level of both Houston exploration in Forest that they had before the mergers. But now the efficiencies were there and you saw that in our year-end finding cost.

On the cash cost side, however, we decreased from a year ago, we saw a slight increase from last quarter, it's simply winter weather, the commodity price related to production tax, however, we were able to offset most of this with our project focus cost control measures. We increased our guidance slightly on cost due to simply higher taxes and higher direct cost and higher commodity prices that would cost us higher fuel cost. We see the same fuel cost increases for electricity and diesel as the consumer sees. We also wrapped up our work over activity in some area most specifically in South Texas from the Houston exploration property base.

So now we turn the attention to more activity while upgrading the portfolio even more. Our newest acquisition will gain a lot of attention as we do our thing with increased activity. We took over at closing, we plan on taking the rig count as J.C. said from 2 to 5 later this year including horizontal activity. The acquisition metrics look favorable especially considering all the news that has come out of this Ark-La-Tex area since the acquisition was announced. This is a very good consolidation area for us. The Ark-La-Tex transaction puts Eastern and Western and Southern race to be the biggest producing business unit. This is impressive considering Southern and Eastern didn't even exist a few year ago and Western has tripled in size.

In conclusion although the current commodity price environment today would not result in over spending in our current budget. We are confident that the shipping strategy more importantly in capital allocation will produce a higher organic growth rate while maintaining our capital efficiency. Folks, margin extraction, and capital discipline still remain. And now I will turn the call over to the operator for questions. Operator.

Question And Answer

Operator

[Operator Instructions]. Our first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you, good morning.

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

Good morning Brian.

Brian Singer - Goldman Sachs

In the Cotton Valley play, what are you seeing in terms of declines from some of the newer wells that you have drilling and could you separately touch again on the specifics of your severe Haynesville test plans?

Unidentified Company Representative

On the decline at the analyst conference we showed a comparable decline of the Cotton Valley that parallels the vertical wells. Its possible that the decline would be less because we are in the supposedly the best zone interval but if you note that curve we use the same hyperbolic decline although the rates were higher in that thing that's probably a conservative assumption at this time but that's what we use. We also in our economics showed a lower rate. In the Haynesville, that zone is the Bossier as well and we will test that because its an elegist to the vertically to what we did in Atoka and Buffalo Wallow. You can drill it and add it because its right below the Cotton Valley. It has not been tested on the newest acquisition although we tested it time or two on our previous East Texas properties. I call the Bossier though because we have been on the Texas side mostly, however, there is activity over there as well and we also get it behind pipe.

Brian Singer - Goldman Sachs

Great and I guess how many additional tests should we expect in the next few quarters based on your accelerating drilling program for the Haynesville or Bossier specifically?

Unidentified Company Representative

I don't know that number, do you J.C.

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

No, I think that the right answer there Brian is that we will want to take one of the new assets on the acquisition that we just made down and test that over our Louisiana side. We are already talking about expanding activities on the East Texas side in the vertical sense before we take a horizontal [ph].

Brian Singer - Goldman Sachs

In Buffalo Wallow and I might have been confused but I thought you made a reference to not having him drill a horizontal well there which made me wonder are you going to... are you thinking about drilling horizontally at Buffalo Wallow?

Unidentified Company Representative

We continue to watch the activity of the offsets Brian but frankly when we commingle the Granite Wash and Atoka we are getting IP's that are so good that we are having trouble to deciding on which is the zones we should go horizontally in. Because our IP is there with rate seen as high as 7.5 million a day, with contributions from all zones in the Granite Wash and the Atoka, really thanks to the questions which zone would you select.

Unidentified Company Representative

Well why would you do it.

Unidentified Company Representative

The rest is horizontal activity offset in one of 4 or 5 Granite Wash zones that come in at rates comparable to our verticals although you need the higher rate for the horizontal because of the cost and then the Atoka which is the new news of the day also mirrors the average well. We will test before we go horizontal each zone vertically and we have tested the horizontal, we have tested the Atoka in almost every well we have drilled since the acquisition.

Brian Singer - Goldman Sachs

Great, thanks.

Operator

[Operator Instructions]. Our next question comes from the line of Gil Yang with Citigroup.

Gil Yang - Citigroup

Hi, just following on with that... is it possible at all to drill stag horizontals or there are just too many in Buffalo Wallow, there are just too many pricing formation to do that reasonably?

Unidentified Company Representative

Not aware of anybody doing that currently in the tight gas, another drilling co-plane of multiple laterals which go different directions. I'm not anywhere, where they get to behind tight zones and do stags because of the mechanical complications. However you do get the opportunity if you start deep, as we pointed out at the analyst conference, Mark Bush pointed out, if we start for instance the lower zone like the Cotton Valley, you still have all those zone behind pipe for future use.

Gil Yang - Citigroup

Okay, so it is something for the future.

