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Forest Oil Corporation (NYSE:FST)

Q4 2008 Earnings Call Transcript

February 24, 2009 2:00 pm ET

Executives

Patrick Redmond – Director, IR

Dave Keyte – EVP & CFO

Craig Clark – President & CEO

J.C. Ridens – EVP & COO

Analysts

Gil Yang – Citigroup

John Wagazino [ph] – Wachovia

Andrew Coleman – UBS

Jeff Robertson – Barclays Capital

Dan McSpirit – BMO Capital Markets

Eric Nuttall – Sprott Management

Operator

Good afternoon, ladies and gentlemen. My name is Tina and I will be your conference operator today. At this time I would like to welcome everyone to the Forest Oil's Fourth Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator instructions) Thank you. Mr. Redmond, you may begin your conference.

Patrick Redmond

Thank you. Good afternoon. I want to thank you for participating in our fourth quarter and year-end 2008 earnings conference call. We have joining us today Craig Clark, President and CEO; Dave Keyte, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and COO.

I would like to caution you about our forward-looking statements. All statements, other than statements of historical facts that address activities and outcomes of Forest expects, assumes, plans, believes, budgets, forecast, projects or 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 on this fat Tuesday as Mardi Gras begins. The results for the fourth quarter were largely in line with our expectations except that we continue to see lower costs and wider than anticipated price differentials in natural gas. Included on our GAAP earnings this quarter was a ceiling test charge for approximately $1.5 billion, attributable solely to our U.S. cost pool. A major factor in the impairment in the fourth quarter was the decrease in crude prices since September 30 as well as the fact that we do not include our mark-to-market hedges as part of this calculation as we do not employ hedge accounting.

During 2008 for the full year, strong cash margins and record production led the way to record results. The result of the company's investments also was excellent and cash costs continued their path down in the face of a very inflationary time for the industry. The decreased industry leading levels and cash costs combined with a very solid F&B cost, once again demonstrated that Forest has a terrific operational group that composed superior performance metrics even in tough environments.

In 2008, we set the following financial performance records

Adjusted earnings of 372 million, up 67% from last year's record, adjusted EBITDA of 1.3 billion, up 46% from last year's record and adjusted discretionary cash flow of 12.56 a share up almost 300% from last year's record.

Our 2008 investment results were strong as well and Craig will talk more about them in a bit. With all in FD&A of about $2.61 a unit and growing reserves 26% and continuing to add in our core and sell our non core assets, we substantially grew and upgraded our reserve base.

Over the last five years, we've spent $7.1 billion, with all in FD&A of $2.34, and importantly, almost entirely spent that money in our core, while shedding almost $2 billion of assets in our non-core areas. This is a very solid performance over a number of years that positions us with scale in some of the best resource basins in the U.S.

In the fourth quarter, the fourth quarter provided significant challenges to our company as a swift and substantial decrease in commodity prices required us to take immediate action to preserve capital. The headline for the fourth quarter results is, delivered as promised results despite a 60% decrease in rigs during the past quarter. Not an easy achievement.

In the fourth quarter, we produced 565 million a day, up 9% sequentially, and of that, 4% was organic. The increase in production kept a very successful run of production increases which we projected at our analyst day last April. In the last three quarters of 2008, production grew $96 million a day or 20% of which 17% of the 20% was organic.

During the quarter, cash margins decreased 60% from 2007 levels to $3 per Mcfe, despite a 17% drop in production expense. In addition, DD&A increased to $2.93 per Mcfe due to price related revisions stripping away proved reserves in the denominator in the calculation of this expense.

EBITDA decreased 4% in the same quarter last year due to decreased margins, but offset by 15% higher volumes. Overall, the fourth quarter came in about as expected, albeit with almost a total implosion in the capital program as our backdrop.

In times where capital markets are shut down, it's imperative to maintain an increased liquidity, even if the operational plan such as ours is to spend within cash flow. In this world weird things can happen. We fully understand and appreciate how a down cycle works. We've been through four of these before. While this is one of the worst confluences of the bench, it is certainly manageable.

After our senior note issuance a couple of weeks ago, we currently have about $800 million of liquidity on our bank facility. This is as much as we have ever had before 2008 and we believe it's a good cushion against uncertain events. Our borrowing base re-determination will be coming up in March, and based solely on our internal calculations we believe the collateral base the banks have is at least as valuable as the one on which our $1.8 billion revolver was set last year. Therefore, we expect to hold our borrowing base at its present $1.62 billion level.

If that is the case, which we certainly believe at this time it probably will be or could be. We expect Forest to be able to operate during 2009 easily within its current liquidity situation and generate free cash flow.

