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Executives

Patrick Redmond - Director, IR

Dave Keyte - EVP and CFO

Craig Clark - President and CEO

J.C. Ridens - EVP and COO

Analysts

Scott Hanold - RBC Capital Markets

David Tameron - Wachovia

Gil Yang - Citi

Kevin Smith - Raymond James

Andrew Coleman - UBS

Forest Oil Corp. (FST) Q1 2009 Earnings Call May 5, 2009 10:00 AM ET

Operator

Welcome everyone to the Forest Oil first quarter 2009 earnings call. (Operator Instructions).

I would now like to turn the call over to Mr. Patrick Redmond.

Patrick Redmond

Thank you and good morning. I want to thank you for participating in our first quarter 2009 Earnings Call. I will also note that a replay of this conference call will be available through May 19, 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.

I'd like to caution you about our forward-looking statements. All statements other than statements of historical facts that address activities and outcomes that Forest expects, assumes, plans, believes, budgets, forecasts, projects, estimates 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 Dave Keyte. Thank you.

Dave Keyte

Thanks, Pat, and good morning. Thanks to all for listening in on a day when, at least in Texas and in Denver, cooling season has finally arrived. First quarter results for Forest were better than we had expected as production volumes held up well against decreasing rig activity and cost containment efforts continued to show positive results.

Included in our GAAP earnings for the first quarter was a ceiling test charge for approximately $1.2 billion after-tax due to decrease in natural gas prices in the quarter as well as the fact that we do not use hedge accounting. Because we do not use hedge accounting, we can mitigate this type of impairment with the increase in the value of our hedges like some others. The fair value of our hedges using ceiling test pricing at quarter-end was approximately $400 million.

In the first quarter, adjusted earnings were $28 million or $0.29 a share, down 70% from last year due to a 37% decrease in realized prices. Adjusted EBITDA for the quarter was $193 million, and discretionary cash flow $157 million or $1.64 a share. Both of these were down substantially from last year due to lower price realizations. However, the results were bolstered somewhat by decreased costs, which Craig will discuss later.

Gas differentials finally saw some minor firming as they were $1.27 in the first quarter versus $2.01 in the fourth quarter of 2008. Despite this, Forest still realized a gain of about $0.10 per Mcfe relating to our hedging of basis in the quarter. The wide basis differential at all U.S. delivery points remains perplexing. Only Canadian basis seems to be normal at this point in time.

DD&A was $2.11 per Mcfe, down $0.55 or 21% from last year. This was due primarily to the ceiling test write-down in the fourth quarter of 2008. This cost per unit will be guided down further due to the ceiling test in this quarter.

During the quarter, we took further steps to help mitigate the impact of the violent downturn in the economy and the oil and gas prices on our capital structure. We termed out $600 million of our bank credit facility. As we suggested would happen on the last call, we had our borrowing base reaffirmed at $1.62 billion with no price increases, providing us with about $705 million of liquidity at March 31.

We renegotiated the leverage covenant in our bank facility to allow debt to EBITDA of 4.5 times through 2010. We renegotiated the debt definition in the leverage covenant to allow certain other types of secured lending to be disregarded in that calculation. We substantially increased our hedge position in both 2009 and 2010. Against what we saw was a very bearish near-term price scenario, we executed these prior to the recent downturn, more hedged through October than during this coming heating season.

We now entered into fixed to floating interest rate derivatives to refloat our $600 million of senior notes issued during the quarter. This was based on our view of a longer, lower economy than consensus, and it's currently saving us about 200 basis points on that debt.

Based on our near-term bearish view, we got an early start to reduction of CapEx in 2009 to ensure free cash flow generation for the year. However, as prices continue to fall, this goal keeps getting tougher to attain. Based on lower prices and actions taken to date to reduce costs, we are reducing our estimated 2009 production costs to $225 million to $255 million, down from $240 million to $275 million.

We are also reducing our estimated G&A expense to $55 million to $60 million from $57 million to $63 million. Expected DD&A charges will decrease, as I previously mentioned, due to the ceiling test in the first quarter. We're now projecting DD&A charges to be $1.50 to $1.65 per Mcfe going forward.

Overall, the company performed very well in the first quarter and held up to the substantial stress in the last six months of an 85% reduction in rig count and a 50% reduction in cash margins, locked down on both capital markets and asset sales market as liquidity sources.

Now that 2008 results are all in, we know that Forest once again gained ground in the cost structure compared to others in the industry. It looks like in 2009 so far, we are gaining further.

At such time as we begin to drill in earnest again, Forest is extremely well positioned to perform at an optimal level of efficiency. Our two main assets, Ark-La-Tex and Buffalo Wallow, have demonstrated superior results from recent horizontal drilling far in excess of our expectations. These assets using new technology should grow substantially faster than they had before, which was still pretty good, and our cost structure will turn us to profitability long before our competitors. We remain the best risk-weighted investment in the E&P space.