Unidentified Company Representative

Yes, I'm not aware of any duel stacked levels at this time.

Gil Yang - Citigroup

Okay. For the Utica tests that you are going to be running this summer, is it solely, can you give us an idea of what you are looking for in terms of are you just testing new frac technologies or are you also try to step away from the original discovery well that you made?

Unidentified Company Representative

The first two Gil are going to be twins to the vertical wells, and the sole purpose for growing horizontal is to see what sort of productivity increase we get from multi-stage fracs of a horizontal well. We don't really need to test anything new on the fracture technique, we already did that in our pile up program showing that rock can be the fracture stimulated success.

Gil Yang - Citigroup

and then the reentry, is that sort of a step far away or is it just sort of a step out or --

Unidentified Company Representative

The step out we had a vertical well that was left in an uncased fashion by the operator for us so we can go in and turn that into a horizontal well and get an extension test as well.

Gil Yang - Citigroup

And how far will that one be away from the other wells that you have drilled?

Unidentified Company Representative

In the scale of miles, it's not going to be a 100 acre offset or anything like that.

Unidentified Company Representative

We did get the wells to reenter and we prepared one for that and then we spread the math throughout the acreage as the first two were, but we haven't spotted them for competitive reasons.

Gil Yang - Citigroup

Okay and then you mentioned that you are not trying to do anything with the frac techniques right now. I presume though that you don't think that the frac recipe optimizes as poor yet so at what point would you start looking at that?

Unidentified Company Representative

Well, I think that the answer there is you're right it's not optimized. Our goal here is to see what we can get out of a four stage crack in one of these horizontals and then work on optimization as the next stage of the game.

Gil Yang - Citigroup

Okay so that would be presumably in the next set of wells if these are successful?

Unidentified Company Representative

Right.

Gil Yang - Citigroup

Okay, thank you.

Operator

Our next question comes from Gordan Dalcot [ph] with Wachovia.

David Tameron - Wachovia

Hey. It is Dave Tameron. Couple of questions for you, if I look at -- Craig you mentioned where you are going be drilling horizontal. I think you mentioned in 4 or 5 years, how is that compared to what you thought 6 months ago?

Unidentified Company Representative

Well 6 months ago the only thing that maybe even a year ago, we were focused on horizontally of course the Shale's you are always going to do that. But at that time the only buzz was I would say the East Texas Cotton Valley and now you've expanded that to I would just say most tight gas areas and you've also expanded to factory carbonates and now shale's and those same basins. So, you have got multiple horizontal plays going on in a place like East Texas. It's safe to say that I think everybody is not only putting Shale's under a microscope, but their putting horizontals under a microscope where they had typically done verticals before. I do think that on the tight gas side which we have a lot of, that maybe as impacted today for companies such as Forest and us in others more so than the Shales because the frac technology has already been protected many, many years ago. So the answer is we are looking at it in all areas but the initial focus for us is on the carbonate but more specifically tight gas on.

David Tameron - Wachovia

Okay and as far as rig, what type of rig do you need to do a horizontal versus vertical, are those rigs plentiful but that horizontal drilling is that market can tail along, can you talk a little bit about that?

Unidentified Company Representative

Some places requires a bigger rig with bigger pumps. I don't think you have to have a special purposed rig or top drive that may help in some case. So, I don't think that in terms of how we were operating that causes it to be a tremendously bigger rig. What it does, you basically able to use better drill pipe, steel and directional services. I think that would be more critical issue than the rigs particularly since our so many new builds still coming out.

David Tameron - Wachovia

Alright. Deep in Louisiana, have you guys, I think you talked about perhaps getting a partner for that play. I know you are going to say you will drill the second half of the... partner lined up yet?

Unidentified Company Representative

We have a partner lined up for I think all but one of them. Clearly the answer is yes on all of them but all but one of them, the Deep one, and basically they are multiple people bidding against each other for that. We are trying to take a half from out of the rest or get a bonus upfront just like we went on any exploration projects. So, typically we will going in those with about half interest and some of the shallow ones we might have it at 75.

David Tameron - Wachovia

Okay and remind me what was size of that, pre-drill pipe number?

Unidentified Company Representative

In excess of 300 Bcf I believe, we only showed one. There were 4 or 5 shallow ones, they are barge jobs, and the one we showed was called Dalaila [ph] which is a Western offset to the discovery that Freeport had several years ago and as a remainder its actually underneath our West White Lake [ph] field that we acquired from Unical [ph]. It was our 3D seismic that led us to that 20/20 gross on risk was the number David.

David Tameron - Wachovia

Okay.

Unidentified Company Representative

And its about 18,000 foot matching test. Typically we will end up with about half the interest in their duel promote.

Unidentified Company Representative

Under the hedges were [indiscernible].

David Tameron - Wachovia

Okay, one more question for you. If I look at 2009 to 2010, even back half of this year excess cash generation, I mean this year it looks like you are able to spend with the cash flow even though the ramp capital budget, what does that look like for next year?