In 2009 we will spend $500 million to $600 million in CapEx. This is consistent with the guidance we released earlier this month. Our goal with the '09 plan is to preserve our asset bases and preserve our workforce in place. In addition, we hope that we will be able to pay down some debt in order to prepare for improvement in the margins in our business. This capital is intended and should keep 2009 production flat to 2008.

In summary, we had a very successful year of investments with what one sell-side analyst said would easily be top quartile performance and a very solid three year and five year numbers as well. We also were highly successful in controlling our operations and will likely be in the top five in terms of cash costs per unit for the year. Because of our acquisition and disposition activity, our assets are now more focused than ever and we have about 127,000 net acres in a very promising Haynesville Bossier Play which makes us the fifth largest land holder in this play.

In short, Forest continues to be an exceptionally run company with profitable and focused operations and potential for several positive catalysts in '09. It is still in our opinion the best risk waited investment you can make in this space. Craig?

Craig Clark

Okay, thanks, Dave. Thanks to all the folks listening today. I will cover the overall results with a little redundancy with Dave, but overall and then talk about '09 before J.C. gets into the operations to tell you. I guess the theme of this conference call would be despite the current overall economic situation in the U.S. Forest still had a great 2008 and virtually all our measured metrics.

We had company records in five areas in '08 and faired very well during the roller coaster ride in commodity prices last year. In fact, we faired well against our industry competitors in most metrics. I didn’t realize how well we had performed on those metrics like finding cost until some of their reserve replacement and finding cost numbers by industries have been recently tallied up.

Our operational success in 2008 can be in my opinion attributed to three things. The number one is Forest culture is that we are operations people who focused on the cost control side in field execution early in the game, this does include rig ownership. All of this has paid big dividends already on our horizontal programs both the Shales and the tight sands.

Number two, we are used to spending near or below our cash flow for drilling and leasehold projects, been there done that. In fact, we have employed free cash flow models over the last five years, the exception only being the fourth quarter of 2008.

Number three, our acquisition and divestiture program is upgraded and set by through the each step and I will talk about the metrics in a minute. But in addition to producing assets our acquisitions have added a lot of undeveloped acreage and infrastructure at very low prices, in some cases, for free in fact.

For the year 2008, the major highlights in addition to the financial metrics, Dave discussed, are with group production and reserves overall and organically with or without revisions to new records.

Cash cost per unit are down for the third year or fourth year, I think the third year in a row and we perfected the horizontal expertise throughout the company, we are not just doing it in East Texas and we had no mechanical failures that are not going (inaudible).

I am especially pleased with the mechanical efficiencies in the newest areas, the Haynesville and the Utica Shales. We quietly added acreage throughout the company, most notably, we now have 127,000 net acres in the Haynesville play, I think that's up from the last number that was published.

Throughout the year we did make acquisitions where acreage and producing assets were involved, it was mostly in East Texas and Panhandle this year, 511 Bcf for $2.68 per Mcfe better than lot of people's finding cost with our core areas – within our core areas not outside them at all. I think we sold 97 Bcf of non core assets throughout the year including in the fourth quarter and that would come out to be $3.20. That sold we are now completely out of Gabon and mostly out of the Rockies in those transactions.

Let's start with the metric everyone focuses on. We released earlier at year-end that's proven reserves and reserve replacement. The proven reserves ended up at 2.7 Tcfe approximately despite about approximately 200 Bcfe of mostly price related revisions. We continue to break out the reserve revisions again this year as we've done in the past. This year's negative revisions were primarily commodity price related and affected the end of live for Terra reserves on longer live properties.

The proved developed percentage was 63% which is exactly the proved developed percentage pro forma for the Cordillera acquisition we announced at the end of the third quarter. So with the same revisions as faced by the industry and without putting up our legacy assets we grew reserves by 26%.

The reserve replacement percentage and associated finding cost are attractive as well. I'll repeat them, we replace 549% at 2008 production at all sources $2.61 per Mcfe excluding revisions.

Our organic reserve replacement excluding the price revisions was 281% with a resulting organic F&D of $2.54 per Mcfe. This compares well last year went back and looked in the organic reserve replacement was 236%. It's also good that the organic replacement was 280% when you consider the CapEx spending based on that, it was 107% of EBITDA or cash flow.

The reserve add success rate production growth and cost control certainly demonstrate the quality of this asset portfolio and the merits of our approach to continue to build these core areas. Nothing is more evident in what happened with the year end results here. And, oh, yes, when we continue to talk about cost cutting, it does help to recover some of those tail reserves that you loose to price revisions from year-to-year.