With that, I'll turn it over to Craig.

Craig Clark

Thanks, Dave, and thanks for those who joined in this morning. I know there are a lot of conference calls today, so I'll try and make it fairly quick. J.C. will follow me on the operations side.

The first quarter can be characterized by good momentum carried over from 2008, especially operational execution and horizontal success with even more benefits from cost control. Now, folks can see what we saw in the Granite Wash.

Despite lower drilling activity in the first quarter, we accomplished quite a bit, including getting caught up on completions and executing as scheduled the Canadian winter program in the Foothills. Production held in there and cost reduced across the board. It gave us confidence to reduce guidance early on cost.

Significant progress on horizontal projects, particularly in the Haynesville and the Granite Wash, and we've had some more good data points on our shale projects for us and others in the Haynesville, the Utica and even in our backyard in South Texas in the (inaudible). Pretty simple, we beat on adjusted earnings, did higher production and lowered cost.

Let me first address the overall industry environment as we see it today. Current natural gas prices make drilling economics tough and make costs come down. Certainly we believe gas supply will decline significantly given the current gas rig count and field storage filling due to the attractive arbitrage from the Contango shale gas drill. We do believe that rejection ended sometime in the first quarter and will magnify the implied gas supply decline.

We are bullish long term on natural gas, but cautious in '09. We have more gas hedged, as Dave mentioned, in the summer and shorter months because of this. Our 2010 gas hedges average around $6.35 per MMBtu. This tells you where our hedge is at. The basis differentials have narrowed somewhat, but not enough. We have basis hedges in place separate from our NYMEX gas hedges.

The benefit of having a portfolio in several basins or several basis differentials is we aren't trapped by one differential. The basis differential in Canada, for instance, behaved, while in the U.S. it widened.

On the drilling cost side of things, unlike early last year when we thought we would get help from service cost, we are now seeing these discounts come about, although this company has never needed service cost discounts to justify our cost cutting initiatives. We believe this is only the beginning on world cost reductions. Our decision to further reduce our rig activity is as much a call on service costs for later in 2009.

In short, we are reluctant to invest, given the costs being charged by the service providers today since the reductions to date are modest compared to the decline in net-back prices. We are seeing discounts, and these are some ranges of over 20% on the rig costs, that's workover and drilling, 15% to 30% on pumping services that are coming around, and 40% surprisingly on things like directional drilling.

All geographic areas are seeing these types of discounts except maybe East Texas where the activity is still high and mute some of the bigger discounts. We see the smallest discounts on hard products, and we had a slide on this at the analyst conference, (inaudible) mud, cement and even steel. Let's be clear. This is only the beginning of these well cost reductions, if and only if your company is diligent and aggressive in pursuing further reductions. I think we qualify.

In terms of capital spending for the quarter, we spent $245 million on E&D spending. We drilled 64 gross wells with a 95% success rate. As we planned, our quarterly capital spending reflects carryover from 2008 activity that was high, specifically completions, the end of our 2008 service discount agreements and as usual the winter drilling season in Alberta.

We began the quarter running 15 operated rigs, went to 10 during the quarter. Now, we are down to 8 today. The advantage to having Lantern rigs is we can pick them up and lay them down. This does not include the two Lantern rigs that we used for re-completions and workovers as a small part of our capital, but good enhancement projects.

Certainly we are reallocating CapEx constantly in this volatile environment. We are testing our investments at $3.50 near-term gas. Our portfolio allows reallocation, and we are seeing re-allocation opportunities to horizontals and the Buffalo Wallow, Granite Wash and Canada. Another example of our reallocation process is moving capital away from the Barnett shale, for example, to East Texas tight gas sands or the Haynesville shale where net-back prices were almost 75% better in the quarter.

We're also shifting capital to crude or high liquid yields projects. I should note that NGL prices, which have improved, add to value in places like Buffalo Wallow where as much as 20% of our overall revenue stream is enhanced. As a reminder, the Haynesville production is dry, for example.

On the other side of costs, cash cost, direct operating cost, taxes, expense G&A, were all lower. Pick one; they were all lower on a per unit basis. This is despite a high level of workovers and higher Arkansas production taxes and somewhat higher ad valorem taxes in places like Texas. No matter how you slice and dice it, whether it's year-to-year or sequential or whatever comparisons, another good job by our folks on costs.

Our behavior as executives on the cost side should mirror the good work of our employees. This early progress on the cost side let us lower our guidance across the board, as Dave mentioned. Don't forget, we preach low cost of entry in any play, and remember that when we talk about the Haynesville or Granite Wash in a few minutes.

Before J.C. covers the operations highlights in detail, I should mention a couple of notable items on our operational performance. Let me reiterate that our assets are as good a quality as any, and we were not assembled randomly. This was the plan, taking advantage of horizontal drillings and new improvement in completion technology all along.

