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.: 333-140532

FOREST OIL CORPORATION

Moderator: Patrick Redmond

05-08-07/11:00 am CT

Confirmation #6423879

FOREST OIL CORPORATION

Moderator: Patrick Redmond

May 8, 2007

11:00 am CT

Operator: Good morning. My name is (Dennis) and I will be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Corporation First Quarter 2007 Earnings 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. 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 on your telephone keypad.

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

Patrick Redmond: Good morning. I want to thank you for participating in our First Quarter 2007 Earnings Conference Call. 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 27A of the

Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

All statements other than statements of historical fact that address activities that Forest assumes, plans, expects, believes, projects, estimates or anticipates and 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 Management of Forest as applicable based on current available information as to the outcome and timing of future events.

Forest cautions that their respect to future natural gas and liquids production revenues and expenses and other forward looking statements are subject to all the risks and uncertainties normally incident in the exploration for and development and production and sale of natural gas.

These risks include but are not limited to, price volatility, inflation or lack of available goods and 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 reports that Forest files with the Securities Exchange Commission including its 2006 annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K.

Also the financial results of Forest foreign operations are subject to currency exchange rate risks. Any of these factors could cause Forest’s actual results and plans to differ materially from those in the forward looking statements.

Forest and Houston Exploration filed materials relating to the proposed merger with the SEC including a registration statement that contains a joint proxy statement prospectus that was mailed to shareholders on or about May 4, 2007.

Investors are urged to read the joint proxy statement prospectus as it contains important information including detailed risk factors. The registration statement and other documents filed by Forest and Houston Exploration may be received from the SEC free of charge at the SEC’s web site at www.sec.gov.

In addition, the documents filed with the SEC by Forest may be obtained free of charge from Forest’s web site at www.forestoil.com or 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 web site at www.houstonexploration.com or 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 relevant materials before making any voting or investment decisions with respect to the proposed acquisition.

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

Dave Keyte: Thanks Pat and thanks to all for tuning in to what will likely be our last teleconference before our planned merger with THX. We’re looking forward to closing that transaction if approved by the shareholders on June 6, 2007, so

we’re less than a month away and are encouraged thus far this year by both ours and their results.

We hope to release revised guidance on the combined company by the end of the second quarter. Until then however, we have our own business to run and the first quarter showed the same kind of predictable results that we have had in the past.

The broad brush on the quarter is that improved differentials and an improved hedge portfolio helped offset volume decreases which were due to weather. Costs remained in line and overall, it was a very down the middle quarter for us as we’ve become accustomed to.

Overall, adjusted earnings were 62 cents per primary share, an increase of 59% from last year due to 6% higher production volumes, increased realizations due to tighter price differentials and realized hedging gains.

EBITDA was $156 million, up 34% from last year for the same reasons and discounted - I’m sorry, discretionary cash flow was up 19% to $123 million as our top line increased revenues and hedge gains were offset by increased interest expense primarily due to the term loans that we put in place in the fourth quarter in Alaska.

Sales volumes were negatively impacted by severe weather and refinery of plant outages in our land based operations, particularly in the Texas Panhandle. The impact from the lower 48 weather is estimated at about $11 million a day for the period.

I think in our first quarter guidance we had estimated it could be as high as $13 million a day, but the actuals came in at about $11 million a day for the period.

At this point however, that production has been fully restored. In addition, there was a shortfall during the first quarter of about $8 million a day resulting from a tanker lifting in the Cook Inlet which was delayed over quarter end. Those volumes will be counted in the second quarter, so if you’re looking at second quarter correction volumes, you should anticipate $8 million a day more than what you would have anticipated for that quarter.

The volumes associated with the delayed liftings will be booked in the second quarter.

Big three assets continue to set production records. We finally went over $100 million a day in combination of those three assets, $41 million a day in Buffalo Wallow, $22 million a day in East Texas, and $39 million a day in Wild River.

During the quarter, the combined rate of $102 million a day compares with the combined rate a year ago of $79 million a day or an increase of almost 30% year over year on just the big three assets.

On the revenue side despite a year over year drop of $2.24 per MMbtu at NYMEX, realizations only decreased by 4 cents a unit. Our base differentials narrowed significantly year over year. Last year gas basis differentials were about $2.50 and this year they’re about 80 cents.

The severe demand call on gas in the physical markets tighten that differential substantially when compared to the financial markets. For instance, (ACO)

differentials shrunk to as little as 40 cents per MMbtu in March from a more normal $1 to $1.40 reflecting the high demand due to cold weather in February and March.

In addition to narrow gas differentials, oil differentials also narrowed. In this case however, we view that the benchmark at Cushing to be the issue rather than the physical market demand. The oil’s refinery outage at McKee plant in the Panhandle pushed significant oil supplies to Cushing which decreased the benchmark WTI artificially during the quarter.

Overall despite a significant decrease in NYMEX prices compared to ‘06, our realized prices only decreased slightly which helped our top line results.