As I mentioned a few moments ago, we spent 107% of EBITDA in 2008 on E&D activity of $1.36 billion. This was in our accelerated CapEx guidance we announced last April. We did however not see the drilling cost productions that we had predicted this time last year in 2008. However, 2009, in our opinion, will be a different story on the cost side. And with the $1.36 billion in E&D spending, we drilled a record 714 gross wells, up 437 net wells, and that was a 97% success rate. I think that may have been the highest we've been ever.

The gross well count is somewhat affected by the low working interest San Juan wells. We sold these in the Rocky Mountain package so they won't be in the '09 counts. So a caution, when you look at the lower well counts in 2009, it's because you lose those low interest gross wells.

I think the 97% success rate is high as we've ever been, but it should provide confidence for the asset quality that these assets remain to perform at these prices and our execution of the 18,000 locations that we speak about from time-to-time in our presentations.

Up to almost 70% of our spending was on five assets, where most of these locations exist. There is your focus. We also added about 200,000 gross acres and 140,000 net acres in 2008, some of which was via new leasing like our Haynesville leasehold, where some of that was leased, and the rest was added from the architects in Cordillera transactions.

Some undeveloped land was included in the sales through 2008, specifically Rockies and Gabon, but we added the acreage in our core areas, specifically East Texas and the Texas Panhandle.

Just as a note, the cost of our acreage, our leasehold through 2008 are seismic, our re-completions are capitalized overhead and maintenance capital is included in our E&D CapEx number. So we are not excluding it from those F&D calculations we referred to earlier.

On the production side, we averaged 569 million a day for the fourth quarter and 518 million equivalents a day for all of '08. That's a record. The 22% year-over-year production growth is despite divestitures and a few hurricanes. We did see some major interesting pipeline averages in the fourth quarter in the Mid-Continent, specifically in the Jackson and Panhandle and CenterPoint in Arkansas, which affected not only the basis differentials, but fourth quarter volume slightly.

We also along with other companies waited in line for high strength frac profit, maybe not as long as some in the fourth quarter, which really affected us a little in the Haynesville, but more specifically, in the South Texas, Vicksburg and Deep Haley wells. Despite these obstacles, we grew production 9% from the last quarter.

I should note, that the recent, had a few calls about the recent pipeline explosion in Carthage, Texas, but the big plant has not affected Forest volumes materially as our company-owned pipeline system had alternative outlets for the gas. The only thing that's resulted from that is we are seeing some higher line pressures in East Texas following net outage at Carthage as the gas is backed up going round it.

Our operating and cash costs, what can I say folks, solid performance with no excuses. Our per unit cash costs are down again from the previous year. That seems to be a repetitive issue. We always do it and we reduced per unit cost by 8% in 2008. Another excellent job by the field staffs and the credit to our project focused cost control initiative. The folks in the corporate office didn’t do a bad job either in reducing expense G&A per unit by 12% to near our lowest level. All of this will serve us good going into 2009.

Now, a few comments about 2009. It's hard not to be bullish I guess on the long-term prices for the prospects of both oil and natural gas. With rapidly reduced worldwide spending, we believe that supply will decline. More specifically, since we are primarily a North American gas producer, the decline in the U.S. gas rigs to what we believe will be below 800 along with a more severe hyperbolic decline from the unconventionals, specifically, the Shale influence will cause a supply decline in 2009.

If we are sure about anything, it's that the rig count and that the decline rate average for the industry will increase. Demand however, specifically industrial demand, is the wildcard. So we remain bullish long-term, but conservative because of demand in our behavior short-term.

As in the past, Forest does not use our hedges or the strip to justify drilling economics. In setting our drilling economics of 2009, we used flat prices of 450 for gas and 40 for oil, to stress test the economics.

So let's be clear about our 2009 spending. The lower spending is not a function of where the properties fall out at 450 gas, but more a function of what we believe will be lower cost. Why drill them now when you can save later in 2009? And we do believe that. As a reminder, our capital guidance we issued a few weeks ago reflects only a 5% average savings in drilling cost, but I personally said publicly I believe 20% is more like it. We welcome our peer companies joining us in the cores for cost to come down in 2009. Maybe this will be the year.

As I noted in our earlier year guidance – in our earlier press release we intend to run 15 operated rigs in 2009, virtually all lantern with two to five non-operated rigs at any one time and those come in and out so there's your 15 to 20.

