Edgar Filing: HOUSTON EXPLORATION CO

Filed by Forest Oil Corporation

Pursuant to Rule 425 of the Securities Act of 1933, as amended,

And deemed filed pursuant to Rule 14a-12 of the Securities Exchange Act of 1934

Subject Company: The Houston Exploration Company

Commission File No.: 001-11899

FOREST OIL CORPORATION

The following is a transcript of a teleconference call made by Forest Oil Corporation:

Teleconference Call

January 8, 2007

7:00 am ET

Operator: Good morning. My name is (Kimberly) and I will be your conference operator today. At this time, I would like to welcome everyone to the teleconference announcing Forest Oil’s acquisition of The Houston Exploration Company. All lines have been placed on mute to prevent any background noise.

After the speakers’ remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad. If you would like to withdraw your question, press star, then the number 2.

Thank you. I will now turn the call over to Patrick Redmond, Director of Investor Relations. Please go ahead, sir.

Moderator-

Patrick Redmond: Good morning. I want to thank you for participating in our conference call announcing Forest Oil’s acquisition of The Houston Exploration Company. We have joining us today Craig Clark, President and CEO, and Dave Keyte, Executive Vice President and CFO.

Before we get started, I’d like to take a moment to advise you about our forward-looking statements within the meaning of Section 27-A of the Securities Act of 1933 and Section 21-E of the Securities Exchange Act of 1934.

All statements other than statements of historical facts that address activities that Forest assumes, plans, expects, believes, projects, estimates, or anticipates, and any other similar expressions will, should, or may occur in the future are forward-looking statements. The forward-looking statements provided in this press release are based on the current belief of Forest Oil management as applicable based on currently available information as to the outcome and timing of future events.

Forest cautions that the respective future natural gas and liquid production, revenues, and expenses, and other forward-looking statements are subject to all of the risks and uncertainties normally incident in the exploration for and development and production and sale of oil and natural gas. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods or services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production and reserves, and other risks as described in Forest’s 2005 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Also, the financial results of Forest’s foreign operations are subject to currency exchange rate risks. Any of these factors could cause actual results and plans of Forest to differ materially from those in the forward-looking statements.

Forest and Houston Exploration will file materials relating to the proposed transaction with the SEC, including one or more registration statements that contain Joint Proxy Statement Prospectus.

Investors and security holders of Forest and Houston Exploration are urged to read the definitive Joint Proxy Statement Prospectus and any other relevant documents filed with the SEC as well as any amendments or supplements to those documents because they will contain important information about Forest, Houston Exploration, and the acquisition. A definitive Joint Proxy Statement Prospectus will be sent to security holders of Forest and Houston Exploration seeking their approval of the acquisition. Investors and security holders may obtain these documents free of charge at the SEC’s Website — www.sec.gov.

In addition, the documents filed with the SEC by Forest may be obtained free of charge from Forest’s Website at www.forestoil.com or by calling Forest’s Investor Relations Department at 303-812-1400. The documents filed with the SEC by Houston Exploration may be obtained free of charge from Houston Exploration’s Website at www.houstonexploration.com or by calling Houston Exploration’s Investor Relations Department at 713-830-6800.

Investors and security holders are urged to read the Joint Proxy Statement Prospectus and other relative materials when they become available before making any voting or investment decisions with respect to the proposed acquisition.

Also, during this call, we will be occasionally referring to our Road Show presentation which further outlines the transaction. The presentation has been posted on our Website — www.forestoil.com — and we invite all investors to go to the Website and review the presentation. Forest will be filing the presentation with the SEC today in accordance with Rule 425 of the Securities Act.

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

David Keyte: Thanks, Pat. I guess you’ve taken about all the allotted time, so that will be about it. Good morning and thank you for tuning in to this pre-market opening call. As you know, Forest Oil announced last night an agreement to acquire 100% of the stock of Houston Exploration and a 50%/50% stock in cash transactions valued at about $1.5 billion. Forest will pay 23.6 million shares valued at about $738 million at Friday’s close and $738 million of cash for 100% of the stock of Houston Exploration.

The transaction is designed to be tax-free to Houston Exploration and Houston Exploration’s shareholders will receive Forest shares tax-free. Houston Exploration shareholders will elect what kind of consideration they want for their stock subject to pro-ration and an equalization mechanism. This will be a mechanic that will be described more fully in the Proxy Statement, but in essence, Forest Oil is committed to put a pot of currency into the transaction which is half stock, half cash, and that shareholders will elect which they choose to take for their own shares and then there will be some balancing mechanism in case one or the other piece of consideration is over-elected.

With the assumption of net debt at year-end 2006 is estimated to be about $100 million, we believe the oil and gas asset valuation and, as is usual, Forest Oil will assume no allocation away from oil and gas properties to (lay) prospects or gatherings. We assume the oil and gas asset valuation to be $1.58 billion.

Forest has received a financing commitment from JP Morgan for a new $1.4 billion dollar credit facility which is anticipated to be used from the cash portion of the transaction and the purchase of any Houston Ex bonds that are

put to us. We intend to term out some of this facility later in the year in the capital markets.

Discussions regarding this transaction began with an inquiry to Forest by JANA Partners in September and we first reviewed the THX company data after a completion of an auction process which was run during the summer; we have not participated in that auction process.

After we became convinced that the process forward would allow us a thorough scrub-down of the business, we worked to put together a transaction that would work for both sides.

We want to thank Barry Rosenstein and his team at JANA who were instrumental to our pursuing and agreeing to this transaction.

