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Executives

Patrick J. Redmond - Director Of IR

David H. Keyte - EVP and CFO

H. Craig Clark - President and CEO

J.C. Ridens - EVP and COO

Analysts

David Tameron - Wachovia

Stephen Beck - Jefferies and Company

Gil Yang - Citigroup

Raymond J. Deacon - BMO Capital Market

Jeffrey W. Robertson - Lehman Brothers

Forest Oil Corp. (FST) Q4 FY07 Earnings Call February 22, 2008 2:00 PM ET

Operator

Good afternoon. My name is Christie and I will be your conference operator today. At this time I would like to welcome everyone to the Forest Oil Fourth Quarter and Year-End 2007 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. I would now like to turn the conference over to Mr. Patrick Redmond. Sir, you may begin your conference.

Patrick J. Redmond - Director Of Investor Relations

Good morning. I want to thank you for participating in our fourth quarter and year-end 2007 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.

Before we get started, I'd like to take a moment and advise you about our forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. 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, will, should, or may occur in the future are forward-looking statements.

These forward-looking statements are based on the current belief and assumptions of management using currently available information as to the outcome and timing of future events and are subject to all the risks and uncertainties, normally incident to the exploration for and developments and production and sale of oil and natural gas. These risks, many of which are difficult to predict and many of which are beyond our control include, but are not limited to, price volatility, the uncertainty inherent in estimating future oil and gas reserves and future oil and natural gas production, cash flows and the timing of development expenditures, the lack of availability of drilling and production equipment and services, the risks incident to drilling oil and gas wells and other operating risks, environmental risks, regulatory changes, foreign currency exchange rates and other risks described in reports that Forest files with the Securities and Exchange Commission including its annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K. All of these factors could cause Forest's actual results and plans to differ materially from those expressed in any forward-looking-statements.

I will now turn the call over to Dave Keyte. Thank you.

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

Thanks Pat, and welcome to our 2007 results conference call. Sorry about those of you who are experiencing the cold in the Midwest and the snow in the Northeast, but it sure feels good on the commodity screens today. This year we will have J.C. Ridens, our new Chief Operating Officer, review 2007 operations, and Craig will comment on our investment results as well as the key components of the 2008 plan.

Due to the questions we have received this morning, I would like to first address production guidance for 2008 before I review the record year that Forest just posted for 2007. As you all know, we only owned the THX assets for the last half of 2007. And for the last half of 2007, we averaged approximately 500 million a day of production.

Taking into account anticipated sequential first quarter 2008 decline, which we think will be similar to that experience between the fourth and the third quarter of '07, we are forecasting an approximate mid-point production rate of around 530 million a day for the last half of '08. That approximates to 6% organic growth rate year-over-year.

As we have exhaustively communicated, we design our capital programs to generate 6% to 8% organic growth while living within our cash flow. We have stated that we believe that we can achieve this hurdle even in the short term with the THX asset and we still believe we will. The plan for 2008 achieves these goals despite the decreases we experienced in volumes in the fourth quarter of '07 and the first quarter of '08.

We have mentioned in the press release a growth range of 3% to 11% for 2008. This was derived by us comparing fourth quarter '07 to our estimated fourth quarter of '08, which we believe to be the most relevant comparison, as the fourth quarter of '07 has a reversionary net profits interest taken out of it, and we would expect that to be the same case as fourth quarter '08. I hope that clarifies what apparently was a confusing disclosure by us and for the confusion, I apologize.

I also want to take a second to put our overall capital plan in context with that in our peer group. So you can assess whether our overall drilling acquire [ph] strategy can compete with the drill-drill-drill strategies that the majority of our peers are taughting. Although we understand that the Street now favors organic growth at this point in the cycle, because non-organic growth is considered less controllable, we internally do not analyze it that way, we analyze it based on total production growth and believe our track record, our strategy is controllable.

As you all know, our drilling budget is designed to provide high single digit growth within our discretionary cash flow. This is a unique model in our peer group, as we choose to provide capital for acquisitions as part of our strategy. We thought it will be interesting to compare our all-in capital spending, including acquisitions, and our production growth to others. Our average production rates were 332 million a day in '06, 427 million in '07, and mid-point of '08 guidance is 520 million a day.

For the last two years, which would have generated the growth from 332 million to 520 million, we have all-in CapEx spending of $2.9 billion including acquisitions, and cash flow of $1.7 billion. This represents an investment rate of 170% of cash flow and delivered an absolute two-year production growth of 55% or a compounded annual growth rate of 25%. I will put these metrics up against any capital programs my peers may have, and in addition, we have capitalized that plan without endangering our liquidity and today have over $1 billion of borrowing base, in excess of borrowings on our credit facility.

The basics of oil and gas investing remain intact as they have for over 125 years. The highest margin producer wins. We intend to continue to deliver outstanding margins through investment prowess and operational excellence. Growth will be the result of the formula, not a factor in the formula, and our growth has been great.

Now with that said, comments on our record year. In 2007, we set a number of records for our company, which is a 92-year old company. Proved reserves reached over 2.1 Ts, up 66% and all-in FD&A of $2.27, and more importantly these assets are now all located in strategically important areas for us.

Adjusted earnings established a new record at $223 million, up over 100% from last year as cost control helped drive increased margins to new levels per unit. Records were also established in adjusted EBITDA and discretionary cash flow as they grew to $871 million and $742 million respectively. Cash flow per share increased 66% to $9.75 per share.

Interestingly, cash flow per share is up 66% year-over-year and the stock price is only up 56% year-over-year. So with all the records we were able to create in 2007, including an outstanding investment in a good cost control year, we lost ground on our cash flow multiple.

In addition to these importing operating records, the company also executed the $1.6 billion acquisition of Houston Explorations, its largest acquisition ever and followed that up with funding provided by the sale of its non-strategic Alaska assets for over $400 million. As a result of operational excellence and the strategic improvement in its portfolio, Forest's shareholders experienced a 25% debt adjusted increase in production per share, a 17% debt adjusted increase in reserves per share, and a 56% increase in the share price during 2007.

These results, while extremely positive, were accomplished with the portfolio that, in our opinion, still needs work to increase its efficiencies. As Craig will detail, in 2008, we'll be further focusing additional capital into our known growth areas and establishing a large divestment program for our lower growth areas, and also implementing a new cost reduction program which he will get into as well.

With these refinements, we anticipate targeting higher organic growth rates in the future, higher than the 6% to 8% organic growth we have consistently delivered, and I think you'll like the plan. But let's review our fourth quarter and record year first.