Lease operating expenses were also very solid coming in a $1.76 per MCFV all in. That includes transportation ad valorem and production taxes were down 5% sequentially despite a very high $5.34 per MCFV in Alaska due to maintenance repairs at McArthur River.

Alaska lease operating expenses improved throughout the quarter, but overall, were very high in Chevron’s Field. The potential sale of our Alaska properties and the acquisition of Houston Exploration should result in a dramatic reduction of our LOE per unit.

GA expense was negatively impacted by $1 million charge relating to 2006 bonuses paid in 2007 which was in excess of accrued amounts but otherwise was expected.

Interest expense gapped upward due to high cost non-recourse notes put in place in Alaska in December. These notes will be paid off or assumed when the sale of these assets is completed.

So we believe costs were basically in line for the quarter. We’re excited to see the cost structure on a go forward basis which should make us one of the lower cost producers in the E&P space in North America.

We believe that synergies on all costs will enable Forest to be hopefully the top best (unintelligible) in the industry. Realized hedging gains supported our results for the quarter as well. Much improved floor pricing year over year as 2004 acquisition hedges ran out in 2006 improved results markedly.

We have begun to opportunistically layer in 2008 hedges to protect the THX acquisition and significantly better economics than originally valued. I think as you recall on our January 8 call, when we talked about the THX portfolio being brought in, it was unhedged.

At that time we felt that the upside was there for both 2007 and 2008 gas. I think we remain at 2008 gas bowl. Prices have improved substantially since January 8 and because of that, we began to put in hedges both in our portfolio and I believe THX put in as many as $80 million a day of hedges in their own portfolio for ‘07 locking in great economics for us.

Finally, there was a gain on the sale of overrides in Australia that we monetized. We received $7.2 million for this asset. There was no book basis in the asset. This sale really kicks off our divesture program for 2007. Although it’s a relatively small amount of money for what our goal proceeds are, it’s a good start for us.

We hope to achieve sales proceeds this year of $600 to $700 million in asset sales. We announced Alaska sale process which will cover the bulk of this

amount of money is in the final stages as bids were received on April 26. We hope to have a transaction announced sometime in the next four weeks.

During the quarter, we spent $155 million in Capital Expenditures. This is higher than a quarter of what our guided capital is. It reflects a seasonally high Canadian capital spend due to break up in the second quarter which will impair that amount of spend rate.

Results have been in line with those experienced in 2006 and we’re on budget for 2007.

In the quarter, we also invested $18 million in working capital as significant year end drilling costs, taxes and loan accruals were paid in the quarter, primarily as a result of our investment working capital net debt rose to about $1.2 billion.

First quarter results and investment results were in line with our expectation for our production rates, put us in a position to meet our Forest standalone targets and the pending merger with THX is also on track and all indications are that their performance is expected as well. I believe tomorrow is when they’re going to release their results.

On the THX merger, I want to spend a minute or two on that. When we discussed this in January, we believed that we would run the combined asset base on a $900 million CAPEX budget and be able to produce about $540 million a day in 2007 on a pro forma business plan.

Just to remind you, that was $335 million a day, roughly for Forest Oil and $205 million a day for THX. I just wanted to keep those numbers up front for

you so as we get towards guidance, you’ll know where we stand versus our initial expectations.

There’s been nothing that we have seen so far this year to change this view. We also believe that of this new higher production base we could deliver mid to high single digit growth well within cash flow for 2008. Again, nothing we have seen so far has changed that view as well.

Therefore operationally, we believe our acquisition model to be on track. On the synergy side, we identified CAPEX reductions to $900 million and G&A savings as our primary synergy drivers. Both of these should be attainable based on what we’ve seen to date.

Therefore, there have been no surprises in this transaction to date. While you always hope that to be the case, it’s gratifying to see that it’s progressing on plan.

The latest developments on the transactions are that the proxy went effective on May 1, for record holders on April 30 and there will be a shareholders meeting on June 5 with the transaction closing on June 6 assuming approval.

THX has begun a tender offer for their public notes which will close on June 6 and Forest has syndicated a new credit facility which will also close on June 6 to provide cash funding for the transactions.

So all the little pieces that need to come together for a clean execution on this transaction are in motion. We believe we’re on track to close this as we had planned.

As a reminder, our goal was to reduce long-term debt by $600 million from the close of the transaction to year end. We also believe that to be achievable and so everything is clicking down the track.

With that, I will turn the call over to Craig who’ll give you much more information than I’ve been able to so far.

Craig Clark: Okay thanks Dave. We’ve got a lot going on right now with properties both coming and going, data rooms, tender offers and the THX property reviews while running our base business at Forest at the same time.

When you look at our stable numbers with all this taking place, it should tell you all something about the talent and bench strength within the company. In fact, we’ve recently promoted several talented individuals that exemplify this bench strength.

Mark Bush has taken over as Vice President of Eastern after J.C. Ridens, who’s with us today, moved over to our Western Business Unit. And Glen Mizenko was recently the Vice President of Business Development and Engineering and was named - or previously was over at Business Development was named Senior Vice President of Business Development and Engineering.