Now for some more review on what we’re buying. Houston Exploration produced 204 million a day in the third quarter. Forest estimates that as of September 30, 2006, they had proved reserves of about 655 Bcfe of which 97% is natural gas, 65% is prude developed. The metrics on this transaction indicate a purchase price of about $2.40 per Mcfe and a ground on prude reserves only and about $7,300 per flowing Mcf per day.

We believe these compare favorably to transactions in these resource play areas and Craig will get into later what we will do with these assets.

The assets are located primarily in south Texas and in the Arklatex area, both in east Texas and the Arkoma Basin. There’s also a large but more perspective position in the Uinta Basin and Niobrara Play in the Rockies. In addition to the proved reserve base, there is just approximately 3,200 drilling locations supporting over one Tcfe of net reserve potential in this asset base.

The combined company on a pro forma basis will have about two Tcfe of estimated proved reserves and based on third quarter numbers will be producing about 520 million a day.

They will also have a total of about 6,000 identified drilling locations supporting the proved base and the additional three Tcfe of net reserve potential. All the proved reserves and production are located in North America.

As Craig will detail out later when the transaction closes, we intend to enhance the value of these assets by both reducing and reallocating capital expenditures, cutting cash costs, and significantly increasing the processing of natural gas.

The transaction is anticipated to be accretive. The cash flow per share, production per share, reserves per share, and about neutral on earnings per share. Since 2003, this is our fifth corporate acquisition. While it’s the largest to date, we expect to employ the same tactics we have in the past to transform a good trade into good business. This means shifting the capital emphasis to more low-risk drilling programs, reducing both cash cost and drilling cost, transform the business to a free cash flow generator, and weed-out underperforming properties.

With this transaction, since Craig became CEO in late 2003, we have spent nearly $3 billion to purchase oil and gas assets in our key areas. For the entire purchase package, the average cost for proved reserves is about $2 in Mcfe on proved only and $6,700 per flowing Mcfe per day; those are pretty good metrics.

However, it’s more important with what you do with the assets after you buy them. For the pre-2006 acquisitions, the original $1 billion of investment has already paid-out in the third quarter of 2006. But more impressively, we have reinvested only $400 million in these properties and now have more reserves than when we started; not bad.

We put over 50% of the original capital in our pockets and still have more reserves than when we purchased. I think it’s fair to say we have a very good track record in acquisitions.

In looking at this opportunity, we have a clear vision on how it will perform under our management. If we own this asset today, our business plan for the combined company would have a $900 million capital expenditure budget with a production target in 2007 averaging about $540 million a day. This would generate in our estimation $100 to $200 million of free cash flow which we would continue to use to fortify these core positions or pay down debt.

Since the two companies will operate separately for a few months until closing, we will come out with official guidance when the transaction closes. However, depending on the starting point, you can expect this kind of a model to be employed in the first year of operation. The second year of operation should reflect slightly more growth as the transitional inefficiencies will be behind us at that point. We should then be executing our model which is designed to deliver high single-digit organic growth generation under our free cash flow model.

In addition to the benefits we believe will be achieved by high grading capital expenditures, Forest’s cash cost structure should be reduced by 10% to 15% in the combination. Synergies are expected in (L-leaf) in the processing of

natural gas, G&A from the elimination of corporate level costs, and cash taxes as Houston Exploration’s cash tax costs will be moderated by Forest’s NOL position.

To further reduce debt, we intend to sell our Alaskan entity and other north non-core assets. Our goal is to reduce our long-term debt from the initial estimate of $1.9 billion to $1.3 billion by year-end. But again, a lot of this depends on timing and when we begin to manage the business.

To summarize, we think the trade was very reasonable for us. We feel 240 for proved reserves and 7,700 per flowing Mcfe for assets with this kind of inventory stacked behind it is exceptional. The trick, as with all acquisitions, will be in execution. I think we have faired well there historically and we believe we’ll succeed again.

To make this good trade into excellent business, you must 1) execute drilling programs to move reserve potential into production growth, 2) achieve target cost savings and cash costs, 3) successfully dispose of (electric) quality assets in the portfolio, and finally, we’ve got to have an optimistic view that natural gas prices will improve from here over the next three years.

While gas prices are outside of our control, we like the odds of achieving the other factors. These activities are in our control and are things that we have shown that we can do well and will do well. Therefore, we’re confident that what today may simply appear to be a good trade will transform itself into excellent business in the near-term, just like the rest of our good trades have done.

With that, I’ll turn it over to Craig Clark who will explain more precisely what the assets are and what he plans to do with them. Craig?

Craig Clark: Okay. Thanks, Dave. A good start to 2007. I want to welcome both Forest Oil and the Houston Exploration shareholders who are listening in on the call today.

Since Dave covered the details of the transaction, I will go over our rationale and our plans for the acquisition once closing occurs. For those of you who know Forest, we always have a plan in place for acquired assets or companies when we buy them. Our acquiring exploits success has been well-documented in our periodic look-backs.

Before I get through part of my remarks, let me thank Billy Hargett and his team at Houston Exploration for working with us on this transaction. Billy’s remarks are included in our press release, which indicate that we both positively view this combination.

I’m extremely excited about working with the people in their - with their people in the near future, and I look forward to meeting the Houston Exploration employees this week.

As you’ve heard me say before, our only assets are people in (well head), so the people value is equally important in this deal. Houston Exploration has a recent history of transition similar to Forest with their asset base moving from offshore to on shore. So we’re optimistic about the potential synergies in terms of critical mass and cost.