Our newest horizontal program in the Greater Buffalo Wallow Area and the Texas Panhandle is a prime example of the good work our people have done in establishing a position early at a low cost of entry and subject to criticism by others who are not privy to our thinking on things like horizontal drilling.

We are a leader in this area, one of the most active drillers in 2008 and not the most active, and we will use our data and operational success in horizontal drilling to maintain our dominant position. Please do not assume that because we don't publicize certain activities first, we were not an early entrant into the play.

Our 120,000 gross acre position was created through leasing, form-outs and acquisition. It will prove to be a low cost of entry. We have a lot of running room here with horizontals planned both in the north and south end of our holdings. In fact, those rings are running now. As we have done in East Texas and the Cotton Valley play, we have tested individual zones in the Granite Wash, in Atoka and many areas and selected the best horizontal candidates.

The eight wells we participated in, as J.C. will note, averaged 8 million equivalents a day. Our first well was over 17 or about 17 million equivalents a day. Good well. Due to our database and testing of all the zones in the play, we have a lower risk and greater control in some other horizontal plays.

I should note three things about this play. First off, we already know how to frac these rocks, have done quite a bit, and I think 150 wells to date vertically. Second, they don't cost as much as some of the other horizontal plays because of that or because of the pressures, and they are rich in NGL yields. All of this is consistent with our plan for a typical resource play, whether it's here or whether it's Canada, and you don't necessarily have to have shales to make a good work horizontally.

J.C. will describe our Haynesville activity, no train wrecks mechanically, raised at average $8 million per day per economics. As a reminder, as we progressed through the Haynesville testing, offsets over the course that we took are over the past year. Hopefully, now you can see why we have done what we have done, including the low cost of entry in East Texas and Buffalo Wallow and the acreage included in the acquisitions, as we consolidated those two areas.

As a reminder, when I go on the road, I say, so goes East Texas and so goes Greater Buffalo Wallow, so goes Forest, and these areas have proven to be the dominant assets, but not one or the other both. We were quick to realize the value of margin extraction and cost control used in conjunction with, but not as an alternative to, technology unconventional rocks or resource play. In terms of cost control, we intend to lap the field.

J.C. will now cover our major operations highlights in the Haynesville and the Granite Wash. Stay tuned as we go horizontals in more places than just shales. J.C.?

J.C. Ridens

Thanks, Craig. If you only had two places to build the company, the Texas Panhandle in East Texas would be as good as any. Both offer the opportunity to achieve high rate wells, particularly from horizontal wells, and we have seen that in spades.

As I mentioned on the last call, we were drilling our first operated horizontal wells in the Panhandle. Today, with results in hand and more success from outside operated horizontal wells also, I will spend more time than usual discussing the Greater Buffalo Wallow area. As in the last call, more time was spent on East Texas.

I will begin today with our latest horizontal success in our Greater Buffalo Wallow area that we just completed for an initial rate of 17 million cubic feet equivalent per day.

This well was drilled with a horizontal length of 3,100 feet in the upper Granite Wash, and fracture stimulated with eight stages. As Craig previously noted, this well has a high liquid's content between NGLs and condensate, significant value is added to the base gas volume from this well, due to the higher prices liquids receive over gas.

While this is our first operated horizontal well in the play, we have participated in eight other horizontals in the Granite Wash, and the results from those have been pretty solid as well.

The average IP from those wells was 7.8 million cubic feet equivalent per day. While not nearly as good as our IP of 17 million cubic feet per day, these data points gave us confidence to begin the transition of our program from a pure vertical play to one with a larger horizontal component.

Most recently, we have participated and also drilled in other intervals horizontally here as well. A horizontal drilled in the deep proportion of the play in which we have a working interest came in for 20 million cubic feet per day, and an offset to it, which we also have a working interest is currently drilling. This is a critical data point as it shows the impact horizontal drilling can add to yet another interval in the Panhandle.

Additionally, there is horizontal drilling on our Cordillera acquisition acreage. The best well drilled to date there had an IP of 10 million cubic feet per day, and the average of the four wells drilled on our acreage at the time of the acquisition averaged 7.5 million cubic feet per day.

The programs suffered from mechanical issues before Forest acquired the assets resulting in shorter horizontals and even a junked well bore. The current well had no mechanical problems and was drilled within the targeted interval for its entire horizontal length.

When we made our latest acquisition, we noted the horizontal potential and the results have exceeded our expectations. This shows once again, why we not only love horizontal drilling but are also very happy with our extensive position in the Panhandle, where we can see multiple horizontal targets.

A plan for the remainder of the year is to operate our 1,500 horsepower Lantern rig, which we moved there specifically for deeper applications, including horizontals, as well as continuing the development of our non-operated position. We have significant running room in the Panhandle, and we tend to exploit it.