Our gross and net well count will be lower due to the 60% reduction in CapEx spending but also due to the lesser gross wells in the San Juan and also due to one-third of the wells in 2009 being horizontal which will take longer to drill than a typical vertical well.

Most of the drilling activity is very focused; it will be in the Ark-La-Tex region specifically East Texas, North Louisiana, followed by the Texas Panhandle and some in South Texas. The impact wells will obviously be the horizontal in East Texas, North Louisiana and Haynesville and the other Cotton Valleys, that would be the sand and don't forget about the Lime.

We had some great data points by the industry in the Lime in East Texas announced that will benefit us as well because we have the rights to that zone in addition to the Haynesville and the Cotton Valley sand. About half or almost half the CapEx will be in East Texas, North Louisiana or in Eastern. So there's your focus in those projects have been stress tested at the prices I mentioned earlier. We again, getting to be monotonous we again guide the production expense per units of decline in 2009 by about 5%. I expect us, needless to say, to do well in cost control in 2009 in all areas.

In closing, I need to emphasize what Forest is all about going into the environment for 2009 which is tough. I guess you could call this a mission statement or something like that. We intend to extract or create margin through cost control and technology. We've already proven our abilities in these disciplines. You can see the evidence of these abilities in black and white in this year results in lower cash costs, the finding costs, the reserves, the spending discipline, the low cost of entry into the hot plays and even the mechanical success on all of the horizontal wells thus far even in the new areas like the Haynesville and the Utica. I didn't realize again how good some of these numbers looked in 2008 until recently when industry numbers became available. I'm proud of the work we've done so far and that the employees have done and I look forward to beating the pack or lapping the field operationally again in 2009.

Now J.C. will touch on the success and the progress on the operations. J.C.?

J.C. Ridens

Thanks, Craig. I'd like to begin today with comments about the success that we have had and continue to have in the Haynesville shale. We successfully drilled and completed our first horizontal well in the Northern Louisiana portion of the play. We achieved an IP of 14 million cubic feet per day from a well with only about a 2,500 foot lateral length. The wells averaged over 10 million a day for the first 16 days of production. We took a conservative approach of not trying to push the 1,000 horse power rig contracted beyond what we thought was an acceptable length on our first horizontal well. We pumped a seven stage frac, utilizing high strength profit rather than sand out of the concern for the closure stress in this high pressure interval. All seven stages were pumped successfully and our analyses have recovered frac fluid, shows all seven stages are contributing to the overall flow from the well.

Based upon competitor press releases, our well had an extremely high rate for foot of lateral drilled and stages of frac pumped. We attribute our higher IP to the fact that we didn't have any of the mechanical issues that some of the competition has had with not being able to get all the stages of the frac pumped either due to the inability to frac the rock or mechanical problems experienced with failures of the completion assembly.

Our next well in the same area will be drilled in the second quarter with a 1,500 horsepower rig from our lantern drilling subsidiary. This larger rig will allow us to continue development with longer laterals as we continue to refine our technique in this area. This was a key data point for us in the play as not all of our land position may lend itself to long laterals.

Proving that high rates can be achieved from the shorter laterals gives us confidence in moving forward on more of our overall position in this play as stated previously that now totals approximately 127,000 net acres. Our acreage position was achieved from leasing and our acquisition activity for the last three years and that gives us an extremely low cost of entry into the play.

As a point, we sold about 200 net acres of non-operated Haynesville acreage to a competitor to complete their acreage position in the fourth quarter for $20,000 per acre. So getting the bulk of our acreages through acquisition demonstrates the additional value that can be derived from our purchase of assets in this key focus area.

We have continued gathering core data in Harrison County on the Haynesville and our initial analysis of the core shows good overall thickness with fracturing present. Gathering this core data will allow for us to further refine our geological interpretation, fracture stimulation and overall optimization of the play as we continue our planned two rig program in the Haynesville during 2009.

Harrison County drilled and cased and it will be fraced in the next two weeks. This well was successful in achieving a lateral length of 3,500 feet. We're planning a ten stage fracture treatment on this well and in addition to our operated completion activity; we have a non-operated well that is also complete. We have a second operated horizontal well underway in Harrison County that’s currently in the bill section of the hold and we are about to spud a third.

The Haynesville is latest in our string of horizontal successes in East Texas which started with our Cotton Valley program. As of year-end 2008, we had completed 15 horizontal Cotton Valley wells with a 100% success rate. Our average gross IP has been over 5 million cubic feet per day from this program and that success continues today. Notably, one of those horizontal wells was on our latest acquisition in East Texas and that well flowed at 4 million cubic feet per day and we are following up on that with another well in the same area.