This is a significant transaction and a major step for Forest Oil. We are firmly entrenched as a North American producer with multiple growth platforms, a huge contrast to where we were three years ago.

I can’t count the growth areas on my fingers. Now I’ve got to use my fingers and toes to count them. You could make the case that divesting our gulf assets a year ago. We essentially traded our Gulf of Mexico in exchange for these assets. But the reserves are double, and I believe they have more growth potential.

We think we’ve taken prompt action over the last three years to add shareholder value. I should note that we chose not to participate in the auction process that Houston Ex conducted earlier this year. Not the first time we’ve done this.

With the support of their major shareholder, (Janna Partners), we were able to reach a negotiated settlement for fair value. We believe the transaction is fairly valued and compares favorably with both corporate and asset deals recently announced. It is especially competitive on a per-flowing per MCFE (unintelligible) basis. It is much less expensive on a proven reserve basis in the last two deals announced in the South Texas (lobo) trend and East Texas North Louisiana areas.

As with most corporate deals, we’ll also get quite a bit of stuff — like land seismic and more importantly, people. Furthermore, buying gas assets when communicate prices are lowers gives us the gas price upside (Dave) mentioned.

The map that we’ll show on our presentation shows a good geographic fit between the two companies’ assets, particularly in South and East Texas. Forest is also in the Uinta basin, but in a smaller way than Houston Ex. The only exception on the map might be that Arkoma our architecture area in DJ Basins. But these are very near other operating areas.

I think that is much more noteworthy on this transaction that we bought assets with similar reservoirs, not just a geography or geology, like tight gas sandstones, with completion techniques that are similar, some of which we’ve shown to be pretty good at. The best analogy for this corporate transaction is probably our Wiser acquisition two years ago.

In fact, this transaction and our plans for these assets are remarkably similar to what we accomplished with our latest public acquisition, Wiser. Our look back to slide for Wiser has been updated and will be included in the presentation.

The Wiser look back shows that we reduce the actual finding cost from $1.85 per MCFE to $1.17 per MCFE through exploitation and exploration activities. We increased production 19% over that time, and we lowered LOE by approximately 40%, and G&A by 70%. Case closed.

The similarities are uncanny between what we thought each asset based with Wiser and Houston Ex would do t the time of acquisition. In both transactions we had large positions we wanted, like Wiser’s Canada and Houston explorations Texas positions. While we’re focused on reducing CAPEX in Wiser’s Gulf of Mexico, we also are focused on that for Uinta with Houston Ex.

We applied our free cash flow model while reducing cost in G&A. We even have similar opportunities for enhanced margins like (NGO) recoveries in both deals.

Now I’ll go into our future plans. Of course, our four-point strategy will be applied. As I go through the major assets I’ll talk about how we’re going to

run them, how CAPEX spending will be shifted once we close, the similarities to the nearest Forest assets, and the upside.

As shown on our 2007 growth areas — I call it the big three slide — we now have the big five — greater Buffalo (unintelligible) over the Texas panhandle from Forest, (Wild River) from Forest, Cotton Valley from both Forest and Houston Ex, Katy from Forest, and South Texas from Houston Ex. That’s the big five.

The up and comers — there are six of them now — Vermejo, Haley from Forest, (Ansel) from Forest, Foothills from Forest, Barnett Shale from Forest, Arkoma from Houston Ex, and (unintelligible) DJ from Houston Ex. These are in no particular order.

The (rock steady) of the low decline properties that give us the lesser decline curve and also add value as well are the (ED Loom Oil) in Canada from Forest, the Permian Oil from Forest, the San Juan from Forest, and the Rockies from Forest and Houston Ex.

In the (flyers) category, to go with Forest’s unconventional (CBM), Shale, and international assets, we’ve added the Uinta Basin, which had a lot of run room, but at current prices and well costs had the least attractive margins of the (unintelligible) basin.

We updated Forest not (unintelligible) project inventory to 2800 projects with a net (unintelligible) potential of 1.9 TCFE, while Houston Ex assets add another 2800 projects approximately with about one TS - TCFE, bringing the total of 5600 projects in just under 3 TCFE.

I’ve excluded the Uinta locations — about 2500 of them. They’ll be on the slide because we placed it in the (flyers) category. To run the assets we’ll keep Houston Ex’s Houston office and set up a new business unit there. Houston office will be called the Southern Business Unit just by name. We’ll handle gulf cost and South Texas and there will be support services in Houston as well.

The eastern business unit will be in Denver and handle all the East Texas (architect) Barnett Shale and the other areas that are not in southern. The Western business unit will remain in Denver and will absorb the Rockies and DJ’s properties in addition to Forest’s large Texas panhandle and Permian basin areas. Again, there is a plan here.

So now I’ll start talking about the Houston Ex - the Houston Exploration assets by areas of importance. First, South Texas — where Houston Ex has the - most of their production and the reserves have been very successful there and it’s shown on our slides. We will combine this operation with our South Texas field, like Kathy, Bonus, (Gera), McAllen ranch.

There’s 116,000 growth acres and over 500 locations identified, 400 of which are not booked and listed on our upside chart. It’s also important to note that Houston Exploration has extensive 3D seismic coverage, also shown on the map over their major fields, as does Forest, over all of Katy, Bonus, and now (Sabine).

Both Houston Ex and Forest have focused on the Wilcox, Vicksburg, (unintelligible) and (Frijo) targets — same objectives — with Houston Exploration focused mostly on Wilcox, Lobo and Vicksburg plays.