We have always said the Buffalo Wallow and East Texas were the linchpins of the company. As goes those assets, so goes Forest, and we are very pleased that we now have two business units drilling high rate horizontal wells.

With that, I will transition to East Texas.

The Eastern business unit is continuing a Haynesville program that got off to a hot start last quarter with the wells that had an initial production rate of 14 million cubic equivalent per day. While they exceeded the Granite Wash well on a pure gas rate, due to the liquids content of the Granite Wash, they lost on total IP.

However, they are maintaining good rates on the Haynesville program with the average IP of the first three wells being 8 million cubic feet equivalent per day. That average IP fits almost exactly to the IP that we used for our type curve, which was 7.8 million cubic feet per day. That type curve was built for the Haynesville in total, not just one area since our acreage is so expansive in this play.

We currently have one well down in Central Harrison County, that will be fracked in the next two weeks, and we are drilling an offset to our first high rate well in the Red River Parish.

A third exploratory well is drilling in Sabine Parish, where our targets of the Haynesville Lime, Haynesville Shale and the James Lime. Having three different perspective targets is very appealing in this area, and we will pick the best looking of the three for our horizontal well bore.

While, I'm on the subject of having different perspective targets, I would be remiss if I did not remind you that our entire horizontal Haynesville program was developed based on the success we had, and continue to have in the horizontal Cotton Valley. Indeed, all of our horizontal drilling even in Canada can trace its roots back to the work that we began in the Cotton Valley.

We continue to have both mechanical and reservoir success in that play, and continue to get good results from that program with the last well having an initial rate of 5 million cubic feet equivalent per day, despite being rate restricted due to pipeline capacity.

The Cotton Valley isn't the only shallow pay zone working for us in East Texas. Our Travis Peak program is alive and well, and we have achieved IPs of over 9 million cubic feet per day from wells there as well.

Those rates are from vertical wells, so not all of our success is horizontal, but a good portion of it is, as evidenced by the last well drilled horizontally in the Arkoma Basin, which tested 10 million cubic feet per day.

As we announced previously, we have conducted no further work in Quebec, while we complete our technical analysis. However, two good data points were announced by one of our competitors from vertical wells within the play. We will incorporate those results into our study with an eye on resuming activity when our analysis is complete.

With gas prices continuing to be depressed, our focus for the remainder of the year will be on drilling high rate wells, primarily horizontals, and especially those that have a high liquids content. With oil prices north of $50 per barrel, we will also be targeting some horizontal oil drilling in our Canadian portfolio.

Projects such as these still have good rates of return and capital will be repositioned to allow us to take advantage of those portions of the portfolio. We also remain extremely vigilant about service costs, both in our capital and lease operating programs. We continue to aggressively bid services in order to get the biggest bang for our buck that we can.

The cost to fracture stimulate a horizontal Cotton Valley well for example has been reduced by over 30% in the last six months, and we don't think it has bottomed out yet.

We have expanded our focus program to drilling and completion projects as well. We have all operating personnel working jointly on both drilling and completions, to seek ways to improve our own efficiency, and not just rely on service costs to clients to achieve lower overall well costs.

With that, I will turn it over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions). First question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Great results in the Buffalo Wallow area. Can you give a little color is there going to be any changes to your plans in development given that recent success? You did indicate I guess an offset operator had a 20 million plus per day rate in a deeper formation. Is that something you're testing on some of your acreage that you operate as well?

Craig Clark

Yes. In fact, we have working interest on one of those wells. So, the short answer is yes. The program will change, and one of the difficulties we've had in the past, you know, we have been there a while , and the difficult is we had vertical rates, and we wanted to able exceed those because of the higher cost of the horizontal, and I think we are there.

Now, you will have more horizontal activity, and it will vary across the acreage in terms of what zone it is because we've tested I think everything from the Morrow all the way through the Atoka, but most of the activity that we spoke of to date on the horizontal side has been Granite Wash.

Scott Hanold - RBC Capital Markets

Is there opportunity, and obviously when you go horizontal you've got to pick your interval, but is there an opportunity where you have prospectivity in sort of a shallower and a deeper zone horizontally?

Craig Clark

Yes. That's correct. As you know, one of the issues I guess of horizontal, and what we did that in East Texas in the Cotton Valley is, you need to find one lobe, because we average about four or five fracs a well vertically is you need to find one lobe that contributes a disproportionate amount of production, in some cases water-free.

So, we've got a lot of testing out there, and I like to have a nickel for every zone we perforated, but I think we've landed on the right one, and there will be multiple opportunities even in the same well much like you would have in East Texas. That's one reason I like this area like East Texas, you get the multi-pay although it doesn't normally have all of the neat names like East Texas has got.

Scott Hanold - RBC Capital Markets

Can you say what you spent on that first horizontal well you drilled?

Dave Keyte

Yes. The fee for that well was $6.8 million, Scott. We over-expended it slightly due to a drilling related problem while we were going through a shallower interval, but 6.8 million is the target on a go-forward basis for a well in the upper Granite Wash.