Much of our first quarter activity and changes were related to our announced acquisition of Houston Exploration. We performed all our due diligence and property reviews and are ready to close and certainly welcome Houston Exploration employees to Forest Oil.

We will essentially take over operations immediately following closing on June 6. We have finished our data room for our Alaska entity as well and are evaluating the multiple bids received.

Overall, everything is going according to the schedule we set forth when we announced the Houston Exploration acquisition and our associated plan for 2007 in early January.

The Houston Exploration transaction and the associated divestitures will upgrade the company’s assets and future performance. We consider the Houston Exploration transaction to be fairly priced, not just in terms of acquisition comparables, although we’ve seen some high priced acquisitions lately, but also much cheaper than last year’s industry cost defined and developed reserves in the United States.

We will have an enviable project inventory, approximately 5600 projects at year end ‘06, all of which are not booked and for the benefit of our shareholder (unintelligible) to drill and book.

At the end of the year, our acreage position for the combined company is around 6.5 million net acres. That’s 91% undeveloped at this time.

In the past, I’ve heard some people say Forest didn’t have a big position on one single asset. Our strategy is simple. We want to have a portfolio which has big acreage positions on multiple assets.

Our cost structure should now be favorable as Dave mentioned when compared to our peer companies and the sum of our parts valuation provides a lot of upside for our shareholders and certainly supports a better valuation.

We’ve got to where we are today in a very compressed period of time by executing on the four-point strategy again and again and by being transactional.

In fact, Forest recently received the M&A financing deal of the year for last year’s innovative transaction with our Gulf of Mexico assets and Mariner Energy.

Our split out and separate financing of our Alaska assets was innovative as well and reflects this management teams’ efforts to add value and reward our shareholders.

There’s been a lot of attention paid lately to Master Limited Partnerships, MLT’s recently. We consider that structure for Alaska last year before choosing the split out financing sell route instead.

We started finding transactional waste to add shareholder value starting almost three years ago. MLTs are just another way to add value which we will consider as we have other transactions in the past.

Forest Oil has long live properties as well which could fit into this structure the same as other competitors in the area.

So there is a lot happening right now even before we talk about our first quarter results.

Turning to the first quarter, we spent $155 million of E&D CAPEX in the first quarter which is only slightly higher than the fourth quarter last year.

This is pretty much on track with our budget with Canadian increasing its spin rate due to the winter access drilling in the foothills and the associated pipeline and (print) construction in the same area.

We were able to maintain our drilling activity in the Texas Panhandle East Texas and West Texas despite the ice storms in the first quarter. In fact, we ran three more rigs in the first quarter in North America without spending much more E&D CAPEX than the fourth quarter.

It’s because of this that I believe we are now seeing about a 5% to 10% decrease in overall drilling and completion costs so far in 2007.

As a reminder, Forest does not have many long-term drilling contracts. So we can see the advantage of current market prices for drilling and completion activities on our properties and for Houston exploration as well.

During the first quarter Forest drilled 73 wells with 97% success rate. Activity picked up in the Canadian Foothills, Permian Basin and Katy. Most areas continued on the same rig count as they had in late 2006.

We moved another company owned land rig or one of our rigs from East - to East Texas to replace the rig sent to the Barnett Shale and moved our large deep well rig from Katy to Buffalo Wallow to handle the deeper drilling on the offset acreage that I’ll talk about in a minute. So far, so good.

On the production side our first quarter production was up 6% from the same period last year but was down from the fourth quarter.

As Dave mentioned, we previously announced guidance where we estimated we would have a down time of 13 million in the first quarter. We wound up about 11 million a day equivalents in the first quarter per down time.

The reasons were three, the severe winter weather and associated pipeline freezing, the refinery outage in the Texas Panhandle which backed up crude oil sales and caused limited gas well shut ins through the basin, and finally, third party plant maintenance in the Texas Panhandle primarily, some of which occurred because of the refinery outage.

I should note that Forest directly contracted 18 haul trucks to transport our common site to Cushing Oklahoma and other faraway locations following the refinery outage. This hurt us a little in terms of operating costs and it lowered WTI posted prices.

This is the first time I’ve ever seen WTI crude oil priced below Brent. The high level of Cushing oil inventory should come as no surprise to people in the know since pretty much every operator was trying to truck their crude there during this period. But it should not have affected WTI posted prices as much as it did.

The Alaska crude oil inventory build of 8 million days equivalent was simply due to tankers not showing up in mid to late March. They actually took their load on April the 5th. As most of you know, we’ve book sales or lifting, not production, in Alaska for crude oil.

Despite all the first-quarter downtime, we were able to set new records on our big three properties, Buffalo Wallow, Wild River and the East Texas Cotton Valley.

And in fact, the average rates for the quarter of Wild River and Cotton Valley were records as well as we have set records in every quarter since we’ve owned those assets.