There are both shallow and deep exploration and development opportunities. We like the multi-pay areas. Additionally, recent horizontal activity by industry in South Texas has been encouraging, although it has not progressed as much as East Texas has at this point. I’ll talk about that in a minute.

The economics in South Texas are slightly better than East Texas, and similar to our Buffalo Wallow, so we will keep activity for capital the same here. There will be quite a bit of G&G work required as South Texas is still not a blanket sand play, so it is more complex for very small companies — mom and pops. However, some majors continue to be active here. Our early success at Katy will hopefully push down south.

The East Texas areas where we probably have the best bit of all, as can be seen on our map. Our combined acreage is 42,000 net acres located in a pretty hot areas these days. Both companies have approximately 400 locations each for a total of 800. Six hundred of these are in the upside category.

We’ve highlighted where horizontal activity has been done on the map as well. In our presentation we also will show a schematic depicting how horizontal drilling techniques are being applied in the Cotton Valley sands - the lower Cotton Valley. We believe that both Houston Ex and Forest asset basins need to be considered for horizontal completion. We’re doing that on the Forest base first.

Forest will increase CAPEX spending in this area, due in part to the horizontal completion but also due to utilizing the forest low-pressure gas gathering system to increase the margins and (NDL) recoveries. I really like the East Texas areas.

The Arkoma basin, our (Arco) Texas new for Forest and will be combine with East Texas and our Oklahoma properties to form the eastern business unit. Our field office is in Tyler and theirs is in the Arkoma are very close. Additionally, there may be the potential for Fayetteville or Woodford Shale on the Houston Ex Arkoma properties, which fit again nicely with - this is the same group in Forest that’s running our Barnett Shale activity.

Houston Exploration has identified 400 locations on their 57,000 gross acreage base, so this is not considered any Shale activity in the Arkoma. This area has been known to be low risk with down spacing potential and likens to East Texas. So we will keep activity at the same level.

I should note that in South Texas, East Texas, Arco (Tex) Permian areas, we have the ability to move the old Forest land rigs to improve our margins and ease of activity. In the Northeast Colorado area, the (Nibrara) play has been one of the best growth areas for Houston exploration. They have developed an enviable acreage position of over 400,000 gross acres along with proprietary 3D seismic.

Their recent acquisition from (Santos) added about 140,000 gross areas in the area. There are approximately 1900 potential locations in this shallow play, which have low F&D cost. As a result, we will increase capital spending here while reducing the other Rocky spending, particularly the Uinta.

A single shallow post low rig can drill over 100 wells per year here. The Uinta basin acreage is large, at over 20,000 gross acres, and near the active natural buttes area as shown on our slide. Forest has two properties in the same basin. One’s an oil field and the other’s a gas field.

We believe with lower gas prices and associated basis differential these days along with higher service costs, this would be our thinnest margin area. So we will reduce or shift activity away from this area when we take over, until techniques improve our well costs can be reduced.

There are however, as Houston Ex has identified, 2500 potential locations here. So we’ve got the option value for the future for our shareholders as exhibited by us putting it in the flyer category.

So this concludes my comment on the plan for these assets. I should note that our spending plan and associated guidance for Houston Ex’s assets are on an annualized basis, so our four point strategy would be implemented at closing.

With five solid growth platforms and six more currently in the wings in the up and comer categories, the future for the combined company is bright. When you compile a plan that I just outlined, it should result in reduction in CAPEX for both companies of approximately just under $200 million while still maintaining organic growth. Forest Oil has recently demonstrated that we are at our best when the acquire and exploit methods need to be employed.

I would personally like to thank the employees of both companies who worked around the clock and over the holidays to pull off this transaction. I’m very anxious to work with the Houston Exploration employees. Thanks for listening today and for your interest and ownership in Forest Oil. Operator we’re now ready to take any questions we have.

Operator: At this time I would like to remind everyone, if you would like to ask a question, please press star then the number one on your telephone keypad. We’ll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Ryan Singer.

Ryan Singer: Good morning.

Man: Hi, Brian (sic).

Man: Hi Brian (sic).

Ryan Singer: In the Houston Exploration management’s presentation last July, much higher natural gas prices seem to be needed to make their East Texas and Rockies properties work as it relates to kind of an adequate return. In general, what do you see differently as it relates to both East Texas especially and then also the (Nibrara) area that gives you more confidence in terms of lowering (S&B) cost and improving returns?

David Keyte: On the Rockies, we would agree, although not in the (shallow) Rockies. On East Texas, just like we did with our recent East Texas acquisition, our plans would be to reduce the well cost. Would also be (NGO) gathering margin enhancement, which we’ve noted that has been done in East Texas already, even though we haven’t owned it a year. And horizontal drilling would be the wild card.

Ryan Singer: Can you talk a little bit more on the well cost front? What can you do that maybe the Houston Exploration is now currently doing that gives you confidence you can reduce well cost?

David Keyte: Planner and drilling. We own the rigs.

Ryan Singer: Great. In terms of your lower capital and gross plan, what natural gas price are you assuming and what are you plans for any incremental hedging?

David Keyte: In our plan for this asset we’re assuming, about $6.50 for the remainder of ‘07 and our plan for hedging at this point is to not hedge the Houston Ex production until the transaction is closed. They have not chosen to hedge their position at this point and you can look for us to probably hedge the combined portfolio consistent with the way we’ve done Forest Oil in the past which is a 30 to 40% hedge position in both products when we get our hands on it.

Ryan Singer: Lastly you mentioned about $600 million I believe in expected asset sales. Can you kind of break that down into where you see that coming from and how much would be - how much are you guiding for from Alaska and then is any of that coming from THX asset?