Scott Hanold - RBC Capital Markets

Oaky, and based on what you seen today, do you have a target, sort of EUR on that yet?

Craig Clark

No, I think it's a little premature for us to call that. The well has only been on for a couple of weeks. As we gather more data on that, certainly we will be establishing a type curve for a horizontal just as we did for verticals.

Operator

Your next question comes from the line of [Mike Pena with Georgia Capital].

Unidentified Analyst

A question for you on the Buffalo Wallow well that seem to be pretty strong. Any idea as to how many other additional locations you may have to go horizontally there over that 91,000 net acres?

Craig Clark

I actually don't have the number. As you know our Buffalo Wallow stuff is not as densely drilled as some competitors, although there’s been some 40-acre, and you can also go to 20s up in the main Buffalo Wallow, just in the center of the bull's eye.

However, to the south where you know we poked our first holes I guess last year, and did this testing related to these, and then the acquisition to the north, it's not very densely drilled, so we've got a lot of running room.

The spacing that would apply, 40 or 80 or 20 would apply on a horizontal as well. You just have to stack them. So, you've got quite a number of locations although, you won't be drilling in areas you've already down spaced. You've got a lot of room to run here, but I don't know the numbers.

Unidentified Analyst

Okay. The Haynesville wells, I know you reported the 14 million a day in North Louisiana, and given the 8 million a day average, I'm assuming the other two were kind of 5 million a day. How does that compare to what you expect to get out of East Texas going forward?

Craig Clark

I'll actually like to get a little bit more, and just as a reminder, we didn't go offset because we were offset by 8 million a day well early on in the play in Harrison, and we didn't go prove up another 8 million a day well, because we get so much acreage, and acreage was pretty wild and still is to some extent.

We tested our verticals that we did, and we had hoped to average eight. Now, we do average eight but that 14 brings the average up, so I'd say we're looking to still find 7 to 8 in East Texas will be the answer, but the average is still there.

I guess the other issue is, we've heard some well cost, a lot of stories on well cost and train wrecks. We haven't had any yet. We are still in disbelief over some of the cost that has been quoted. Since we got our East Texas Cotton Valley sand horizontals down to 4.5 million before some of the discounts applied that J.C. spoke.

So, it’s hard for us to understand why a well that would go 1000 foot deeper in at least East Texas would cost more than double that. So, well costs are markedly lower, particularly when you don't have a train rig. So I’d say we are looking to still find the 7 million to 8 million a day type well in East Texas. We are not far from that.

One of the wells was in the best Cotton Valley sand area. I haven't done any commingling to date, and we still have that opportunity to get what I would call a free wellbore above us to add the Cotton Valley sand to Travis Peak That's what J.C. noted there.

Unidentified Analyst

Okay, great. Thanks for that. You also mentioned targeting oil weighted and liquids weighted prospects in addition to the horizontal oil prospect in Canada as well as the Buffalo Wallow. Any other potential projects that could add liquids there?

J.C. Ridens

Well, our portfolio, particularly in East Texas and Buffalo Wallow, really allow us to get a higher liquid's content. So those are two areas that we're looking for. We also have, as I had mentioned, that horizontal oil program up in Canada. We had significant success with that last year. After breakup is over, we're going to move back into that.

The area that probably does not bring us that same bang for the buck on liquids yield is South Texas, and we will be curtailing activity further there as a result.

Craig Clark

It's clear, NGL prices are obviously more favorable to gas (inaudible) we take with us on the road and crude. Most of our crude is in the Permian and in Canada, some of it in Louisiana. We have a lot of liquids, and we talk about that since 2004, processible gas in East Texas, Buffalo Wallow and to some degree Canada. All our gas, for instance, in Buffalo Wallow has high yield. The current target that we are drilling that doesn't have a lot of liquids is the Haynesville. That's relatively dry gas as far as I know from our production.

Operator

Your next question comes from the line of David Tameron from Wachovia.

David Tameron - Wachovia

Congrats on a great quarter. Craig, as I think, and J.C. mentioned it briefly, about (inaudible) and some other things you saw. As we think about Granite Wash, geologically speaking, is this a blanket sand misformation you are targeting? Should it be present across most of your acreage? I know you mentioned it's not as densely drilled as others, but can you talk about how much of this formation you think extends across the play?

Craig Clark

All of it does from either the Morrow, the Granite Wash, which is the one we are talking about, and the Atoka. It's all there. As approved, all the wells had at least four to five fracs in them. The Granite Wash gets renamed sometimes the Britt sand or Caldwell. They name the sands, but it's the Granite Wash, and it has multiple loads across.

Yes, it's blanket. I think the Ark is picking the best one, and that's why we did horizontals after we did individual testing of each of the four, five sands, and it's across the whole play for us.