The headline for the fourth quarter can be summarized as superb investment results and margin extraction drives better than expected results. In the fourth quarter, we slightly outperformed our expectations and posted a 181% increase in adjusted net earnings to just over $70 million from last year... this year over the last year, and a 103% increase in adjusted net earnings per share. The key to the quarter was higher cash margins per unit driven by $1 per unit increase in revenue and a $0.50 per unit decrease in cash cost. That is remarkable.

Production volumes decreased sequentially due to operating issues on non-operated properties in the Uinta Basin and the southern foothills of Alberta, as well as the previously discussed net profits interest reversion at our Rincon Field, which reached payout.

Volumes were up in the fourth quarter of '07 over '06 by 74%, primarily due to the acquisition activity in '07. Cash margins in the fourth quarter increased by about 50% to $5... to over $5 an Mcfe from $3.43 per Mcfe in 2006. Realizations improved by about $1.13 per Mcfe due to increased commodity prices, and cash costs decreased 17% or $0.46 to $2.32 per unit from $2.78 per unit. The decrease in cash cost was driven by an almost $0.50 per unit decrease in production expense, offset by higher interest expense and modestly higher G&A expense.

The DD&A rate was $2.68 per Mcfe and reflects essentially our four-year FD&A costs plus about $0.25 to $0.30 of deferred tax gross up under purchase accounting for acquisitions made.

EBITDA during the quarter increased 105% year-over-year to $266 million from $129 million in '06. Discretionary cash flow increased 132% to just over $100 million... from just over $100 million in '06 to $238 million in '07. Investment results for the full year of 2007 were outstanding. We are now over 2.1 Tcfe with an all-in FD&A cost in '07 of $2.27 per unit. The FD&A recorded should place us somewhere near the top quartile or quintile of all E&P companies this year, despite the fact that FD&A costs seem to be coming down across the board.

This is particularly impressive considering the acquisition of an asset base that had a poor history of delivering solid investment results with historical FD&A of about $4 per Mcfe. Also impressive is that the FD&A costs for 2007 include a net addition of over 700,000 undeveloped acres in the Lower 48, or an increase of over 300%. If you took the approach of some companies and allocated even as little as $500 an acre to this acreage, our FD&A costs would have been 20% lower.

These types of investment results can't be taken lightly. We have now spent $4.4 billion over the last four years at all-in FD&A costs of $2.19 per unit. The results have been consistent year in and year out with a very narrow range of $2 to $2.27 over that period of time, despite much higher costs in services and equipment.

Overall, the fourth quarter came together slightly better than we had expected, the year was spectacular. Record operational results, 700% reserve replacement at $2.27, a much improved asset base with thousands of locations yet to drill, and a very clear vision for what we need to do in 2008 to deliver additional value.

Now turning our attention to 2008, I will outline the guidance or the numbers involved in 2008, but more importantly, Craig will talk about the strategic initiatives that will be undertaken in 2008. The 2008 guidance is built on a plan of $900 million to $1 billion of CapEx. It does not consider any dispositions which we will be planning to do. The production in 2008 is expected to range from 183 Bcfe to 190 Bcfe. This implies a growth 3% to 11% comparing fourth quarters in '07 and '08.

The mix should be about 75% gas, 15% crude, and 10% NGOs. Differentials are estimated to be $1.25 to $1.50 for gas based on NYMEX price of $7 to $7.50. Oil differentials are estimated at $6 to $8 based on current NYMEX levels, and NGO should realize about 50% of NYMEX prices. Production expense, including production taxes calculated at $7 to $7.50 NYMEX, should be in a range of $250 million to $270 million, consistent with the fourth quarter.

G&A expense, not including stock-based comp, should be $55 million to $60 million, again, consistent with normalized fourth quarter. Total cash costs, including interest and cash income taxes, are expected to range from $2.30 to $2.40 compared to $2.68 in '07.

DD&A is expected to be $2.70 to $2.80, in line with the last full year's FD&A adjusted for deferred tax gross ups under the purchase price accounting.

All in all, for 2008, we see another record year in the making and when the impact of property sales is more visible, we are aiming to increase our organic growth rate coming out of '08.

With that, I'm going to turn it over to J.C. who will review... oh, you are going to take, Craig, I'm sorry. We don't have the three man deal down yet. I'm going to turn it over to Craig and Craig is going to review with you the '08 plans. Go ahead, Craig, sorry.

H. Craig Clark - President and Chief Executive Officer

Thanks, Dave. It's another good quarter for the company and our shareholders, and more importantly, an excellent year in the long history of Forest. Although we had lots of records, as Dave mentioned throughout the company's results, the biggest single accomplishment I think is completing all of these transactions ahead of schedule and achieving a new 17-year high for our stock price.

Certainly we continue to transform this company while adding value along way. We can add value from the drill bit, and transactions, operational efficiencies or even from technology. But for us, it's all of the above, not just one. And fiscal 2007 had a little bit of everything, from buying Houston Exploration to selling Alaska to monetizing the drilling rigs, to exploration success in international. Again, from all of the above.

In 2007 and going forward in 2008 and beyond, our job is to make a profit and prudently spend capital, not randomly project reserve potential. Furthermore, I guess a good description of us would be that we excel in margin extraction and CapEx allocation; that may be our job description. We have sometimes called fixer-uppers by the sell side analysts, but I'd prefer value adders. With this year's numbers, particularly in the areas of cost and reserve additions, you get a glimpse of the profitability within this company when profits are not blunted by rising costs or overspending. And by cost, I mean everything from drill bits to administrative overhead.

Discipline, more specifically, spending discipline, may be the hallmark of this company. For the year 2007, the major highlights and I'll go through these quickly, in addition to the aforementioned records in reserves, earnings, and cash flow are as follows. We closed over $2 billion in transactions, primarily Houston Exploration and Alaska divestiture, while also completing an attractive bid offering immediately following, as planned, the Houston Exploration acquisition. Dave and his team did a terrific job here.

Over 2 Tcf of reserve for the first time replaced over 700% of the production at an all sources F&D of $2.27 per Mcfe. Further, the organic reserve replacement was 236% at a cost of $2.21 per Mcfe, while not overspending our cash flow significantly.

Production grew by 50% from a year ago, a whopping 74% from the same quarter last year, and we reduced operating cost per unit from a year ago by 26%, including reductions on the newly acquired properties. As Dave mentioned, we quietly added about 700,000 in undeveloped acreage in the Lower 48 in Canada following Alaska. We booked our first reserves in international ever in the history the company outside North America with the Italy discovery at approximately 50 Bcfe. And last, but not least, during calendar 2007, the price of Forest stock rose 56%, which ranks near the top of the class in terms of price appreciation.