David Keyte: Well Alaska will be the major part of that and it has $375 million of debt on it so there will be an equity component there as well. And then additional assets out of Forest Oil and TXH depending on how we view the growth profile of the asset bases.

Ryan Singer: Right thank you.

Operator: Your next question comes from the line of Andrew O’Conor.

Andrew O’Conor: Good morning Craig. Good morning (Dave).

David Keyte: Hey Andrew.

Andrew O’Conor: Good luck with your proposed transaction here. I wanted to know can you estimate the F&D costs for the combined company in ‘07? Craig I think you were suggesting on the last conference call that for ‘06 you were looking for Forest to be at about the $2.16 F&D cost again for ‘06 and I see on Slide 5 you indicate due to exploration at $2.41. I’m just wondering can you hazard a

guess about F&D costs for ‘07 and beyond for the combined company? Thanks so much.

Craig Clark: I do not know what they will average for ‘06 that’ll lead them into ‘07. Our all in was we expect it to be flat. I think the $2.40 you’re referring to is the acquisition cost which will dominate the F&D this year. We had hoped that our organic this year would actually be below the acquisition cost and it looks like we’re going to be close to that at Forest. I do not know what theirs is because they haven’t reported yet.

Andrew O’Conor: Okay so you’re not able to hazard a guess about a combined F&D cost for ‘07?

Craig Clark: That something we’re working on at close. That’s going to depend on what we close because it’ll be their spending pattern until close and then it’ll be ours thereafter.

Andrew O’Conor: Got it. Okay thanks very much.

Operator: Your next question comes from the line of Tom Gardner.

Tom Gardner: Good morning Craig, (Dave).

Craig Clark: Hey Tom.

Tom Gardner: Hey I wanted to ask what is the total CAPEX requirement you’re modeling for about the 6000 drilling locations you’ve outlined in your release?

Craig Clark: Oh I don’t know that number.

Tom Gardner: Oh.

Craig Clark: We’d have to research it on a risk basis.

Tom Gardner: Okay.

Craig Clark: It goes way out there obviously with that many locations.

Tom Gardner: Okay. Concerning the Uinta specifically the south natural beach area, have the economics recently improved? I mean, what is your view of the current development economics there?

Craig Clark: Well the - I guess to get on my soap box a little bit as a follow up to the East Texas question, the service costs need to come down and I guess I should apply that to East Texas as well. That would I guess my first wish for 2007.

In terms of the gas price the bases have not - are still high, but they’re not blowing out like they were earlier in the year. So that’s helped a little bit. And then there’s been some recent activity with technique improvement on the lower end wells in terms of tracks. I think it’s too early to tell at this point. The biggest thing that needs to happen in my mind is if you say you can’t do anything about gas prices, get after your well costs.

But there hasn’t been significant improvement of light in terms of the wells except people are using different (unintelligible) technology sort of like you saw us do in Canada on the last quarter.

Tom Gardner: Got you. And one last question concerning the 2007 production from the Houston Ex properties. You still modeling about that $230 million a day or something different?

Craig Clark: No we’re modeling lower than that. And again that’s - if we were to own the asset, we would moderate significantly the attempted growth profile on this set of assets and cut back capital and reallocate and start gearing it up for ‘08. So we have modeled lower than $230 million a day for their set. That’s primarily because of this capital reallocation.

Tom Gardner: Right.

Craig Clark: Not our opinion of their forecast or anything like that.

Tom Gardner: Got you. Thank you so much gentlemen and good luck on the deal.

Craig Clark: Thank you.

Operator: Your next question comes from the line of Jack Moore:

Jack Moore: Good morning. I was wondering if you could just talk a little bit more about CAPEX going forward. I know you’ve cutting spending by $200 million with increased activity in some areas.

Craig Clark: (Unintelligible).

Jack Moore: Can you also talk more about the just expected cost savings and personnel numbers going forward.

David Keyte: On the CAPEX I think that, you know, in looking at the combined CAPEX for ‘06 it’s almost $1.1 billion. We think that we can allocate capital to the combined asset base. I only spent $900 million on that asset base and still deliver a high single digit type rate of return, or growth profile organically.

Now most of the capital coming out is coming out of exploration in the Rockies. We will probably add capital in terms of (Houston X’s) asset base. We would add capital to East Texas. So I think that, you know, just the re-jiggering of the capital and the cutting out of the higher risk end of the capital expenditures now going on will result in that savings.

In terms of other cost savings, we think certainly now that the normal corporate level costs that you get in the combination with a public will come out. Personnel requirements we haven’t yet defined. LOE we think we’ll get good cost savings by processing their natural gas for liquids and in terms of capital costs, of course employing our own rigs rather than renting rigs is always a good business.

Jack Moore: Right. Thanks very much.

David Keyte: You bet.

Operator: Your next question comes from the line of David Tameron.

David Tameron: Good morning. Congratulations on getting the deal done. A couple quick questions. First, Craig I mean the obvious question from a Street perspective is this thing was out there forever, you know, shopped either informally or unofficially and, you know, now you come in and buy it. And granted obviously it’s a great price, but what - I guess getting back to (Brian’s) question, what do you see, you know, at today’s - what do you see today that maybe you didn’t see three months ago when you took a look at it in the data room?

Craig Clark: Well it remind you of two things. One is (unintelligible) and actually even wiser. But not - we didn’t see anymore or less than we had other than commodity prices change. We certainly spent some time getting our arms around the areas we were interested in and specifically the Texas areas. So nothing really changed from the look except we had a good long look at it and we didn’t participate in - we had about three months of off and on.