David Tameron - Wachovia

Somebody mentioned some non-op interest with Newfield in their wells. Could you talk about what formation they are targeting and how that compares to your first well?

J.C. Ridens

I did mention the operator, but we're working interest on it with various operators out there, and most of the targets had been in the Granite Wash. Although there has been some activity in the other zones, but most of our work and interest is in the Granite Wash in varying loads. It's the granite wash.

David Tameron - Wachovia

As I think about bigger picture, what other opportunities do you have within your portfolio?

Craig Clark

In the tight gas sands and carbonates, obviously we have done it in East Texas. We may have failed to mention one of the delays in the Haynesville, as we did send a rig to the south to drill a Cotton Valley lime well, which has got more and more press both horizontally and vertically. We've got the rights to that, and we have that well drilling down south. That was one of our bigger rigs.

So we took a detour on one of the East Texas rigs to the south for the Cotton Valley lime. So we have multiple zones. Pick one in East Texas, South Texas. Our neighbors, we're trying in Eagle Ford. In Canada, it would probably be in Wild River in the Foothills.

The plan all along was to have this kind of potential. The verticals have to stand on their own, if the horizontals have to stand on their own. A horizontal of the magnitudes we’ve had so far in East Texas and Buffalo Wallow are superior to verticals in most cases. My usual three-to-one rule because of cost. We have got that across the asset base, because it's tight gas sands and shales.

David Tameron - Wachovia

Have you drilled any horizontals in Canada?

Craig Clark

Yes, we have. I think two in Burffalo. I am sorry.

J.C. Ridens

Two in Wild River, and we've drilled four or five up in our EV oilfield.

Craig Clark

We quit talking about little [biddy] wells, but we did it last year sometime in the last quarter. We are drilling horizontals in the Foothills, but they are really high deviated wells, but they are intended to be horizontals. They are really not exactly horizontal, because the dips are so severe. So, Canada is I guess new to the party, and they are doing it as well.

David Tameron - Wachovia

Okay. You briefly alluded to Eagle Ford. Do you guys have any perspectivity on your acreage for the Eagle Ford that everybody is chasing after right now?

Craig Clark

That's over three counties, I think, on the south end, not the north or central end. The three counties that seem to get the most press going from north to south on the south end would be McMullen, LaSalle and Webb, and we were in Webb County.

As we penetrated, we will look at it just like we did [cores], we'll test it, but it's basically above some of our Wilcox targets in at least that county. As you know, we have kept our South Texas acreage intact following the Houston Exploration acquisition here about two years ago.

Operator

Your next question comes from the line of Gil Yang with Citi.

Gil Yang - Citi

Maybe the question for J.C., is there anything in particular that caused your Buffalo Wallow wells to be better than the others that seemed to have IP of around 8 million a day? Would you attribute that to just your technical expertise or is it something about the formation?

J.C. Ridens

I think that it’s a combination of both, Gil. I think it's all about selecting the right interval to put the horizontal into. You got to stay within that interval, which we were very successful at. The way that we fracture stimulated it I think certainly helps, because we went into that with a very aggressive frac program, eight stages with a whole lot of slick water and a lot of sand as well. As a result, I think that when you combine all those factors, you get to the rate that we saw.

Craig Clark

It's not just in one field. We are right on the edge of the Texas-Oklahoma border. So, there is a couple of Oklahoma non-ops in there, Buffalo Wallow. It's spread out. That may explain some of the diversity, although I have seen frac with two, three or four fracs. We did eight. That may have something to do with it, but it is spread out. So that's good for our acreage, but it is spread out over some (of that area).

Gil Yang - Citi

So you have confidence that there is running room in rates of IPs. They are higher than the eight potentially, if you just do your pricing?

Craig Clark

That's the average, but you got some on the low-end and test the zone. I guess the key is our verticals were averaging on a couple three million a day. So we want to make sure they are better than the verticals we're not drilling at all. And that's why some of the early wells that were by competitors that were seven or eight, at the cost at the time, that wasn't as good as some of our verticals.

I think clearly when you are in high single digit or 10-plus million a day, they are better than we could we could do with three verticals.

Craig Clark

That the only data I've got. I'll stick to the 8 million a day average. Clearly, in the area where we drilled that first well at 17, that's horizontal country and much better than the average, but that's spread over a large area. I'm not being wishy-washy, but it speaks well for your area, and we are going to go with the average. In fact, we ran the economics of 8 million a day, coincidentally.

Gil Yang - Citi

Okay. It must be frustrating to you that you have got these great drillings out in your stock trades at a pretty significant discount. I would guess that your leverage situation is not helping. What are your plans or what is your view on what you can do to pay down debt or derivative your leverage through asset sales or any equity or bond issuances, convert issuances?

Dave Keyte

Gil, this is Dave. I think that certainly we think that the overall debt is high. As you know, we got stuck before we could shoot on our asset sales as the market turns south rapidly. I don't think we have a liquidity issue. I think we have an overall debt issue. That needs to be solved right now through asset sales.