These wells are economic at current prices and we've reduced costs from $5.2 million to $4.8 million for a horizontal well prior to 2009 industry price reductions. We intend to reduce costs in the Haynesville as well. With continued success for our horizontal program of both the Cotton Valley Sand and Haynesville Shale, our plan for 2009 will be to fund the eastern business unit disproportionately.

We will spend almost half of our capital this year in this business unit which is reflective of their success in growth rate over the past three years. This business unit had a base of exactly zero million cubic feet per day in East Texas and North Louisiana in early 2006. That base has now reached 91 million cubic feet from both acquisitions and organic growth.

In 2008 alone, their production increased 48% and their organic growth of 21% was primarily derived from horizontal wells. In other words, it's grown from being no business unit to being the largest producer in the company. Of course, our horizontal program isn’t limited to just East Texas and North Louisiana.

We've also had success in the Arkoma Basin of Arkansas, with our first operated well achieving a horizontal length of 3,000 feet. The best horizontal well we've participated in so far in this area had an IP of 10 million cubic feet per day, so you can see the potential this area has.

We have also used horizontal drilling in both our EV oil field in Canada where we got an IP of almost 300 barrels per day from the latest completion and also in Wild River, where we have used it to access one of the less permeable zones in the field to increase recoveries as well.

Another significant development of Wild River was our success in getting the field down spaced from four wells per section to six, which will increase our reserve base and drilling inventory for this asset in 2009. We are currently drilling our first operated horizontal well in Buffalo Wallow and we are going to use our same technology that's been proven successful elsewhere.

I can't stress enough that our operated horizontal program has been mechanically successful and we have yet to lose a horizontal well bore. This is a complement to our operations staff and they're planning an execution of a challenging technique and I will put our record at success up against anyone's.

Further, over a third of our 2009 activity will be horizontal, primarily in the Ark-La-Tex area. Our mechanical success rate expanded in 2008 with a successful drilling and completion of a three well horizontal pilot program in the Utica Shale in Quebec. I need to remind you, we are the first mover in this play, and as a result, we are blazing the trail for development in this base.

Each of the three wells targeted a different section of the Utica and they were also in three different geographic areas. We tested our three wells after pumping four stage fracs on each one. Our rates achieved were between 100 Mcf per day and 800 Mcf per day without full recovery of the load water from the fracs.

We were hampered in load recovery by the lack of availability of coil tubing unit to drill out the frac plugs as we do in our other plugs. This resulted in a prolonged operation of using a snubbing unit to drill out the frac plug. As the wells were taking too much to simply drill the plugs out without this snubbing unit.

While the producing rates that we achieved were not as great as we had hoped for, we were successful in getting all three wells drilled, cased and fracture stimulated. At times, we saw higher peak rates than the 100 Mcf per day to 800 Mcf per day I mentioned earlier, but those were not sustained.

Our frac designs were based on our experience in the Barnett Shale, pumping approximately 20,000 barrels total into each well and we're currently evaluating the results achieved for future optimization of our technique.

Once again, being first mover in this play means Forest doesn't have the benefit of any horizontal outfits for comparison as we did in the Haynesville. The Utica like old shale will have an evolution of technique to become fully commercial. We've seen this in the Barnett and the Haynesville with earlier results being encouraging, but not nearly as good as they are today.

With our acreage being in the form of ten year exploration licenses, the bulk of which are good until 2016. We have the advantage of being able to take our time in this play and do the proper look back before we continue with our next round of activity. And that next round may very well be going back into the existing horizontals in completing additional intervals with a modified track technique this summer.

Our pilot program was configured to drill longer laterals than we actually needed for four stages of frac. As a result, we did not use all of the horizontal lengths available in our wells and we still have usable horizontal hole in which to do future work.

In summary, we are pleased with our drilling results for 2008, which showed we could grow our portfolio at an accelerated rate. We demonstrated expansion of our horizontal program to many different areas of our asset base and our goal in 2009 will be to increase the cost efficiencies of our program through both technical advances as well as decreased pricing from our vendors to reflect the lower level of activity within our industry today.

Operator, we are now ready to take any questions.

Question-and-Answer Session

Operator

(Operator instructions) Our first question will come from the line of Gil Yang with Citigroup.

Gil Yang – Citigroup

Thank you. Good morning or good afternoon to you in Denver. I think you said that your budget was based on 5% cost savings since I guess year end I would assume. Is that right?

J.C. Ridens

Yes, that's based on 2008 average well cost, Gil.

Gil Yang – Citigroup

Average well cost.

J.C. Ridens

Yes.