In my presentation today, I'll go through the overall results and then J.C. will follow with the operations report, and then I'll do the 2008 plan in greater detail. All of us will answer questions at the end, if you choose.

Let's start with the metric everyone focuses on at year-end reserve replacement success, another great year for Forest, and more than just overall growth in reserve, but also in terms of the amount of CapEx in which we had to expose to add these reserves. In other words, we had 236% organic reserve replacement while spending about our 2007 cash flow. We also stated the same percentage of undeveloped reserves are PUD [ph] neutral. These results confirm that we did what we said we would do, so you can check that box.

The 703% all-in reserve replacement is by far our best year and set the stage for a record proved reserves. The $2.27 all-in finding cost is highly influenced by the Houston Exploration acquisition metrics, but is very favorable whether it's considered all-in acquisition or organic, no matter how you slice and dice it.

Speaking of organic reserve replacement, we had an excellent year with the drill bid replacing over 200% of our reserves at solid finding cost. But excluding the revisions, the F&D cost was lower than that of $1.99 per Mcfe.

The $2.21 organic finding costs are even more impressive when you consider that the Houston Exploration's assets we purchased six months ago at a cost, I believe, in 2006 of around $3.78 F&D. So, we brought the finding cost metrics in line and on the new property base much quicker than we thought by prudently reallocating capital on these assets.

As I have been saying for a year now, the priorities for any acquisitions, but particularly on a corporate one this large, were to close and takeover, integrate the people and systems, extract synergies from the integration, specifically G&A, work on cash cost reduction opportunities, cease the overspending of CapEx, and then shut down the least economics CapEx spending, which I think is the key to stop failures, no matter how fashionable the geologic play is. All of this has been done to date in only six months of Forest operatorship. And finally, capital reallocation to better projects, which is in progress.

So, there is again margin extraction in capital allocation, which worked pretty well to date on our newest property base and I am pleased with the reserve growth and associated finding costs, I couldn't be more pleased with those costs in 2007. I should note also that we've included in our CapEx spending and finding costs, resultant [ph] the large amount of undeveloped land post-Alaska, which we quietly built up, as Dave said, about 700,000 acres in the Lower 48 in Canada.

Again, when you do a corporate deal, you do get other stuff, and in this case it includes some undeveloped land. I should note the negative reserve revisions broken up in the table for all of you, we broke all that out for you in the press release, so primary revisions that relate from higher exchange rate-driven LOE in Canada, some of the area that was up in LOE for 2007, different type curves for the step out wildcat areas of the Texas Panhandle, and a few PUDs from the Houston Exploration acquisition that were less than predicted while we shifted our program around. We are going to be conservative on reserves in new areas until we see another year of performance.

In terms of capital spending, we spent $777 million last year to drill 495 gross wells and approximately 285 net wells in 2007. Our success rate was excellent at 96%. I should note that the gross well count again includes a low working into San Juan Basin unit wells that make the gross look high. We operated most of the wells in the total though, so following the sale of Alaska, the company becomes increasingly an operator producer as opposed to several years ago. Most of you know, this was a personal objective of mine when I took this job.

We've also performed a significant number of operations projects, over 650 that were capital spent on the properties either we acquired or our base properties that enhances their value. I guess this is the fixer-upper part comes from our project FOCUS program, which also involves, as you know, operating cost control.

On the production side, we averaged 494 million a day... equivalents a day, up 74% from a year ago, but down sequentially from last quarter. The decline, as Dave said, can be attributed to three factors, two of which we anticipated the reduction in the net profits, the reduction in net production due to the reversionary interest or we call it an NPI [ph] at Rincon, the Shell le Waterton plant had a sour gas leak in November that... and remained shut in. This affected us by about 5 million a day net, and also prevented the last two horizontal completions from coming online, the first of which we noted last summer at 14 million a day, we have 12.5% of this production.

Shell informed us that pending the regulatory review, the plan of this pipeline can possibly be offline for most of 2008. The shut-in and deferred completion of a dozen Uinta Basin wells because of the low Rocky Mountain gas prices in the fourth quarter pretty much sums it up.

We have the usual winter downtime that everybody has. We even sold the Waha pipeline down in the Permian, but we offset these outages with better anticipated production in East Texas and South Texas.

However, despite this downtime, we were within our guided range, which is especially good considering lower CapEx spend rate. The lower spend rate in South Texas and the Waterton plant outage that Rincon NPI [ph] carry into the first quarter and are the main reasons we lowered the first quarter '08 production guidance, and we will... which will continue creating the sequential decline. But production is expected to then accelerate at a better clip for the remainder of '08.

In terms of operating costs, tax costs, we had another excellent year in reducing our per unit cost. Our LOE per unit decreased 26% from a year ago. The efficiency gains or margin extraction, as I'd like to call it, continue despite high industry costs and higher service costs that didn't mitigate until late in 2007. I saw a company highlight this year that their LOE increased the smallest of anybody in 2007. Heck, our costs were on the decline since the start of the four-point strategy several years ago. These gains in costs came from the sale of Alaska, the addition of gassy assets from Houston Ex, but also the reduction of LOE on the Houston Ex properties, and from our internal cost control program that J.C. calls project FOCUS.

We just finished up project FOCUS in Canada and are now sending the team to South Texas. They better hurry because the Southern Business Unit led the way on cost cuts in 2007. Our fourth quarter $1.35 per Mcfe overall production costs ranks favorably in our peer group, especially when you consider we have about 20% oil.

Our total cash cost number, including G&A, interest and taxes of $2.32 per Mcfe ranks even more favorably in the peer group, especially when G&A per unit is included. Our G&A cost ranks well, as Dave noted, and looks appropriately proportional in my belief to our overall cost structure. I have seen some numbers for G&A this year in the industry due to higher per unit than LOE, I don't agree with that, it's a lot tougher to control cost out in the field than in some air conditioned office. I commend our production folks, more than you can imagine on the job they have done in cost in 2007.

The operations highlights in the press release are separated by business units. So you can see the drilling activity at year-end, as well as their anticipated drilling project count for 2008. The major highlights were summarized in the release according to the Big Five, which will continue to drive the company results, still contributing about two-thirds of the company's production in 2007, but they will see more CapEx in '08.

We substantially added to the Big Five project inventory in 2007, including some of the undeveloped land that Dave mentioned that we purchased. I will now turn the call over to J.C. to cover the operations highlights.