Although not a historical record for the field, Katy has been up again this quarter. So I guess Katy is a record for the time Forest operated it.

Our LOE was kept under control again this quarter essentially flat on a per unit basis from a year ago and down 4% from last quarter.

I am pleased with the LOE control in the first quarter because typically we have winter related costs like we did in the fourth quarter. So our folks in the field were able to offset these increases with their efforts.

The only higher costs from a year ago was the Chevron operated properties in Alaska. I’m anxious to add the Houston Exploration properties into our project focused program. It’s a cost control program later this year that JC Ridens has spearheaded.

Our gas plant and pipeline work in East Canada - excuse me, in Canada and East Texas should benefit us later this year in terms of cost savings as well.

Now, I realize that cost savings aren’t the only thing to improve your results. But it is refreshing to see are people doing something over the past two years as opposed to being cost victims.

I will now go over the major operations highlights for the first quarter, most of which were included in yesterday’s press release.

I’ll also note where some Forest activity is relevant to the Houston Exploration assets like the East Texas Horizontal Program.

The Western Business Unit now run by JC Ridens had to deal with most of the weather and refinery outage problems, but had a solid quarter overall.

In the Buffalo Wallow field, our drilling times have been reduced enough that we added 16 wells in the quarter — the most we’ve ever added — even though we had a deeper average depth from the offset drilling.

Due to downtime, we averaged 38 million equivalents a day from Buffalo Wallow in the first quarter, but hit a new record rate of 41 million a day equivalents late in the quarter.

A couple of new items to note at Buffalo Wallow that happened during the quarter. First we drilled our third test well in the area to date on some of the undeveloped acreage away from Buffalo Wallow proper testing 7-1/2 million a day.

This was a great result on an undeveloped acreage blocks which could expand the field. We immediately staked an offsite location.

Secondly we began drilling on a six section farmout adjacent to Buffalo Wallow. In fact, we’ve never drilled a dry hole in Buffalo Wallow to date even when we’ve explored on the offsite acreage. This area continues to surprise us to the upside.

There’s been more horizontal activity both east and north of Buffalo Wallow in the Granite Wash Formation. We will monitor industry activity as we did in

East Texas to determine if this is a feasible application in our area since our vertical wells appear pretty good.

In the Vermejo/Haley area, we’ve not added any new exploratory wells, but our low cost reentry program continues to be successful with the last three reentries testing at a combined rate of 7.9 million a day.

I think we may have more reentry candidates than we first thought so we’ll continue this program

The industry activity at Haley has slowed considerably due to either their CAPEX constraints or awaiting the new 3-D seismic survey that will be available later in 2007.

One area we increased our activity in the first quarter is in the Permian shallow well program in West Texas, most notably Tex Mex and Martin and Andrews County and also in the Sprayberry area.

Net production has increased 275% in Tex Mex since we acquired this one in late 2003 and over 300% in Martin since acquiring it in late ‘04.

These shallow oil wells still offer robust economics with rates averaging 68 to over 300 barrels of oil per day this past quarter.

In the Rockies we resumed some drilling. We successfully delineated our North Anvil discovery in Montana with vertical wells. We tested 220 and 254 barrels a day.

We’ve already staked two offsets and plan to shoot additional 3-D on the offset undeveloped acreage.

Houston Exploration has a horizontal play to test the Bakken or Sanish in the Northern Rockies that’s not too far from here that will make good synergies with this play.

Forest has also assisted Houston Exploration with the re-negotiation of their long term rate contracts in the Uinta Basin last month.

Our southern business unit which will be named Eastern following the THX closing and will be headed by Mark Bush who previously ran the Southern production operation.

The Eastern region will comprise East Texas, Central Texas, the Arkoma Basin, our Arko-Tex area, Louisiana and our shale operations like the Barnett.

The new Southern Region will be housed in Houston and will handle the lower Gulf Coast, more specifically the South Texas position.

The eastern business unit had a great first quarter in 2007. They had higher production levels at Cotton Valley and Katy and had first sales in the Barnett Shale.

In fact the eastern business unit production was at a record level of 6% from last quarter despite the fact that they saw a lot of winter weather in East and Central Texas.

The East Texas Cotton Valley program continues to be ahead of schedule. And we’ve now taken all the steps in our mini plan I call it, we set forth a year ago when we acquired this property.

Production averaged 22 million equivalent to date in the first quarter. That’s net — a 69% increase in one year alone. When we purchased the Cotton Valley fields, we’ve wanted to average 20 million a day in ‘07. So it looks like we’ll have to revise the scale up for 2007.

We’ve also seen drilling times and costs reduced recently in East Texas. Most of the credit goes to our folks that work for Atlanta drilling. One of the Atlanta rigs is now drilling our first horizontal Cotton Valley test which should TD this month in Harrison County.

Industry horizontal activity is still brisk in East Texas and has now been done in five target zones by various operators, one in particular.