Gil Yang – Citigroup

What would happen if costs come down sort of to the 20% level that I think you mentioned you sort of expect would you spend that on more drilling or pay down debt?

Dave Keyte

If you are talking about a difference in average it goes from zero to 20 versus zero to 10 like we think. You are talking about 25 million bucks so I don't have an answer for that specific amount of money, Gil. I think we get it in here and see what we do there get it in here.

J.C. Ridens

I would say debt or you would have to reallocate it to the more successful areas. One thing I will say is if you do see a 20% reduction for that matter a 10, a lot of projects that fell out at four dollar and five dollar gas come back in again, you get a huge benefit in the rate of return. You get back some of the margin you probably lost in the last few years. So I want to incent those cost reductions on those wells and that's why we are continuing to drill some.

Gil Yang – Citigroup

Can you in that domain, you say you stress test your projects down to 450 and $40 oil. Can you describe what you mean by stress test, does that mean a 10% rate of return or is there something else that you're thinking of?

Dave Keyte

No, in order to make the capital budget this year, the well has to be either a commitment well or it has to achieve a 20% rate of return at those levels.

Gil Yang – Citigroup

Okay. Alright. Great. And last question is how much data do you have on Hamilton County and can you compare what you think is there versus what you saw in Red River?

J.C. Ridens

Actually that's Harrison County.

Gil Yang – Citigroup

Harrison County, okay.

J.C. Ridens

And we've got a lot of data there because the number of vertical wells that we've drilled in the Haynesville which totaled 14, about 12 of them were in the Harrison County area and we've got core data. We've got offset penetrations. We also have some non-operated activity in which we participate that helped calibrate that data point as well, Gil.

Gil Yang – Citigroup

Can you describe what you are seeing?

Dave Keyte

We are seeing good vertical test rates. We've had one well vertically that tested as high as 4 million a day and from the completion side we've seen horizontals as high as 8 million a day for an IP and…

J.C. Ridens

Not ours.

Dave Keyte

Offset operators but it's a data point that we've got nonetheless. And then we've got thicknesses that we have mapped out from both vertical penetrations as well as seeing what the offset horizontals have done.

Gil Yang – Citigroup

Can you just sort of in terms of thicknesses are they more to Red River or…

Dave Keyte

The thicknesses in actuality are somewhat greater than Red River.

Gil Yang – Citigroup

Okay.

Dave Keyte

Now it is shallower and therefore lesser cost to drill but also lesser pressure. The Texas side is shallower than those wells on the eastern side of Louisiana.

Gil Yang – Citigroup

How much shallower on average do you think they are in that area?

Dave Keyte

1,000 feet to 1500 feet, I believe, Gil.

Gil Yang – Citigroup

Okay. Great. Thanks a lot.

Dave Keyte

Thank you.

Operator

Our next question will come from the line of John Wagazino [ph] with Wachovia.

John Wagazino – Wachovia

Hi. Good afternoon, guys, and congratulations on the great '08.

Craig Clark

Thanks, John.

John Wagazino – Wachovia

Can you give me real quick just a little housekeeping break down of the CapEx by region for the last year?

Dave Keyte

I don't have it. I'll have to get it back for you. But it was pretty equally distributed as per – we stuck to the same percentages throughout the year that we guided I think early and clearly the business units that spent the most were eastern, western and southern and last Canada, of course we didn't spend anything really in international. The eastern was the only one that received additional capital late in the year and that was clearly for the Haynesville. But the percentages are almost all – Pat can give that for you, it's almost exactly the pie chart we put out at the Analyst Conference.

Patrick Redmond

Something like 35 eastern, 35 western, probably 20% southern, 10% in Canada, it's probably chopping wood close.

John Wagazino – Wachovia

Perfect. And do you have any other updates on divestiture programs and any timing or same type of size looking for 350 million may be out in '10 now?

Patrick Redmond

Yes, maybe if things clear up by then. But that's just going to be shelved until we see all the backlog washed through. We think it will take somewhere between $30 billion to $40 billion of activity to clear the market and that given where we are in the credit cycle that's going to be ways away.

J.C. Ridens

With that said there is a market for I would call small properties and you will probably get a few or hopefully get a few small stuff out the door that are non strategic but I think in terms of those larger packages even $200 million the markets in (inaudible) and that's when we push it into '10 not to mention the fact that commodity prices will improve hopefully.

John Wagazino – Wachovia

Alright, that's all I've got for you. Thanks very much.

J.C. Ridens

Thank you.

Operator

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

Andrew Coleman – UBS

Good afternoon, folks.