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

Thanks Craig. We'll start with the Western Business Unit. In 2007, Western production grew approximately 9% from the previous year. This business unit drilled 277 gross wells with a 95% success rate. This is the premier resource program and the gross well count in this business unit alone is as many as all the Forest drilled a few year ago. We anticipate 250 gross wells in 2008, with increases in our growth areas such as adding a sixth rig at the Buffalo Wallow program.

Buffalo Wallow is our single largest producing field and continues to the big driver for the business unit with production approaching 50 million cubic feet per day during the quarter. The total of 63 well were drilled during 2007 with 100% success rate. IPs from this wells ranged from 1.8 all the way to 8 million cubic feet per day, with the higher rates being achieved in the step out areas. Even though we have stepped out, we have yet to drill a dry hole in this play and our success rate remains at 100%.

At year-end we had five rigs running out here, two on the shallow field acreage and three in the step out areas. We planned to balance that out in 2008 by adding a sixth rig. The initial rates in the deeper areas were higher than the main field. So we will have to see how these well decline after about a year of production to determine whether we are on the same type curve here or getting a bigger contribution from the deeper Atoka zone.

The only variable left in Buffalo Wallow is how fast we will drill the remaining 700 unbooked locations and what happens on the remaining undeveloped land. I should note these 700 locations are based only on the current drilling to date and the current spacing. This number could be more than double with 20 to 40-acre spacing assumed. We'll go into detail about Buffalo Wallow on our other big projects at the upcoming analyst conference in April.

Our well portfolio in this business unit is largest in the company. We continued our development program in the Text-Mex field, where production was up almost 50% in 2007 alone. In 2008, we'll look at water floods in several of our newer Permian oil fields, where primary development has now identified the field's aerial extent.

In the Vermejo area of the Delaware Basin, we will resume exploratory drilling now that the new 3-D is in hand. We'll start at one rig deep drilling program approximately mid-year. Activity is picked up in the area quite a bit recently, and we will follow up with our own.

In the Rockies, we resumed completion activity on wells that were previously drilled in the Uinta Basin. As Craig said, those were drilled during the time of depressed pricing and now the completion activity has picked up. IPs on these wells were better we have seen previously and have averaged about 1.5 million cubic feet per day, which represents a significant improvement over the previous average of about 700 million Mcf per day.

We are encouraged about our high grading effort on these prospects. The deep Mesa Verde, Mesa Verde, Mancus, and Dakota play continues to evolve near the northern portion of our large acreage plot. Plans here are to drill about 20 wells in 2008, including testing the deeper objectives.

Moving on to the Eastern Business Unit, this business unit has exceeded expectations for the quarter and for the year. Mark Bush and his team have done a great job of integrating new assets and keeping both them and the legacy assets growing. Their production increased 52% from last year, primarily from East Texas.

In 2007, they drilled 114 gross wells and had a 97% success rate. They expect to drill 178 gross wells in 2008, with most of the higher activity being in East Texas and a full year of the Arkoma Basin drilling. The East Texas program is doing very well. Production here was north of 50 million cubic feet per day for the quarter, and that's up about 150% from last year. As stated earlier, they now have a second horizontal Cotton Valley well completed, which is 7.8 million cubic feet per day, has exceeded the rate achieved on the first well by a significant margin.

The third horizontal has been cased and is pending completion. Based on the successful horizontal program, we will now be running two rigs on the horizontal program in 2008, with three rigs drilling vertical wells in the more densely developed portion of our acreage. With this program, we'll drill 12 horizontals and 40 vertical wells in 2008. We envision more horizontal activity company-wide, but particularly in East Texas. I should mention that one reason we entered East Texas two years ago was the opportunity for multiple targets within the same basin.

Although we never envisioned the horizontal success, we did see the multiple tight gas opportunities, fractured carbonates in the James Lyman Pewit [ph] and even the Bossier interval. We have even been looking at a the deeper horizontal Austin Chalk opportunity recently. We have two of our Lantern rigs deployed on these assets and they continue to perform well, so well in fact that may add another one of our company-owned rigs to this area in 2008.

The Arkoma Basin has continued to yield good results as well from shallow air-drilled wells. Production was essentially flat to the previous quarter at about 40 million cubic feet per day, as we completed line looping and compression projects which were designed to keep the high rate completions from knocking the older wells offline. We've seen IPs from this play range from approximately 1 million to 7 million cubic feet per day. We've converted two of our Lantern rigs to air-drilling and we will add a third industry rig in this area in 2008 as well.

Overall, we drilled 50 gross wells in the Arkoma in 2007 with a 98% success rate. With the third rig we are adding, we expect to drill about 100 wells in 2008, including non-operated wells where we are participating on a horizontal program with the operator of the offset AMI [ph] with two wells currently drilled and undergoing testing.

This business unit continues their development of the Barnett Shale as well. The last two wells in the Barnett tested 1.5 million per day each and we are beginning to see somewhat predictable results from this program. With our recently completed transaction on Erath County, we are now ready to begin drilling there in the second quarter on our expanded acreage position, which now totals almost 62,000 gross acres. We have now established a large enough acreage position to make this material to the company.

The Erath County wells are expected to be somewhere between three quarters to 1 Bcf, so keeping cost down here is going to be important. To help us out, we will probably move yet another of the Lantern rigs out of the Permian Basin to cost control in the play. Overall, we planned to run a three-rig program in the Barnett for 2008, and our upfront acreage and seismic costs, or what we would consider cost of entry, remains fairly low in the Barnett play.

Moving south into the Southern Business Unit, in 2007, there were 35 wells drilled in the business unit with an 87% success rate. This BU has also lowered their LOE substantially, about 9% since we have owned these assets. That's a great result and as Craig mentioned earlier, project FOCUS is going to kick in there in 2008. We hope to drive those even lower.

As we have mentioned earlier, the activity was deliberately slowed in the fourth quarter to allow seismic evaluation to catch up with drilling activity. While we may have reduced activity too much late in 2007, which caused production to decline, I think that we are on the right track in high-grading the portfolio using 3-D seismic, as you can see in our F&D results.

Fourth quarter initial rates of Charco field were good, 2 million to 9 million cubic feet per day. We have already ramped activity up to six rigs in the business unit. Approximately 59 wells are planned in 2008 with activity focused on the Charco and Katy fields for the Wilcox objectives, and Rincon, PCB and McAllen fields for the Vicksburg. Even with this level of activity, this business unit continues to be our largest free cash flow generator spending only 50% to 60% of their cash flow in the last half of 2007.