The Cotton Valley Sand, Travis Peak, Bossier Shale, and Bossier Sand had horizontal drilling in them. This activity has also moved further south, north and east of the original test in the blocker and Carthage areas.

Both Forest and Houston Exploration’s acreage are located in this activity so both assets have the potential for horizontal drilling on the undeveloped properties.

As noted in the press release, our East Texas low pressure gathering and processing facilities were started up on schedule in January and will be used to hook up third party gas as well including Houston Exploration wells.

The Katy field west of Houston, Texas has seen almost a 70% increase in production since taking over operations eight months ago. They’re currently at 22 million a day.

Our goal is to double production before our one year anniversary. Our partner Exxon has worked well with us.

The recent increase in production came from the first two middle-Wilcox drilling wells, the last of which tested 2.7 million a day.

We will also continue a work over re-completion program in the shallow Yegua and Wilcox reservoirs.

We have two more middle-Wilcox wells being completed at this time. The past success of Katy is the main reason we were contemplating or contemplated expanding the big three to the big four in 2007.

As noted earlier, we had exploration success in southwest Louisiana on our large civilian acre block. The well tested 7.7 million a day. We opened it up a little bit at 6000 pounds pulling pressure. Forest has 22% working interest in this well.

We have already started to offset delineation locations and will have the potential for a total of four wells in this field.

The large proprietary 3-D shoot on the north part of our acreage will be out of processing in late 2007.

Our Barnett Shale program had first production in the first quarter at 2.1 million a day. We previously released that. The second well is now being completed and fraced.

The third horizontal is now drilling and operated by Forest using a rig for us moved from East Texas.

We have several locations ready and anticipate a one rig program will give us six to eight wells in 2007. We need to get more locations before we go to a second rig. We’re evaluating this and working well with our partner.

Our gross acreage position in the Barnett Shale has now increased to 23,000 acres.

The Canada Business Unit had a very active first quarter in both in terms of drilling and facilities work that hooked up three gas plant facilities in the quarter, one at Wild River and two non-op at Ansell.

And just like last year, Canada hasn’t drilled a dry hole thus far in 2007. Even though they have a good portion of their program, it is still exploration oriented.

In the Wild River area, they completed eight wells with 100% success rate and again set another record for the quarter at 39 million a day.

The new Wild River gas plant was finished in the first quarter with first sales in early April.

This plant will provide additional firm capacity for Forest and will enhance our net back sand NGO recovery.

I should probably combine Wild River, Ansell and the Hinton areas into one area since it’s the same play.

Further south in the Ansell area, we added two more exploratory wells at 5 million a day each. I think these make the 15 to 16 successful wells at Ansell so far. Two additional wells have been cased and are now completing.

New gas processing facilities were finished to handle the new higher gas volumes. There’s been a lot of discussion about Ansell moving into the big three asset category. However, I think it’s still too early to tell where it’s going to be as good as Wild River in terms of staying power.

Our program in the winter access areas of the foothills resumed this winter with a West Narraway pipeline connecting the last two Narraway exploratory wells which tested 4-1/2 to 5 million a day a piece.

The last two Copton/Palliser wells tested 2 million a day a piece.

There’s been a whole lot of industry activity offset to our foothills acreage. I think we’ve got this play established in terms of predictability even though exploration involved by using 3-D seismic which covers most of Forest acreage.

The Evi-Loon shallow oil program had six wells at 75 barrels a day a piece. We’re still looking to maybe drill as many as 50 in fields here with economics similar to West Texas.

I should comment that the prices for shallow rigs in Canada have come down quite a bit because the shallow rigs in our opinion, are the ones that are mostly responsible for the 15% to 20% decrease in rig count in Canada.

Overall, prices in Canada have moderated just like in the US.

In international, as I alluded, we’re going to drill 1 to 2 million depth exploratory gas test in central Italy this summer. The prospect is called Monte Pallano and is near the Bomba area.

The pipeline access is only 7 kilometers away. And gas prices and Italy remains strong at $8 to $10 per MMBtu US.

Our net acreage position in Italy currently is 364,000 net acres. And these wells are in the 2007 budget.

We were able to sell, as Dave mentioned, our Australia assets for 7 million. We’re out of Australia. We had no reserves or production booked.

This is a good indicator that the remaining rationalized international assets we inherited have some good value.

Overall, I’m pleased with the quarter operationally and I’m glad to see the exploration piece of our portfolio start to kick in.

I should probably take a minute to highlight the fact that not all our first quarter activity was development oriented. We had a little more exploration in areas like Buffalo Wallow offset, the Rockies, Gulf Coast and Canada all of which were successful last quarter and added more potential locations to our robust inventory. And as I mentioned we’ll be drilling Italy midyear.

Our strategy and objectives near term for Forest are to: close and integrate the Houston Exploration acquisition, while setting up our Houston office, reduce and re-allocate capital company wide specifically on the acquired properties, sell approximately $600 million worth of assets, most notably Alaska.