Dave Keyte

Hi Andrew.

Andrew Coleman – UBS

I had a couple, one question on the rig count. What's your current rig count level for the first quarter right now?

Craig Clark

It's about 20.

Andrew Coleman – UBS

About 20, you said?

Craig Clark

Yes.

Andrew Coleman – UBS

Okay. And is it fair that that's mostly out in the eastern area?

Craig Clark

Yes, we got our sheet here, but eastern has got about I'd say eight or nine of them. And then western's got five or six of them, Canada has got two, and southern is one or two. And I think that's about 14 or 15 up in the non-ops vary and of course, they are lower interest but the non-ops vary from four to eight. So I guess if you're averaging, you would be between 18 and 22 right now, and it's the non-ops that are fluctuating. You remember we own all but one of the operated rigs. So that rig counts pretty constant. And that's where you spend your money anyway.

Andrew Coleman – UBS

Great. So thinking about reserve bookings for 2009, I recognize there were only 60 days and the end of the year kind of thing, but this rig count at 20, I guess it's fair to say you'd probably keep a fairly similar smooth kind of booking profile, kind of 20%, 25% per quarter, if you will, to get to that full year number with an added bump from potential pricing, a revision to the upside of pricing, it get better?

J.C. Ridens

I think that there is no reason to think we would push reserves into one quarter or another. It goes with the capital and we've maintained a pretty constant type percentage and a pretty constant rig count, except for a little bit of ramp last year and then the precipitous drop that Dave referred to, but yes, tracks it in the course that would become relatively predictable on that side at year-end close.

Andrew Coleman – UBS

Okay. Good deal. Second of all, can you just give a breakdown on your approved reserves between the U.S. and Canada at year end? Or should I just wait for the K to come out?

J.C. Ridens

Wait for the K. I don't have that exact number, but I would guess.

Dave Keyte

290 Bs in Canada.

Andrew Coleman – UBS

Okay.

Craig Clark

That's 11%.

J.C. Ridens

That's within ten or so.

Andrew Coleman – UBS

Okay, fair enough. And then, you made a comment that you drilled that first Haynesville well with a 1,000 horsepower rig.

Dave Keyte

Right.

Andrew Coleman – UBS

Does that give you a little bigger stick maybe to go negotiate with some of the rig companies if you don't necessarily have to be using a 1,500 horsepower to kind of drill the Haynesville? I guess what lateral length does 1,000 horsepower top out at?

Dave Keyte

Well, I hope it's 2,500 feet which is where we finished, but yes, the answer is, it gives you leverage. I do not think that, that would be the rig particularly on the deeper side that you would want to use. We had it because it was there in the field, and also it's very important that we don't stub our toes. So we went light on the lateral and heavy on the frac and it looks like it paid off per foot. But we have eight rigs plus or minus in the horizontal range which in the Lantern fleet, most of which are in East Texas, but I do think that overall, because of the potential problems you could have and there is some colorful well results mechanically, we would probably design at least the Haynesville for 1,500 horse rigs and we will have four of them.

Andrew Coleman – UBS

Okay. And then, for those wells are you running the liner all the way to surface or are you hanging it up a 7 inch?

Craig Clark

No, we are running a full string of 4.5 at this point.

Andrew Coleman – UBS

Okay. And then the last question I'm looking at the 700 gross wells you drilled last year. You said the coal bed methane wells there were a little bit, those are about to be sold. How many total wells did that entail as the 700?

Craig Clark

The San Juan and they are both just the regular and the coal bed methane, but they are like 2% working interest. We've had them for years. I think the number in the K last year was like 300 of them, but it will be about the same number. But they are high gross low net. So in the net well count they are rounding here. I'll just make that point to see if the gross well count comes down disproportionately. It's not only because of the capital program, but it's quite a few gross wells, but the net well is rounding here.

Andrew Coleman – UBS

Sure. Okay. Thank you.

Operator

Our next question will come from the line of Jeff Robertson with Barclays Capital.

Jeff Robertson – Barclays Capital

Thanks. J.C., I might have missed this when you were going over the operations review in the Ark-La-Tex. Can you talk a little bit more about the Cotton Valley lime and what your plans are for that this year?

J.C. Ridens

The Cotton Valley lime we've got a proposed well rather that will spud here in the next month or so. And that will be our first test point on that. And then we'll take it from there. We've seen indications in, as we get to the base of the Haynesville, where we see that lime shale interface that we think is interesting and we will probably end up taking one well or two wells into the lime for a test this year.

Jeff Robertson – Barclays Capital

Can you say where those tests will be?