Unidentified Company Representative

We are not going to obviously predict '09 at this point. As said, we are... it was interesting to try and keep chasing this price that we thought we would be outspending cash flow by about 10%. Now we are, your forecast is same about even our internal forecast is probably right on there too. It is just hard to tell. I think that we need to get through summer and we will make CapEx and price call during the regular budget period.

David Tameron - Wachovia

And then what you do with the excess cash?

[Multiple Speakers]

Unidentified Company Representative

Well, I never seen a credit card company go a year without an acquisition so we will see what happens. My guess is there will be some thing that will catch Craig and J.C.'s eye between now and then.

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

The one thing I will say is when I revised capital we did not chase the price cover. We had the incremental capital, then we talked about the analyst conference and the acquisition based on the assumptions for some of the tangibles like steel. So pretty much it adds up. We did not make an attempt to chase our cash flow up with the commodities as it had risen substantially in the last 2 months.

David Tameron - Wachovia

All right. I will let somebody else jump on thanks.

Unidentified Company Representative

Thank you Dave.

Operator

Our next question comes from the line of Andrew Coleman with UBS.

Andrew Coleman - UBS

Hey, good morning folks.

Unidentified Company Representative

Good morning Andrew.

Andrew Coleman - UBS

I had a couple of questions here. Looking at, I guess if you could walk me through how you would stimulate the carbonates versus the Shales, I always thought that carbonate is just like a straight asset frac?

Unidentified Company Representative

Do both on the carbonates. The carbonates could be sand frac, they can be asset frac where we are edging natural factors, that's the difference like the old Austin Chalk Maze. On the Shales, getting out the catalog they use just about everything. What we have been doing is primarily the slick water fracs that were the prevalent frac in Barnett Shale, those are what we did in the Utica Shale as well. Basically we are just breaking the rock up with minimal sand and high rate but the carbonates are stimulated more similarly to a sand stone.

Andrew Coleman - UBS

Okay. And then I guess keep the cost all relatively tightly dispersed there regardless of what formation you are in?

Unidentified Company Representative

Well the slick water fracs that you use on the Shales and in some cases the tight gas sands are very, very cheap. Its not a lot of jail, it's a little bit of sand, and a lot of horse power. The more exotic fracs like acid fracs or high [ph] sand fracs are more expensive. And what you have seen in my opinion in the last few years if the fracs have not gotten bigger they have gotten smaller and we have made a conservative attempt as an industry to commoditize the fractures simulation job. And resulted in some significant decreases in the out well cost like at Buffalo Wallow.

Andrew Coleman - UBS

Okay. And then looking at the stuff you are going to test there in the Bossier you said in the Texas side is that going to be the Shale section or one of the carbonator sand.

Unidentified Company Representative

Well you get -- I'll answer mostly the Shale section although there is several Bossier plays all the way down Freestone and Limestone County all the way up to Louisiana border that have a Bossier sand in it. And of course you've got a Deep Bossier play going on down in Leon and Robertson County that provided some pretty high rates from the Bossier and that's both, a Bossier sand and a Bossier Shale.

Andrew Coleman - UBS

Okay, thank you. Are you guys a little depth limited on any of the acreage in East Texas or Louisiana?

Unidentified Company Representative

There is some severance in some but for the most part, it's not broke up.

Andrew Coleman - UBS

Okay, then last two questions then, how close are you guys to that EnCana wells, you talked to 3H or something?

Unidentified Company Representative

Well, if you're talking about the ultra big Bossier --

Andrew Coleman - UBS

I think it's the Haynesville one.

Unidentified Company Representative

Where are you at, Louisiana or Texas?

Andrew Coleman - UBS

Thinking about Arkoma, Texas purchase you guys made.

Unidentified Company Representative

Yes, we are... where are you at.

Andrew Coleman - UBS

Louisiana.

Unidentified Company Representative

Okay, I am not familiar with where that well is located. Our Ark-La-Tex area acreage and there's a map in the analyst conference and our road show, its from Freeport over and its mostly around the Woodardville area. I am not aware of in Canada although they are active, South of Vernon [ph], I think that will be East of us but I can't spot that well.

Andrew Coleman - UBS

Okay, so I will double check. And lastly looking at the Utica, do you guys have any... I guess, what kind of pipeline capacity do you have available to you as a drilling to over the next couple of years?

Unidentified Company Representative

200 million to 400 million cubic feet per day of TCPL.

Andrew Coleman - UBS

All right, that is for me. Thanks a lot, appreciate the question there.

Unidentified Company Representative

Thanks Andrew.

Operator

There are no further questions at this time, are there any closing remarks?

Patrick J. Redmond - Director of Investor Relations

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

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

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Source: Forest Oil Corp. Q1 2008 Earnings Call Transcript
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