The most notable success in South Texas during the fourth quarter was at Katy field, one of the legacy Forest assets. We drilled an infill Wilcox well which logged 5 pay zones. The first zone completed, has tested at rate as high as 7 million cubic feet per day. This is a huge success for a field that was only producing 13 million cubic feet per day, when we took over operations 18 months ago. Katy production achieved a new record of 28 million cubic feet per day during the quarter and continues to grow with an additional extension well cased this month.

Looking north to Canadian business unit in 2007. Canada drilled 60 gross wells at a 98% success rate, in typical Craig fashion, he wants to know who drilled one dry hole. Our 2007 production particularly the fourth quarter was affected by the water complaint and pipeline delays on non-operated properties. Deep basin drilling continues to be successful at Wild River, Ansell and Hinton. Below the Ansell and Hinton are coming in at higher rates from the deeper craterous zones but none of these came online by the end of the year, due the Ansell plant being at capacity and the Hinton wells not being tied in.

These will add to our 2008 production ramp, beginning in the second quarter. We're evaluating shallow zones in addition to in-fill drilling at Wild River. We currently have 7 rigs running in the deep basin including non-operated rigs where our acreage totals 70,000 feet gross acreage approximately. In addition to that, we are running two rigs on our shallow oil program. We've completed one horizontal well in the EV oil field and we are preparing to complete a second.

Testing of these wells will determine if the horizontal application is appropriate for this asset. With horizontal drilling now being done here, we currently have operated horizontal activity in East Texas, the Barnett Shale, Canadian shallow.

Finally, speaking of the international business unit, special mention of them should be made this year since they booked gas reserves on their two Italy discoveries. The first time in our history we've booked reserves outside of North America and we did it in a pretty substantial way. On the Monte Pallano discovery we found over 50 Bcf of gas and we need to drill at least one more well there in addition to the two we have already completed.

The reserves include the deeper pay that was found in the first well. As we've stated earlier, we are working on the permitting of the production facilities and pipeline. We estimate about a year for sales to occur. The Italian gas market remains robust currently at $17 per Mmbtu U.S. Our discovery here is material to the country as they are large importer in natural gas and this is significant value that we have added to international portfolio. Craig?

H. Craig Clark - President and Chief Executive Officer

I'll go through the 2008 plan in detail and try and hurry through it so that we can get to the questions. There are three major components to the 2008 plan that are designed to reduce cost increase, capital efficiency, more so than we did last year and boost our organic growth rate beyond what we have experienced the last four years. We have now fully integrated the Houston Exploration acquisition, it is safe to say and have lived with these assets and others that we required long enough to begin to select those outstanding assets which require more capital on those assets with lesser growth and economic viability.

With these initiatives in 2008, we will come even more efficient on our margin extracted than we are now. First, we will significantly increase the activity focused in places like Buffalo Wallow, the Ark-La-Tex area, South Texas and the Deep basin in Canada. These assets have shown through as areas with significant success with barge land position, excellent economics, good growth and are well understood by us.

In 2008, we plan to increase the combined rig count from just these assets alone from 18 currently in the fourth quarter of 2007 to around 27 in 2008. The capital allocated to these areas will of course increase as well in 2008. But we will basically shift CapEx within the portfolio to accommodate most of these increase. That's why we have a portfolio. As we already do in a year we look at capital spending efficiency and cash flows quarterly for reallocation.

While pounding the golf ball up to middle on these assets we believe we can most effectively accelerate our large inventory of projects in these areas. Secondly, as an initiative to high grade our portfolio we are going sell zero to low growth assets primarily in Western, including from the THX asset base. The no-growth fields dilute our good work on the big five assets in the next growth area for the up and come category. In some cases these assets require disproportional amount of maintenance capital.

In the past, we had chosen assets to sale by estimated geography or poor margins specifically LOE but now we can't move the needle on our cost efficiencies much by selling a single margin or field due to our current low cost structure. The value of this property base instead of the usual $100 million of marginal fields we have been on the sale each year could be in the range of $300 million to $500 million. The pieces of these package are still being worked out... will become what will come from all business units.

I should note that the proceeds of what will not be considered as free cash flow, we still intend to fund our drilling with operating cash flow. This sale would enhance the overall growth profile of the company and increase our efficiencies company wide. We've shown in our road show look-backs for acquisitions that we have done at one on acquisitions as we have on divestures. In fact, our road show presentation we show that our team is credit value not only in the stock price, but we've also treated the values of ports as private. In other words, from an entrepreneur standpoint, our equity value is up over 30% per year, since our new strategy was undertaken on this slide.

Finally, we're going to reduce our costs once again in '08. We saw some overall decreases in late '07. I'm talking about drilling costs mainly here. But 2008 should provide some additional savings. We recently bid large packages of drilling in completion services in the U.S. and Canada separately and received on average 15% to 20% discounts on major services, like stimulations, cementing, logging and rigs. Some services like tubulars, directional drilling and mud didn't move much due in part to tubulars coming down earlier or due in part of those services demand.

Canada's discounts I should note, were larger than in the U.S. So maybe we can get some of the margin back, we tried to get starting mid 2007. Our larger position with the combination of Houston Exploration in certain basins has certainly helped these packages. Out track record is excellent here and reflects being at the top quartile of our peer group. We also will continue to work LOE that's just a normal function around here, through project focused initiatives.

This program has made us million of dollars and should continue to reap dividends. The specifics of our plan call for spending to be in the range of $900 million to $1 billion essentially flat with the post Houston Exploration run rate and consistent with what we projected over a year ago. This CapEx was derived from our cash flow projections and not baked in to deliver some growth number. The CapEx in each business unit will be reallocated to achieve the overall objectives.

I'll try and rough out the CapEx for some of the analysts about each business unit, Western will be about $300 million for the 250 gross wells J.C. referred to, about 70 is in Buffalo Wallow alone. That does include the low interest wells in San Juan. In Eastern, $280 million for 178 wells, 150 of those are in the Ark-La-Tex area, Southern, $215 million for roughly 60 wells, Canada, $135 million for roughly 60 wells more than half of those are in the Big Basin.

In new ventures international, $20 million primarily for infrastructure in Italy and their shale gas operations. That totals around $950 million of CapEx which is the mid-point at about 550 wells. These totals do include taking a few more exploration shots in South Texas, South Louisiana, Vermejo/Haley, now that the 3D is in, in Canada.

In terms of our guided production for 2008, we expect the first quarter to decrease simply due to the unexpected hangover from 2007 like Waterton plant, the gas shutting in the Big Basin in Canada and items that we did expect due to significantly reduced spending in the Rockies and South Texas in the fourth quarter. With the cuts in CapEx spending on the newly acquired properties specifically South Texas, we did expect a decline and we got it.