We are looking at some selected asset sales, including perhaps Canada, which is a different market than in the United States. Maybe there will be a couple of asset sales up there that could work for us. Right now, we are going to rely on asset sales, because back in shape when the markets return.

Craig Clark

To clarify, I think the A and B market for a seller is opening up somewhat on the crude side because of the price and for asset sales marginal properties, et cetera. Canada has opened up as well. We'll be looking at the packages that we were trying to get out. We would look at trying to renew some of those in the U.S. and Canada from a marginal property standpoint.

Operator

(Operator Instructions). Your next question comes from the line of Kevin Smith with Raymond James.

Kevin Smith - Raymond James

I just had a few questions here. You talked about the liquids components of the Buffalo Wallow. What do you think the rate of return is going to be versus your Red River, Haynesville, well? I assume it will be higher. Is that fair?

J.C. Ridens

Yes, it is fair, because you got two factors working for you there. One is the well cost, $7million for drilled and completed well and then about 20% uptick in overall price because of NGL yields. So, right now, it looks like the rates of return would be higher in that play.

We also don't have some of the technical difficulties that you have in the Haynesville play of high temperatures, LWDs and mud motors burning up. You get a lot better runs out of these tools up in the Panhandle. So, our horizontal portion of this well actually drilled extremely fast and very trouble-free, which certainly will contribute to seeing a higher rate of return.

Craig Clark

I do think Kevin it really gets down because I seen the cost, and you've heard our discussion about cost for the shallower Cotton Valley, and why it shouldn't cost that for the Haynesville, but despite that, there has been a lot of wide range in cost in the Haynesville, mainly because of the difficulty.

I'm not familiar with the casing failures that seem to be talked about, but that cost is the big key to the dollars. I won't get into an argument of which well is going to recover more gas, and then you have the liquids.

We did see a phenomenon when we drilled at Cotton Valley Taylor. That's one reason why we waited when it kind of bad rap to select the zone. We were always questioning whether if it is the best rock. Did it have a shallower decline than what we had in the other Cotton Valley sands, and we did see that.

So, it's our hope that we see since we picked the best lobe. We tested it in the Granite Wash, it would have a shallower decline. Therefore we would get more bang from a decline curve, not just in higher IP, but that's just compared to the same sands. I'm not going to get into a Haynesville decline curve deal, except to say that because of the cost and liquids, it does have better economics as we sit here.

Kevin Smith - Raymond James

Do you have any guess as to what you think first year decline curve is going to be for a Buffalo Wallow well?

Craig Clark

We're using the same as tight gas sand, in those range, around 50% to 60%. Typical tight gas sand. That's probably a little severe, and of course, as you know, we’ve talked about an 80% initial decline for the first year in the Haynesville because it’s a shale, and the other one is a sand. We at least have some perm in the sandstone as opposed to the shale where we had literally none, or nanodarcy perm.

However, the question is, will it be a soft or decline curve than what we have in the same vertical wells of Buffalo Wallow, and we saw that happen in East Texas, and I'm hopeful we will see that here. The rates are obviously better than we ran the economics at.

Kevin Smith - Raymond James

All right. One other question I had; what was the lateral length in your East Texas Haynesville well?

J.C. Ridens

It was about 2,500, 2600 feet.

Kevin Smith - Raymond James

Okay. I knew your Red River one was little bit short. What was that?

Craig Clark

2,500 feet in Red River.

Kevin Smith - Raymond James

So, these were about the same?

Craig Clark

We had two. One op and non-op, and I think they were just both short of 3000 feet.

Kevin Smith - Raymond James

Okay. And then one last question, remind me again, when do you plan on testing the Haynesville line?

J.C. Ridens

We are drilling it. I don't know when it will be down. We are drilling a vertical and then we’ll stop, so, I think we'll hopefully have it done sometime in the third quarter, but we will go through the Haynesville on the way to the line, and take our cores and the good stuff we do, but that's a vertical well initially, east of where Devon's activity was in Shelby County around the board.

Operator

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

Andrew Coleman - UBS

I had a couple of questions. First, thinking about the $1.6 billion write-down pre-tax, and you guys had $2 billion of PUDs in your standardized measure at year end. Is it fair to say that the $1.6 billion is mostly PUDs or do you think is it 80% PUDs? It looks like we are kind of getting down about a PDP evaluation here in terms of what you remaining standardized measure looks like.

Craig Clark

I don’t release reserve, but at the end of last year, lost really on the ceiling test revision side, of course you are assuming we test everything, but it was the [tail] reserve, primarily the old properties.

This quarter, it was the tail of the gas properties along with properties as well. You got some help from oil, but not much. You got some help from liquid, and you did lose some PUDs for the first time. I don’t the percentage, but you lost some PUDs

Its basically PUDs and tail of gas prices in some regard due to the high basis differentials at the quarter, which have recovered somewhat, but you did lose some PUDs.