But in terms of knowing a lot about the asset to increase our confidence, we, you know, did participate in I think it was an announced auction process so it was a negotiated settlement. But the big advantage of that of course is that these prices on the corporate side were a lot less than what you see asset deals go for in the same, in fact in this case of South Texas, the exact same area. So it kind of moved our way.

David Tameron: Okay. And you guys, is anything of this based on strip pricing that’s come down or (Dave) kind of said you’re not going to hedge near term until close. I mean, how’s what’s happened with the commodity strips influenced the price of the transaction?

David Keyte: Well it just influences through the application or through the stock prices. I think that, you know, when we buy, we don’t necessarily take a strip price look. We take our own look at what we think is a proper price risk for closing. And right now we have not yet violated that number. So we’re happy not to be hedged at this point.

Now if prices dive another dollar on the nearby strip, it will start to temporarily break through our assumed economics. But I think we do have a view that gas over the next three years is going to improve from here. So and you and have to have that view or you wouldn’t be buying 100% gas asset.

We like that. But I think at this point it’s working well within the plan and we’re comfortable not being hedged on it until close.

David Tameron: Okay good. And then (Nibrara). What kind of growth - I mean how fast can you accelerate that? What - I know F&D costs are probably around a buck or so but is that kind of - what do you see from that area going forward?

Craig Clark: One rig will drill 100 plus wells a year. They’re real shallow, a couple thousand feet. As I called it a post hole rig. The F&D is about what you quoted. The wells cost about $300,000 or $400,000 a piece. I got two auctions there. One is to rig up another post hole rig. And remember we’ve got a couple of singles with lantern that we could employ as well.

If you take a second rig in there you drill 200 wells instead of 100 wells. I don’t know the actual growth, but it’s probably been the growthiest asset that they’ve got. However a lot of that acreage is undeveloped so you’ll be, you know, stepping out each at a time.

So, you know, you’re not spending much money went there because they’re very shallow and cheap. So you double the activity. It’s almost around the area in your CAPEX although you do get some growth out of it. I think the current production of it it’s about $6, $7 million a day right now and you double it pretty simply.

David Tameron: Okay. And then one final question and I’ll jump off. You guys threw out a number in the financials in the appendix of the presentation, $540 million a day for ‘07, just kind of on a pro forma basis. Does that - off the $313 you had in ‘06 how does that compare? Is that $313 plus $205 less Alaska? Or what actually is in that $540 number?

David Keyte: No there is not less Alaska. That’s basically our guidance. I guess we haven’t given guidance for ‘07 but our expectation for ‘07 adding in basically a flat Houston Ex type production. I think that what we’re anticipating if we own the asset for ‘07 would be a year of transition to get this capital reallocated and the operation under our belt.

So I think what that $540 reflects is Forest Oil plus Houston Ex flat first day and they’re up a little bit from $204.

David Tameron: Okay and then you just said 7, 8% going forward on them. Is that …

David Keyte: Yeah I think we can re-establish the growth rate in ‘08.

David Tameron: Okay, thank you.

David Keyte: Yup.

Operator: Your next question comes from the line of Gil Yang.

Gil Yang: Hi can you just comment on how much value are you creating by accelerating the NOL?

David Keyte: Gil I really can’t. Again a lot of this depends on when we take over and what position they are in tax-wise when we take them over. My guess is well we should be able to accelerate $50 to $100 million.

Gil Yang: Okay so of nominal value you mean?

David Keyte: Correct.

Gil Yang: Okay and so your (unintelligible) wells will expire or will be used up when?

David Keyte: You know, I don’t have - on our forecast we’re still okay based on our level of CAPEX and interest cost. So I still think we’re okay in the next two to three years.

Gil Yang: In two years is how you feel the draw in ALL is that what you mean?

David Keyte: Correct.

Gil Yang: Okay.

David Keyte: I don’t anticipate cash taxes for over two years.

Gil Yang: Okay. You know, (unintelligible) coming as a relatively short RP ratio. Do you anticipate that you’ll be able to change that in any way or is that a goal to change that?

Craig Clark: Well, you know, you’d like it to be a little bit longer but in the combined unit, the year’s still double digits so I’m okay with that, therefore the balance in the portfolio. You know, you’ve got some short and some long and they still had a little bit of offshore in there at some point.

But yeah I’d like to change that but not just reserve-wise, I mean in terms of the type of wells we drill. For example, you get a longer RP asset when you go up in the (Nibrara) or when you go in some of the other areas.

However, the shortest RP seems to be either the Rockies or South Texas because the South Texas has been their juggernaut producer, and I think it

makes about 50 to 60% of their production, and it’s that decline curve with not a lot of activity that does that RP.

Yes, we would lengthen it, but mainly through drilling the wells more rock steadies and more up and comers. The lowest decline properties they have are obviously in the (Nibrara).

Gil Yang: Okay. And it sounds like the company’s had sort of negative production growth for a couple of years or so. Can you talk about how your program changes that to be more flattish as you sort of suggested?

Craig Clark: Well, I hope we grow it as well. In terms of negative, I’m not familiar with the negative except (unintelligible) they’ve grown it slightly. But you know my rule of thumb, you know, if you’re going to spend a hundred percent of the cash flow from the properties, you need to grow it, which is what Forest has done consistently.

So, there will be a free cash flow model implemented. Of the total asset base it’s about $170 to $200,000,000.