In fact, the low percent of cash flow Southern is spending way low, we may have reduced activities too much in the name of hydrating. We need to get back in the driver seat now that we fixed the vehicle. Unlike the past two years, the production guidance will be more back end loaded than normal as we bring in the shut-in wells on in the second quarter and benefit from higher drilling activity in Southern beginning in the first quarter.

We have a wider range of guidance than usual due simply to the inability to predict if the Waterton plant in Rincon, NPI [ph] return back to Forest during the year. However, our last three quarters growth rate should be on an annual rate closer to 10% rather than our usual 6% to 8% as our improved spending takes hold. So, our 2008 plan has been mapped out and we believe it can be carried forward in years to come. We will become even more efficient not only in capital allocation, but in cost control and portfolio quality.

The goal is to emerge from 2008 with a lower cost structure, yet lower, and a higher organic growth reserve base than when we started as we continue to upgrade and not live with the hand we are dealt. We believe in this plan and we will be discussing the 2008 as another record year probably in 12 months, looks like we are off to a pretty good start based on what we did in 2007, with the properties we have got. If prices and cost hold, this plan should deliver record production, earnings and cash flow in yearend reserve. All by investing new money prudently and efficiently operating these assets.

Not a sea-change in strategy just continual improvement in our model.

Let me reiterate how pleased I am with the records gain in fiscal 2007. Our 1 p [ph] reserves are proven over two Tcfe are certainly valued conservatively in terms of our peer group. And folks that's 1 p reserves. I am not talking about probable and possible. I think all of our employees have done an excellent job in 2007 using all of the above to add value for our shareholders.

I believe they are up to the challenge as we laid in 2008 in order to deliver another great year. Thanks for listening today and we'll be happy to answer any questions, operator?

Question And Answer

Operator

[Operator Instructions] Your first question comes from the line of David Tameron of Wachovia.

David Tameron - Wachovia

Good afternoon. Dave, real quickly, midpoint of guidance, is that 510?

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

Yes midpoint of guidance is 510.

David Tameron - Wachovia

Okay, and everything you're referring to is off of those numbers?

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

That's correct.

David Tameron - Wachovia

Okay. Second, Cotton Valley, I don't know if this is. Craig or J.C., could you talk a little bit about, what are you expecting. I know it's not some targets before 3 to 1 anything, if you can give us a little more detail going forward of what well cost are and IP, ZORS, et cetera.

H. Craig Clark - President and Chief Executive Officer

Yeah the, three to one still holds vertical and that's just because of the well cost, we've exceeded that and J.C. you want to comment on the cost.

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

Yeah, we've seen the cost come down, the last well that we got down was quite a bit cheaper than the first one, as a matter of fact we lowered the cost by about a $1 million for the third one based on that. Total cost is about $5 million is what we are projecting for this last well.

David Tameron - Wachovia

Okay, and to add, I mean to go from not sure if we're going to drill horizontally or taking a wait see approach and then adding two rigs, just after drilling two wells or drilling your third well, why are you so encouraged, I guess? Is that other results as well from industry?

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

No it's actually well, it's our results, remember we in picking the horizontal candidates we tested individual zones in I think six different areas and it's the testing in individual areas which includes some of the newly acquired acreage from Houston EX, that we are encouraged as we test single zones in areas that are relatively undeveloped. The industry obviously has provided some positives to that, but it's based on our own single well testing.

David Tameron - Wachovia

Okay, jumping to Italy did you give us a number of how many reserves you've booked associated with Italy, what the number was?

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

The number was 56 net for the third-party engineers and that will include I think an additional well whenever you're getting rate to come on line but we... those wells plus the seismic plus the wells drilled 30 years ago have closed the structure and it came out at over 50 base.

David Tameron - Wachovia

So, 56 net implies special gas prices right now that you can generate, well north of a 100 in asset sells, is that fair? If you choose to sell that asset.

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

A lot, more than that. The gas price is tight in the formula to crude, your choice of gas market would be either tied that to that formula which is high that's where you got the 17, or do term contracts on fixed priced basis, they need the gas desperately. The pre-tax PB tenants over $400 million.

David Tameron - Wachovia

Okay, that helps. All right, I'll let somebody jump in and I will jump back in the queue, thanks.

Operator

Your next question comes from the line of Robert Lind [ph] of Simmons and Company.

Unidentified Analyst

Question regarding capital allocation, your '08 budget of $900 to a $1 billion, if the current strip holds where it is and plus you get some proceeds from dispositions. Do you increase above that $1 billion in spending and where does it go? To your port into the big five sort of the same allocation you have now or does that move into other new venture exploration areas?

H. Craig Clark - President and Chief Executive Officer

We've kind of held the line on capital spending, I think the work has been told militaristic when describing some of us around here, but the fact is this that... that's why I like to go in below cash flow, it gives you the flexibility to do every thing from acquisitions to shifting capital, its tough to take away and also if you have the exportation success you didn't count on. We will probably stay in that range but I want to emphasis that we do shift capital from business unit to business unit like we did last year to East Texas.

Unidentified Analyst

Okay. And then just a question for J.C., in South Texas ramping up to five rigs implies that you like what you saw on the 3D seismic, can you tell us how many of these rigs are going to go after maybe some deep structures that you saw on the 3D?

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

Yes. We have got one rig targeting drilling some stuff at McAllen Ranch where we haven't been active in a few years, we reworked that with the new Southern team. And then also we have got potential to drill a deeper structure and in around the Rincon area. And we will also be continuing to pound the ball at KD with the results that we have had there. So, I think that what we see out of the 3D that we have been working on is our confidence factors is little bit higher with the Charco program, certainly the results that we have seen at KD yield great results, and so I think that's why we see on the ramp up in the activity now Robert.

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

Robert I think it's safe to describe that is not just deeper but more step out like including in different counties.

Unidentified Analyst

Understand. Thanks guy that's all I had.

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

Thanks.

Operator

Your next question comes from the line of Stephen Beck of Jefferies and Company.

Stephen Beck - Jefferies and Company

Good afternoon. I would like to shift focus over to the Barnett a little bit. Can you talk about what volumes are and what your gross potential is for this year?