Our personal goal is to reduce our well cost an average by 10% to 15% and then expand the big three or big four growth areas using both exploratory and acquisition projects, specifically Houston Exploration, expand our shale operations and of course grow production and reserves affordably and organically.

2007 will be a big in the transformation of Forest Oil, as our theme is Taking the Next Step. I want to thank you again for listening in today. Operator, we’re ready to take any questions they may have. Thank you.

Operator: At this time, I would like to remind everyone, in order to ask a question, simply press star then the number 1 on your telephone keypad. We’ll pause for a moment to compile the Q&A roster.

Your first question will come from the line of Brian Singer with Goldman Sachs.

Brian Singer: Thank you. Good morning.

Craig Clark: Morning, Brian.

Brian Singer: Can you talk a little more on the Buffalo Wallow Extension well to the south, characteristics and central applicability to a larger portion of the Buffalo Wallow acreage?

Craig Clark: It’s on our undeveloped acreage which represents a lot of the acreage that we added from the initial acquisition, and I think we’ve got about 45,000 acres. And, of course, most of our infields and locations that we identified a year ago were 300 to 400 of them, and now this adds to that, and that’s why I think it’s slid up to around 600 to 700 locations.

This is a brand new one, so we haven’t delineated it yet. We’ll be offsetting it, but that type of right is highly encouraging because previously that was reserved for the sweet spot in Buffalo Wallow. So that’s what the Deep Rig will be doing is drilling the deeper wells in the southern area that we call (Fry) and (Britt Ranch).

Brian Singer: Your project your well costs to be similar to what you’re drilling in the sweet spot?

Craig Clark: Well, higher because it’s an average depth of 13,000 foot at Buffalo Wallow. The ones to the south get as deep as 15. The medium wells are naturally 14. Amazingly, with this quarter, we’ve drilled the 14,000 footers in the same days it was taking us to drill the 13.

So we’ve had a couple of day improvement in our drilling time. But that’s a nice add on the undeveloped property, which I think was one of the wild cards we talked about for Buffalo Wallow was the deep and what the undeveloped acreage added. So that’s a plus.

Brian Singer: Great. Switching to the Vermejo Play. Chesapeake has become a little bit more optimistic on the Haley Play — do you see any overlap or any new techniques to try on the Vermejo. Are you any more excited about that play?

Craig Clark: They’re near us and we compete with them and Anadarko, and I think a lot of people are thinking 3D may be necessary for some of the deeper drilling. Our re-entries have hung in there, so we’re still have the same opinion of it on the re-entry side, except that before you drill some of the deeper wells, I think you want to have the 3D.

But we remain the same on the re-entries and so we continue that program and wait on the 3D. I haven’t had anything that changes our opinion except that we slowed it down because we were getting the drilling in front of the seismic. I don’t thing that would be prudent right now.

Brian Singer: Right, and lastly, a quick numbers question. What’s your going LOE in Alaska?

Craig Clark: Mike, what is it?

Mike: It was $5.34 per unit...

Craig Clark: For the quarter.

Mike: For the quarter.

Craig Clark: But it improved throughout the quarter.

Mike: Yeah, now it’s around $4.00.

Brian Singer: Thank you.

Craig Clark: Four to five I think was ‘06 and then they are affected by winter, because they have a little winter as well, but I think that was the wintertime effect.

Brian Singer: Great. Thanks a lot.

Operator: Your next question comes from the line of Tom Gardner with Simmons & Company.

Tom Gardner: Good morning, Craig, Dave, Pat.

Craig Clark: Tom.

Tom Gardner: Hey, regarding the Houston Exploration Acquisition, could you detail the areas in their portfolio that would be assimilated into yours as core areas and perhaps discuss low-hanging fruit with respect to margin improvement.

Craig Clark: Well, I’ll just take them — I’m going to speak with (closology) if you don’t mind, Tom. The areas that we have the biggest synergies, and I think we said this all along, was if you look at the map on the road show in East Texas, they abut us even in some cases, to the point that even our gathering system goes by.

So that’s the closest synergies — (unintelligible) formations. And actually it’s in a three-county area. Second most (closology) would be South Texas, even though their position in South Texas is much larger than ours, their seismic is much more plentiful. The map shows that they’re in the same formations along the lower Texas Gulf Coast.

The next place that I would guess has a side synergy would be the Ark-La-Tex area, the Arkoma, because of East Texas and the activities that we conduct in East Texas, and the next would be the I’m gonna call it part of the Rockies. It would be the Colorado (unintelligible) stuff and the stuff up in the Willowston that goes with our Willowston discoveries, but that would probably be a new area for us in the northeast Colorado and in Uinta was where we planned to reduce capital, although Forest has some properties in the Uinta that are non-operating.

In terms of low-hanging fruit, obviously we think the benefit of the synergies of the properties, particularly in South and East Texas, not necessarily on LOE because they’re dry gas, but in terms of capital costs, G&A, combining those operations and then also to be able to process the NGLs through facilities like our East Texas Gathering system would be that.