But, you know, if you’re not going to grow it more than 1, 2, 3%, you need to free cash flow and give somebody else the baton like some of our big three assets. I expect the growth.

Gil Yang: Sorry.

Craig Clark: I expect the growth, let’s be very clear, to come from our big three, (Katy) which pops up in there in ‘07 and some of their South Texas, that is the big five for growth.

But it — we’ll spend less on the ones that have been declining, or not contributing to that proportional growth.

Gil Yang: Okay.

Craig Clark: They have been overspending cash flow, I believe year to date.

Gil Yang: Okay. All right, thanks.

Operator: Your next question comes from the line of Adam Schwartz.

(Bob Godismen): Hi, this is (Bob Godismen). I just wanted to ask you a question about the economic under flat gas prices.

If gas prices were to stay at current prices or possibly even be softer, what do the economics of this transaction look like over time?

David Keyte: At the prices that we are at today, the economics or at least our hurdle rate, as I said, I think we assumed lower prices than we’re seeing today. Obviously, when we started this process, we had a lot of cushion. Now our cushion has been eroded to probably 50 cents on a three year strip.

But I think that certainly the economics on this transaction are at least as good as the prior four corporate transactions that we have invested in at these price tags.

And you got to know that after three years, we drop the prices on our economics even further than when we started.

Craig Clark: On (Wiser), we assumed flat production and then the cost actually drove it early on, mainly the LOE. And don’t under estimate that, particularly in lieu of the — if prices come down, I expect some service cost reductions or well cost reductions.

And then of course we increased production primarily due to Canada. But in this case, cost would be an early driver if prices went down. Those are the things we control, production and cost.

(Bob Godismen): Right. And could you just again refresh my memory? The four transactions, what were the economics so that I can kind of…

David Keyte: You know, those really are more proprietary. We don’t want to discuss those in a broad audience.

(Bob Godismen): Okay. Well, why don’t you call me a little later?

David Keyte: We’d be happy to do that. We have it on the look back slide in terms of the metrics, (Bob). We can definitely call you later, (Bob).

(Bob Godismen): Thank you very much.

David Keyte: You bet.

Operator: Your next question comes from the line of David Anderson.

David Anderson: Hey guys, I don’t mean to harp on that 540 number. But what kind of production was assumed for divestitures in there? Or was there any?

David Keyte: Nothing, nothing. No divestitures.

David Anderson: Well, if that’s the case, then doesn’t look like, if I pull out the flat production numbers out for Hou Ex, doesn’t that mean that Forest (unintelligible) is flat as well?

David Keyte: No, (unintelligible).

David Anderson: And if that’s the case, where are you pulling back?

David Keyte: No, Forest isn’t flat. Forest produced – we’re a combined company with 517 for the third quarter.

David Anderson: Okay. I guess I have to take another look at that. And then secondarily, what are you guys attributing to in terms of purchase price here for that (Nibrara) and Uinta?

I mean, judging from the way you went in terms of flyers, it was suggested you’re not getting much credit at all for that. And then what about the – and then with the (Nibrara), combined those two properties are largely improved and they really weren’t producing much at all.

So, I mean, how much of the purchase price would attribute to that?

Craig Clark: I don’t have the allocation and don’t want to break it out for competitive reasons. But in terms of their production, I believe their whole Rockies position was nine in the third quarter, which is about 8% of their company’s production.

And the (Nibrara) was a little more – I think about half that and increasing. But the key on that is, is that, you know, it’s been basically a hockey (unintelligible) production, from zero to five million a day pretty quick.

And then in addition to that, the undeveloped acres because there’s over 400,000 acres. And I believe on their recent acquisition from (Santos), that’s mostly undeveloped as well.

There’s not a lot allocated to it simply because they didn’t have – you know, it’s not their biggest area. In fact, I think in terms of their four key areas, it’s the smallest behind Arkoma, East Texas and certainly South Texas.

David Anderson: Okay.

Craig Clark: But the acreage is disproportional. So obviously, you know, it obviously has a little bit more attractiveness in terms of locations. The 1900 locations is more than half the locations we quoted for that.

David Anderson: Okay. And you also mentioned that you’re going to pull back on the Hou Ex properties until it basically turns its overall transition until it can really come to New York.

Your scope – but about six months ago, Hou Ex came out with a rather bold target of 19% production growth. They were actually back to 13% about six months later.

If you were going to pull back, where do you think their production growth was? Or what – would it have been processed?

David Keyte: That’s their business. That’s not how we would run their asset base. But they will have control of this asset base until we take over, so that’s really a question for them.

Craig Clark: We will – our opinion would be the CAPEX should be shifted away from Uinta. And I think that’s the difference in the growth profile that we have versus them.

David Anderson: Okay. All right, great, thanks.

Operator: Your next question comes from the line of David Heikkimen.

David Heikkimen: Good morning. Just had a question for you about the 655 BCF Forest reserve Forest estimate. Would there be a reason why you’d expect the THX Reserve Report to be dramatically different from that at year end?

Craig Clark: Those are our estimates at Forest, not theirs at 930. They have to do their fourth quarter activity, which they’re in the process of doing now as well as reflect the commodity prices when they run their reserves.

That’s our estimate at 930 before the fourth quarter, and whatever the commodity prices that they run their cases at.

David Heikkimen: Okay. So you wouldn’t expect a difference between year end and your 930, or you’re just saying…

Craig Clark: I hope not. But I would actually expect – you know, but there should be some minor differences because...

David Heikkimen: But no major change.

Craig Clark: (Unintelligible) producing activity. But that’s not their number, that’s our estimate...