Now, with that said, with the cost that we just talked about that we not allowed to include in the calculation or future development cost or whatever they were prior to the quarter close, you will get some of those back and that will be our goal for this year on the cost side.

It will be more than favorable than just me talking about cutting cost, you get the tail and your PUDs back if you're successful in cost control, and as you know, we’ve done a pretty good job offsetting that with operating costs.

Andrew Coleman - UBS

Then, thinking about Canada, you guys are considering monetizing some of those assets, would that mainly be PDPs up there or would you be looking at (inaudible)?

Craig Clark

We had the three packages that Dave referred to I guess that we announced late last year when the market shutdown for A&D, and we sold a western package that was the Rockies.

The three packages, I shouldn't say three packages, but three areas that had properties to contribute that were in the other three business units that had not cleaned up their portfolio in the last couple of years, and that did include Canada, some of the stuff in eastern, some of the stuff in southern, but yes, it was clean up stuff pretty much across the three areas.

Then as you know, we have a lot of non-op in there. The only non-ops that’s left in the company now is little bit of OBO in our non-op in western, but it's really the non-ops in Canada. Those would be our targets for sale.

Andrew Coleman - UBS

On the non-op piece, about how many wells would that entail? Could you give any range on that?

Craig Clark

I don't know. Well, on that last package, the [well cap] was huge, because it had the San Juan, and it had Rockies. It was a high well count in the (inaudible) shallow wells up in Northeast Colorado. It was disproportionate, but I am sorry I don't know the number.

At one time, I actually thought that out of 10,000 wells in the company gross pre the package sale, it was 4000 of it, but only like 10% or 15% of the production. We quoted that number last year when we quoted the package, but I believe it's a substantial well count, but not much production.

Andrew Coleman - UBS

Thinking about the Lantern drilling rigs you guys have, given where the rig market is currently, is there any interest in buying some of these rigs to keep your costs down?

Craig Clark

We picked our target last year. It kept us out of the term rig market contract, which we are thankful for. We got a variety of rigs to suit us, and our goal was always to have half. Of course, all the rigs now are Lantern that are being picked up and down. So, the answer will be no.

However, we did accomplish getting those rigs where we wanted them to be for the activity we described last year, and this year, including, as J.C. mentioned, getting one of the big rigs in the Panhandle to drill horizontal wells. People wonder why we set the rig up there now.

Operator

(Operator Instructions). Your next question is a follow-up from David Tameron with Wachovia.

David Tameron - Wachovia

Just in general, when you talk about your rig fleet that you just alluded to, assuming you go to more of a horizontal program in the back half of the year, do you have those rigs within the Lantern fleet to execute that?

Craig Clark

Yes, we have eight rigs that we use for horizontal with exception to Canada of course. In our horizontal history, only the first Haynesville well was drilled with a third-party rig. All the other horizontals of any zone were all Lantern. I think eight of them have been horizontal or can go horizontal within our portfolio.

David Tameron - Wachovia

Obviously, Chesapeake has been high profile about shutting wells. Your hedging program indicates you're bearish on gas prices. Can you just walk me through if and when you do that and how do you think about that?

Craig Clark

Well, let's be clear. In our hedging program, obviously we were optimistic for next year, but you will get the recovery throughout 2010, sponsored by supply. That's our headline. We start hedging in 2010 and 2000, not when we panic in 2010. That's part of the reason the hedges are occurring.

With that said, you work on your cash flow and you don't justify drilling economics. We've heard there is a lot of wells being drilled and shut in or not completed. I don't really agree with that, because I think it hurts the economics of the well, if the not the well itself. That may be driven by term contracts or acreage explorations. We are not doing that.

If you don't need them, don't drill them. Drilling them and curtailing them doesn’t makes much sense to me either. Drilling them and shutting in, particularly the shutting piece, because as you bring wells up and down, Mother Nature does not cooperate in some areas, but you have to be cognizant if your cost were higher than the gas price.

I think you may have seen some of that touch it in some of the high basis differential like Rockies. You don't want to give the gas away. If it gets to that, you will have to address that. We have nothing shutting this time, because our LOE is substantially cheaper than the net-back if you look at it.

David Tameron - Wachovia

To do that process, you start looking on a cash cost basis. Is that the best way to start with?

Craig Clark

You look at really your cost to operate, which is your overhead and your LOE, your cost to produce the oil and gas out of the ground. We are cognizant, because we did basis hedge for that reason. Certainly, drilling wells and shutting them in is harmful sometimes, but we were not doing that. We are just not drilling them is the short answer.

Operator

There are no further questions. I would now like to turn the call back over to Patrick Redmond for any closing 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 contact us. Thank you.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: Forest Oil Corp. Q1 2009 Earnings Call Transcript
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