We think the biggest advantage would be to re-allocate the capital from the lower margin areas to the higher margin areas, basically from north to south, and if this sounds like a broken record, this is exactly what we did on Weiser back in 2004.

Tom Gardner: That’s very helpful. Appreciate that. Moving over to your Cotton Valley horizontal test, could you sort of discuss your ingoing expectations there with regard to rates and reserves, (unintelligible) costs?

Craig Clark: I think we’ve been kind of publicly conservative saying that not every field needed to be horizontally drilled when it’s already been down-spaced. The wells cost double to triple. An average well out here is a million and a half-dollars vertical. Some are deeper; some are shallower, and you need to double or triple that, and it’s not in the drilling.

It’s in the completion because of the fracs that have to be done with the rig and therefore we look to make the average well be doubled or triple, so I think that most people would be looking to make a $3 million a day type well with two or three B-type reserves, and again we’ve seen some wide variation. We said previously, that the variation averages from one to 15 million a day and there’s been some more larger wells announced.

I’m speaking strictly for the Cotton Valley Sand. I think some of the variability occurs because they’re in different zones, deeper in the Bossier,

down south. But I would think that you’d want to make at least triple the vertical well to make sure the economics go hand in hand with the well costs.

Tom Gardner: Excellent; excellent. One quick question on G&A. Do you anticipate any other costs going forward that might negatively affect it or can we expect it to return to historical norms?

Dave Keyte: (Unintelligible) stand alone, it’ll be right on the Guidance that we’ve been provided, so it’ll return to norm with the acquisition of THX, there’ll be some moving parts for the rest of this year, but ‘08 should be a very normal year for Forest Oil type level of G&A. We’ll be able to we believe take approximately 40 to 50% of the THX G&A can be reduced.

Tom Gardner: Thanks, guys.

Operator: Your next question comes from the line of John Herrlin with Merrill Lynch.

John Herrlin: Yeah, hi. Three quick ones — with the Italian Wildcat, did you promote it out and what kind of target size have you (unintelligible) and how long with it take to (unintelligible)?

Craig Clark: We programmed about a month for the well. That’s move-in to move-out. We’ll drill one and possibly two. One’s straight; one’s directional. So it’s a couple of months in and out and we’ll do the testing with the rig. The depth of the well is around 8,000 feet deep. They’re not hard to drill, although some of these reservoirs were penetrated 30 and 40 years ago which gave us some confidence of hydrocarbons.

There’s no promote – we have 90% work and interest. It’s straight up and as you know, we inherited some of this acreage. And the target size, I think the

potential for the accumulation is about 30Bs, and we think you can drain it depending upon whether you need two wells or three wells, and I should note that the wells drilled years ago had absolutely no or minimal stimulation done on them and I think there’s been some wells in the area test about six, seven, eight a day.

So the question is, will stimulation help and will you need two or three wells? But it is off the 2D seismic on some of the acreage that we inherited, John.

John Herrlin: Okay, Craig you mentioned the success you’ve had using your own drilling rig, (unintelligible) lantern and the fact that you didn’t lock in equipment. Lantern has kind of been a good foil for a rising rig rates when that was happening, would you feel compelled to maybe buy more rigs now that things are down to fit your development programs?

Craig Clark: We, as you know, most of the rigs we built except maybe one, were all built with spare parts. We got them at — we inherited the rigs for little of nothing. I doubt if we’ll build additional rigs now because our goal was always to be roughly half our fleet, and actually I’ve got one of each kind now, all the way from a single work-over type to the big rig which is 1,500 horsepower with big pumps that we used at Katy to try out, and it’s drilling those 15,000 footers at Buffalo. So I wanted one of each. And I think we’ll be okay with that.

And there’s obviously options that modifies those or use them. They have built our efficiency specifically in East Texas. The rig curve – they’re in first place on all the wells being drilled and I hope they’re going to have the same effect at Buffalo Wallow as they’ve had in East Texas.

And it gave me some option value from moving a rig to the Barnet Shell to keep a lease from expiring with our partner or otherwise. I think we’ll be okay on the rigs; I don’t think we’ll build any more because we’ve got enough flexibility with contractors now that we didn’t have a year ago.

John Herrlin Would you lock in equipment on a rental basis, Craig?

Craig Clark: On multi plays, the answers is yes. I just avoided signing greater than one-year contracts simply because you could almost pay the rig out and keep it yourself and you didn’t know what kind of rig or crew you were getting, and as you’ve heard me say, it’s not the iron; it’s the crews.

But we now use and exploration will take advantage, but where we’ve got multi-well plays we’ll lock those rigs up, but not for long term because we want to make sure that we don’t stop with one which is the phenomena going on the Rockies with our operators. Some people are having rigs built that they don’t need.

John Herrlin: Okay, last one for me is regarding services costs. You said basically that services costs in Canada were down same amount as in the US. You talked to other companies or listened to other conference calls, and a lot of E&Ps were saying that US operating costs were kind of flat. Do you expect more moderation or more moderation in Canada given the precipitous climb in the rate count?