David Heikkimen: Right.

Craig Clark: ...of their company. They may differ with us, but they’ll report fourth quarter and we’ll go from there.

We bring it across at our estimates when we close because of purchase accounting.

David Heikkimen: Okay. And then looking at their drill that F&D cost using your estimate, we get close to $5 in MCS. Bringing down $100 or $200 million of capital in Uinta, would you approach the Forest ongoing F&D cost of 2 to 250 (NM)?

Craig Clark: Gosh, I hope so.

David Heikkimen: Okay. And...

Craig Clark: (Unintelligible) do it. That’s the highest F&D in the portfolio. So it’s (unintelligible) to figure out — and it’s not just the wells, it’s the cost. The wells are more expensive because it is the Rockies.

That’s why you do it. It’s the lower return, higher F&D area, what we perceive in the combined portfolio.

David Heikkimen: Yes, so really that capital they were allocating that was growing production, you don’t see it as creating that much incremental asset value, is what I’m reading between the lines?

Craig Clark: Unless you can work on the techniques and the prices. The (unintelligible) cost are high because of the industry in the Rockies.

Then it would still be in the flyer category for us until wells or economics improve.

David Heikkimen: And you guys see a lot of value being added in East Texas and South Texas just given how you’re talking about allocating capital. Is that a fair...

Craig Clark: Yes, they’re South Texas because they’ve been a juggernaut producer down there and East Texas because of what we’ve been able to do with our assets over the last eight months.

David Heikkimen: In South Texas, just one final question, they’re got about two, maybe two and a half years of drilling inventory at their pace. Maintaining flat production after that, do you think you’ll continue to make acquisitions there?

Or given that inventory that they have left and what they have been drilling at, one of our concerns was, could they continue? How will you guys mitigate that relatively small inventory?

Craig Clark: We’re not going to stop working, that’s for sure. I’ll just say about the South Texas area. First off, as a general comment, it is still somewhat geologically complex as exhibited by the 3D.

That kind of keeps the mom and pops from doing a lot of activity. But the majors don’t do much consolidation. So the answer on consolidation is yes, it’s a candidate.

David Heikkimen: Okay.

Craig Clark: Also, in terms of the activity, there are fields that you like better than others that are growthier, that’s where we’ll spend capital within South Texas.

In addition to that, the horizontal, which has been applied already, but not as frequent as East Texas, obviously makes it more growth than you would expect. But I don’t expect it to run out of activity as you continue to work through it.

It’s their largest area going away. And they’ve obviously grown that over the years as well. Coupled with activity that we’ve had in the area, there still is undeveloped acreage out there.

The caution on the technology early on is you’re into a rapid fire development program because there is faulting in geologic complexity. So you’re not going to burn through that inventory as fast as you would in a down spacing area.

So I don’t think you’re going to be done in two years.

David Heikkimen: Okay. So it’s longer than two years. Fair enough, that’s useful. Thanks guys.

Operator: Your next question comes from the line of Ray Deacon.

Ray Deacon: Yes, hey Craig. Sorry, (Dave) just asked my question. I’m all set.

Craig Clark: Thanks Ray.

Operator: And your next question is a follow up from David Tameron.

David Tameron: Craig, a couple more questions. South Texas, can you talk a little more about the horizontal, you kind of alluded to it but didn’t give us a lot of detail. Can you hit on that real quick?

Craig Clark: Yes, there’s been – that’s basically what’s been doing in East Texas is selecting a zone. It’s been in the Wilcox in order to enhance the production of the wells.

And actually place the frac in the desired area laterally away from the well using a horizontal technique and cracking it in stages like you’re doing in East Texas.

It’s been applied in the Wilcox, I’m told some other zones have had it as well. And the early results have been good.

But it’s much more in its infancy, however, the well dips are not much different than East Texas, so, I mean, that (unintelligible) more technologically challenging as it is.

You would look for a more blanket type saying, whether it’s Vicksburg or Wilcox, you do have faulting and cutups down there. It’s not going to be as simple as East Texas.

But because you have higher pressures down there, you may get some higher rates. But we haven’t even scratched the surface of that as an industry.

There’s been one operator talking about that and calling it still. And it’s down in this area. I mean, one thing about Houston Ex, they’ve got South Texas covered up pretty well. So if it happens or how it happens, it’s going to be pretty close to where we have properties in the combined entity.

David Tameron: Okay. Thanks. And then, I guess for (Dave) or for yourself. On a total cash cost, it looks like the numbers coming off pretty hard for ‘07. Or I guess on a combined basis if you’re showing the presentation, off 15%.

Again, does that include – is that just the combined companies pro forma today?

Craig Clark: That is the combined companies, it includes no disposition.

David Tameron: Okay. So when you’re showing a cash cost of $270 for Forest, the third quarter, combined company 234 in the – I mean, that doesn’t assume Alaska, it doesn’t assume any cost savings going forward?

Craig Clark: No, just add them together.

David Tameron: All right, so that number is high, I guess is what I’m getting at.

David Keyte: (Unintelligible) I mean, if you sell Alaska, you’re going to drop another probably 20 cents.

David Tameron: Okay. All right, thanks.

David Keyte: Yes.

Operator: At this time, there are no further questions. I will now turn the call back over to Patrick Redmond.

Patrick Redmond: Thank you. This concludes our conference call. I want to thank everyone for their interest and participation in our call. And as always, if you have any further questions, please feel free to contact us. Thank you.

Operator: Ladies and gentlemen, this concludes today’s conference. You may now disconnect.

END