H. Craig Clark - President and Chief Executive Officer

The volumes, only production we currently have net, I think it's a couple of millions day [ph] net, is only on... there is only owned, have got some royalty [indiscernible] in Hill County. There is no production over to the west or any of the undeveloped land outside the original core area that we drill. I think we maybe only drilled five or six wells. And I am not projecting potential, you could at 80 acre or 100 acre spacing you could fit a lot of wells on 70,000 acres gross, but you'll have a lot more wells over on the West because they are shallow and you can drill them quicker, we anticipate running three rig program. One that's the continual program in Hill; two, on the shallow post holes, for lack of a better word, that we have got out West, but you have got quite a few wells to drill only there's only been 19 wells total I think drilled on both blocks. So you got a lot of running room, and of course, our partner in one case had to slow down because of capital requirements and that's where we come in including getting hold of the seismic and all the other things JC referred to.

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

And that net production of 2 million a day is reflective of only having a 50% working interest in those wells.

Stephen Beck - Jefferies and Company

Okay. And, then can you tell me how much acreage you have in the North Dakota baakin [ph] and what you are thinking about doing there?

H. Craig Clark - President and Chief Executive Officer

We inherited some of that acreage, we have some of it before, it's probably a stretch to call it, North Dakota Balken [ph] but it's up in the play area and I believe it's 25,000 acres and it came from the Houston Exploration acquisition and we have yet to, we formed a JV on one side of the acreage with a partner but we've yet to drill a lot of it.

Stephen Beck - Jefferies and Company

Okay. And then you provided the pre-tax PB-10 number. I was wondering if you could provide the undiscounted number... the undiscounted cash flow?

H. Craig Clark - President and Chief Executive Officer

I just don't have that with me. I am sorry. The answer is, I'll have to call you back on it, I guess. Probably actually, I am just getting a nasty look from my lawyer. I guess I am not going to call you back. But you got to wait a week for the 10-K. It'll be broke out in the K for you, because it is a different segment, so you will have it broke out in it.

Stephen Beck - Jefferies and Company

Okay. And then

H. Craig Clark - President and Chief Executive Officer

I am sorry.

Stephen Beck - Jefferies and Company

That's all right. And then last one for me is can you tell us what the volumes that are there being sold with the assets?

H. Craig Clark - President and Chief Executive Officer

We haven't identified the package yet. So it's going to be, it will not be a small package, so the volumes that are going out the door, both, in terms of reserves and production will be impactful to the company.

Stephen Beck - Jefferies and Company

Okay. Thank you.

H. Craig Clark - President and Chief Executive Officer

Thank you.

Operator

Your next question comes from the line of Gil Yang of Citigroup.

Gil Yang - Citigroup

Hi. I have a bunch of maybe a little questions, As you go forward are there any other reversions or anything like that we should know about in the next couple of years?

H. Craig Clark - President and Chief Executive Officer

No.

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

No.

Gil Yang - Citigroup

Okay, so Rincon is sort of one time only thing?

H. Craig Clark - President and Chief Executive Officer

Yes, it's kind of like a foreign production deal where it is a production sharing contract.

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

It comes in and out depending on your spending and commodity prices deal and as you know that's a different accounting treatment than Hostonex had.

Gil Yang - Citigroup

Okay. You are not saying this could come back. You are just saying that.

H. Craig Clark - President and Chief Executive Officer

It could.

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

The more... if you spend money it reverses the net profits calculation. That's why the guidance is a range. We don't know if it will come back in '08, but as you spend money you get some of that back. If you spend enough to zero that calculation out at any given month.

Gil Yang - Citigroup

So, did you start drilling at Rincon again you might be able to crawl back into the...

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

But you get to drill more than one or two wells. You got to have a, like Houston EX, drill the number of wells and that's why it didn't revert in until we took over I guess in the fourth quarter.

Gil Yang - Citigroup

Okay, in Uinta has your operator... is there still some risk that the operator, the gas prices have dropped at some point would slowdown activity again and have they put in bases hedges and have you done the same for the area to prevent that?

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

We slow the activity down. As you know we also took over operations. We slowed that down because of the overspending that was occurring at Houston EX, so we slowed that down, not the completions but the drilling part. The reason the completions weren't done in the fourth quarter is you didn't want to leave those well sit in, or sell $1 gas or whatever the price was, that activity has resumed but it starts with about a dozen completion wells that we drilled mid to late last year. And we would, obviously, like growing some efficiencies with well cost coming down as rig rates have but resuming of it basically is a factor of gas price which was horrid last year compared to what it is right now.

H. Craig Clark - President and Chief Executive Officer

Just to be clear, we took over operations on a minor piece of the field, not the whole field. That was targeted.

Gil Yang - Citigroup

And so what the operator chooses to do will take a large chunk of that production?

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

That's correct.

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

And we have rights to elect and not elect, but basically we... as you know that was a large area for over spending previously and we took care of that.

Gil Yang - Citigroup

Okay. Dave a question for you is... you've mentioned few moments ago talking about... you prefer to look at overall growth... after the divestitures, you know obviously your production will drop from the current guidance as oppose but then you have more cash would you accelerate spending to the point where you could offset the reduction in volumes from the asset sales?

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

Yang I really I don't think so, all right, we've never gone a year without an acquisition. So, although I usually accuse my CEO spending it before we have it, he has been remarkably quiet for about six months. So I am thinking that that capital will be better deployed in the areas that are adjacent to areas we're having good success in, those won't surprise you, Panhandle, East Taxes, Ark-La-Tex, South Texas. Those kinds of areas will attract our capital, and we just think that we can do better a job of getting rid of the... how to know grow assets and be able to increase our organic growth rate.

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

Whether we drill or acquire makes no difference to me although then we have got lot of drilling to do. But if... I wouldn't look to add in the areas that were successful I couldn't add enough acreage in places like East and South or North Texas.

Gil Yang - Citigroup

Do you think that if you added acreage you tend to be adding un-producing... not producing acreage, so your net be a lost... that you'll have a net loss of production or would you able to buy? What is it going to do?

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

I think that I would guess that if we simply took the capital we got and redeployed it, we would have a net lost in production because what we are trying to do is continue to feed the beast in terms of drilling locations and we'd like to every year build a ramp up our rig count in those areas. By dropping back in terms of total size to get a great acceleration that's just... that's exactly what we have been doing when we get rid Alaska, and we get rid of Gulf of Mexico. We are going to do it another time, maybe not to that magnitude, maybe, but we are going to give her the low growth so that we can accelerate our growth rate.

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

And the production will be just because of the instantaneous part, I don't envision selling properties to go by acreage, but we do hope we create value by selling just like we've done breaking up with the parts of what we bought previously. Houston EX would qualify for that as well.

Gil Yang - Citigroup

Okay, thank you.

Operator

Your next question comes from the line of Dwayne Robert, FCRC [ph].

Unidentified Analyst

The least success you still have latent expertise in South African market, do you have a group people that's looking specifically at international, that would have that kind bias or is it all melded in with your domestic new ventures as well?