J.C. Ridens

No, I cannot.

Jeff Robertson – Barclays Capital

Okay.

Craig Clark

Jeff, we have three producing fields that are classified as lime. One in Upshur, one in Henderson and one down near, I think the (inaudible) I like to see it's either Limestone or Leon County. So we have production out of the lime at that vertical at this time.

Jeff Robertson – Barclays Capital

Okay. And the Arkoma horizontal program, what formation are you testing there?

J.C. Ridens

Those are targeting the Basham and the Borum, which are members of the Atoka.

Jeff Robertson – Barclays Capital

How big can that program be, J.C.?

J.C. Ridens

It could be a size of a dozen wells probably for operated. And then we still have a non-op component going on as well that may add another six wells to eight wells, I think.

Jeff Robertson – Barclays Capital

Is that the area that previously when Houston exploration owned it they just drilled vertical wells?

Dave Keyte

That's correct.

Jeff Robertson – Barclays Capital

Okay. Then lastly in the Ark-La-Tex area are you having to do anything with transportation to fit into your development plans this year and as you look out into 2010?

J.C. Ridens

Yes, the only thing we are talking about doing is some expansion of our gathering infrastructure. Again we see plenty of pipeline take away as being able to get our product to market out there. The only thing that we may have to do is re-dig a little bit of that to handle the high pressure Haynesville compared to our low pressure Cotton Valley system.

Jeff Robertson – Barclays Capital

Okay. Thank you.

Operator

(Operator instructions) And our next question will come from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Gentlemen, good afternoon.

Craig Clark

Hey, Dan.

Dan McSpirit – BMO Capital Markets

I recognize that your game plan in the Hazel shale for 2009 is to further delineate your 127,000 net acres, but will any of the wells drilled this year go to testing 80 acre spacing?

Craig Clark

No, I don't really think so, Dan, I think that our primary focus is going to be on drilling in more of a conventional spacing, if you will, of one well per section initially and not getting into a down spacing situation right away while we prove up additional acreage as well as meet some of our explorations that we may be facing.

Dan McSpirit – BMO Capital Markets

Okay, okay. And in the same play in the Haynesville where you control the shallower rights in drilling the deeper pay of the Haynesville or the Bossier, will you be able to convert at all the shallower pay, convert the PUDs at all?

Craig Clark

We can probably do a Cotton Valley booking along with that.

Dan McSpirit – BMO Capital Markets

Okay.

Craig Clark

But, in reality if the Haynesville is as successful as we think it will be what we'll probably end up doing is coming back in and drilling a twin to that well before that Haynesville's ever fully gone or come mingle it at a later day.

Dan McSpirit – BMO Capital Markets

Got it. Got it. Very helpful. Thank you.

Operator

Next question will come from the line of Eric Nuttall with Sprott Management.

Eric Nuttall – Sprott Management

Regarding the Utica program, did one of the horizontals on the masca [ph] blocks test the same interval of Shale that tested up to a million a day on one of the previous vertical wells?

Craig Clark

Yes.

Eric Nuttall – Sprott Management

Okay. And if we didn't get anywhere remotely close to a three to four times multiplier on the lateral versus the vertical basis, is it safe to assume that there was an error or an ineffective completion job that resulted in no incremental production increase?

Craig Clark

We had trouble getting the water back we used to clean it out. We saw gas and in fact one of our partners or competitors has released higher rates so we saw enough gas we had to use a snubbing unit to clean it out. And the short answer is we either need to deal with, we did three different intervals that was previously announced, Eric.

Eric Nuttall – Sprott Management

Right.

Craig Clark

In three different areas. And there was reason for that because the shale is so thick and now you are going to have to unload the wells and or change your frac design which J.C. discussed. But clearly you are going to have to pick the best of the three zones and we did that intentionally. But one of the ones was the one where we did the vertical and the only difference being is with the vertical we fraced the (inaudible) top to bottom as opposed to targeting one interval and we did a lot smaller frac which meant we didn't have very much fluid to get back and I think that's the central issue. It was not an issue of us not planning. It was an issue of the remoteness over there and us having to use a snubbing unit to clean the plugs out and we did complete these wells like conventional Barnett shale well we had to use a rig to do a plug clean out. It's not like you do sometimes in East Texas. And when the weather clears up a little bit we will be back in there to do some work on those wells specifically evaluate the frac jobs and the unloading.

Eric Nuttall – Sprott Management

Great. Thank you.

Operator

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

Dave Keyte

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

Operator

Ladies and gentlemen this does conclude today's teleconference. You may all disconnect.

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