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

Dwayne, the line cut out at the early part of your question, I'm sorry.

Unidentified Analyst

Okay, I'll try and be real flosint [ph]. I'm just curios how you organize your new ventures, in that you got some international success and some international experience outside of Italy. Is your new ventures group focused on international or is it the same group of people that also looks at new ventures domestically?

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

No it is different, international gas, which are very small, are the same guys that we had working and obviously you can tell they are focused on Italy. The new ventures group was carved out of the Company two years ago, so that they didn't have to chase to day-to-days stuff, they actually [indiscernible] part of our western and they were there to look at primarily sales and build acreage position to there and then pass it off to the business units like they've recently done with the Old County but they are a separate group and they both report to J.C.

Unidentified Analyst

Okay, and separately as you guys increase in scale. If you could talk a little a bit about how you think about exploration, is it just very opportunistic or do you have a kind of a target born out of your biases over the years as to how much exploration risk a bigger company can take?

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

I'll let J.C. answer part it, but you know my three bucket rule. That is you don't just do one, you do to explore about a third but you don't want to dominate your results or your projections like the company may have done previous years long time ago, you also work on your base properties and you also exploit your acquisitions. I think I don't know the exact number because it will be in the K broke out, but we typically spend about 25% on explorations. It's just not frontier dominated like it used to be, so you have got the deeper the step-by-step that J.C. referred to, you want to comment.

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

Yeah, and we are opportunistic in the sense that in any given year, we don't necessarily target an absolute dollar volume for exploration. As we go through the budgeting process, we look at what projects the business unit bring forward as well as what they may come up with during the year. So, having that flexibility to revert dollars from business unit to business unit and from project-to-project allows us to accomplish that, Dwayne.

Unidentified Analyst

Yeah that's great. Thank you very much guys.

Operator

Your next question comes from the line of Ray Deacon of BMO Capital Market.

Raymond J. Deacon - BMO Capital Market

Hey, Craig. I had a question about the inventory in the Arkoma and in Canada. It seems like, given the level of activity you've got going in each of those areas the inventory is going to get blown through fairly, fairly quickly. I guess, did you see anything and in '07 that gave you more confidence, especially in Canada I guess, to add rigs, there?

H. Craig Clark - President and Chief Executive Officer

Arkoma is not an issue because it's so new we haven't got into the inventory very big. At 70,000 plus or minus, but with that being a lesser capital spending in proportion to the cash flow for Houston EX and we haven't really got much more into it after we did the big line loop project that occupied the fourth quarter. So, the answer for Arkoma is you are long on inventory because it's so new. On Canada, and you know this well, it evolves. The inventory continues to increase, but your drilling through a wild river.

Now, J.C. has alluded to some horizontal/shallow in Wild River, so you are not going to be done for a couple of years, but it will take... it will not be the dominant part of the program. I would probably say Ansell is moving up the chart pretty quick.

Raymond J. Deacon - BMO Capital Market

Yeah. Got it, well I guess in terms of... so you wouldn't I mean the Arkoma the net on rest [ph] reserve potential you put in your latest presentation on 90Bs. It sounds to me based on the activity like that number could grow.

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

Yeah. We've again we've just scratched the surface. Now these wells go pretty quick they air drilled 7,000-8,000 feet deep that does not include in anyway any shale opportunities here on the western edge of it, that's just drilling the acreage that didn't have a lot capital spin on it prior to taking over.

Raymond J. Deacon - BMO Capital Market

Okay. Got it. And I guess, Dave, I just wanted to make sure understood, so that the PB10 includes about $400 million for Italy, I guess.

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

That's right of the 6 billion, 400 million is Italy.

Raymond J. Deacon - BMO Capital Market

Got it. Okay, great. Do you think that if you look at that... it's my last question... the 2.8 Ts of unrest potential, is the development cost of those reserves much different from the 227 all in numbers that you have got for this year, I guess.

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

I think that... no... and you can see that through the... well, actually you can't because they are not booked yet, but 2.8 should be very consistent because they are on the same fields that our existing prove reserves are in and over four years we have been posting very consistent F&D numbers, both, organic and all-in, so I would not expect those to change.

Raymond J. Deacon - BMO Capital Market

Great. Thanks very much.

Operator

[Operator Instructions] Your next question comes from the line of Jeff Robertson of Lehman Brothers.

Jeffrey W. Robertson - Lehman Brothers

Thanks Dave. Can you talk a little bit about what the assets... what impact the asset sales package may have on your margins? I know you have a... I think you said you haven't put the package together yet, but directionally can you give some sort of a color for what it will do to your corporate LOEs, and things like that?

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

Yes, I think, well, it won't be a surprise to you that we'll probably select out assets that will improve our margins. The goal here is there is a lot of pretty lofty goals for '08, but one of them is to improve our margins through this disposition and improve our growth rate through this disposition program. So, Craig has got initiatives and J.C. have initiatives on the cash spend side and the BD guys will have initiatives on helping the metrics out in terms of LOE and growth on the disposition side. So, I think you can look for LOE to drop for Forest [ph].

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

Jeff, I don't... I am not going to select the properties solely based on that. Which was kind of my driver before geography or focus, I would go and look at more of the growth, because with our cost structure being pretty low as it is, you are not going to move the needle much, but as you know I am never satisfied with LOE.

Jeffrey W. Robertson - Lehman Brothers

And, Craig, I may have missed part of your comments, but can you talk a little bit about the near 400 Bcf of extensions and discoveries in terms of where those, which properties or which areas those were attributed to?

H. Craig Clark - President and Chief Executive Officer

They are pretty evenly distributed everybody more than replace reserves. I'll tell you who had the best year in terms of that order, it would be Eastern, primarily East Texas, by Ark-La-Tex, but East Texas. The second place would be Western with the expansion of the work they did in not only in Buffalo Wallow but in the other areas like the Permian. Third place would be Southern, that has include and taking advantage, of course, [ph] legacy assets, like KD. And fourth place would be Canada, particularly coming in and Ansell.

Jeffrey W. Robertson - Lehman Brothers

Thank you.

Operator

There are no further questions at this time Mr. Redmond, you have any closing remarks.

Patrick J. Redmond - Director Of Investor Relations

Yes, before we conclude I want to mention that we will be holding an Analyst Conference on April 1st in New York City. If you'd like to participate, please contact me. This now 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 call us. Thank you.

Operator

Once again thank you for participating in today's conference call. You may now disconnect.

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Source: Forest Oil Corp. Q4 2007 Earnings Call Transcript
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