Craig Clark: Yeah and when I said costs, I was referring to drilling and completion costs, not necessarily operating, and Canada is a unique phenomena now. Their costs never went up as high as they did in the United States and they won’t come down as low. But the small shallow posthole rigs are plentiful right now against our shallow oil program.

We’re not a shallow gas player, so I’m not the one to ask, except that in the deep-base scenarios, because of the winter, they haven’t come down as much yet because it just — we just finished the winter up there and we’re in road bands right now. It’s just that I think we’ve had overall some of the same type of cost reductions, but it’s mostly on the shallow side, not on the deep side yet.

But I’m also one that don’t think the Canadians went up more. I think we saw more inflation in paces like the Rockies than we did in Canada. And I’m guessing 5 to 10% because of the capital and the type of wells we’re drilling, but we are seeing some service price concessions in both candidates in the US and for Forest Oil, that’s most specifically drilling costs or drilling rig rates and fracture stimulation.

John Herrlin: Thank you.

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

David Tameron: Hi, good morning, Craig. A couple of questions — divest your program. Have you publicly announced what assets are going to make up that other piece of the $600 million besides Alaska?

Craig Clark: We have not. We will turn our attention to that after we get through the Alaska process. We’ve got some ideas and are gathering information on a set of assets, but we have not announced it.

Dave Keyte: That would be Alaska being the biggest part, some of what I’ll call it the non-assets, and then like Australia and then the rest would be marginal properties, but mostly from Forest we haven’t targeted any Houston Ex.

David Tameron: Oh, fair enough. On the timing of Houston Ex and Alaska, just from a modeling standpoint, when you go forward, are these going to close - does Houston Ex expect to close June 6 and that’s when you’ll reflect it. That same way with Alaska, will it be reflected the day you close or is it going to be retroactive adjustments?

Dave Keyte: No, they’ll be reflected the day we close.

David Tameron: All right. I think most else has been answered, but quick question in the Barnett. You said this is going to be a four-stage frac. The second well, are you still targeting 3000-foot lateral?

Craig Clark: Depending upon the acreage. I think the optimum lateral in this area would be 2,000 to 3,000 feet, but I’d say the average would end up being 2,500.

David Tameron: Okay, so the second well is probably 2,500, is that...

Craig Clark: I believe that’s correct, but the laterals out that far, I don’t know exactly the footage account in zone.

David Tameron: All right, and then when you guys announced the deal, you threw out some cost numbers, and I know you went over some of the CAPEX and big picture production numbers, can you re-cap what you said about costs as far as post-Alaska, post-Houston Ex? I think you used the words dramatic reduction, or may be those were Craig’s words. But what are you guys looking for as far as at a percent basis?

Craig Clark: I think, we’ll come out with Guidance, David. I think I’ll defer until then. But it will be a pretty significant reduction per unit costs, and I think that we’ll just

have to wait until we come out with Guidance and give an official number out there.

David Tameron: Okay, and then I guess - let me go out a different way too. Alaska, you gave out LOE number per unit. Can you give us a per unit DDNA?

Craig Clark: A DDNA - it’s just the US cost pool. So...

David Tameron: All right, okay, all right. Thank you.

Craig Clark: Sure.

Operator: Your next question will come from the line of Duane Grubert with CRT Capital Group.

Duane Grubert: Yeah, Craig I just want to ask about the three non-core assets. First, just to clarify, after the Alaska transaction, the way you guys have it envisioned, will you have any interest at all in anything in Alaska at that time?

Craig Clark: The data room has the entity in it, and depending upon the bitter, could have the other undeveloped acreage and pipeline assets that are not in the entity. And of course, you’d have to have value for both and the primary thrusts thus far have been to sell the oil and gas production currently with the exploration acreage outside it. So the answer is I don’t know. It’ll depend on the number and the buyer.

Duane Grubert: Okay, and then the kind of similar question. You guys got out of the Gulf of Mexico. Houston Ex had a series of steps getting out. Do they currently have any Gulf of Mexico assets that you will be inheriting?

Craig Clark: They have production from one small block in West Cameron and I believe they have about 18 undeveloped blocks that they went to the lease/sell and acquired, I think mostly in ‘05. And we’ll have to take a look at that for prospectivity and then do something with that, but we do not intend to stay in offshore long-term.

Duane Grubert: Okay and then finally if you could just update us if there’s anything going on in South Africa?

Craig Clark: Nothing except for production license and the commitments on the offset blocks. The production license, I think we’ve announced, is the next step for our gas discovery in I believe it’s called Block 2A.

Duane Grubert: Thank you very much.

Craig Clark: No capital being spent over there except they’re doing a little seismic.

Duane Grubert: Great thanks.

Operator: Your next question comes from the line of Craig Petrassi with Josup & Lamont.

Craig Petrassi: How you’re doing guys? Good morning.

Man: Morning.

Craig Petrassi: Could you provide any further comment on the joint venture with Westside Energy in Hill County as far as when we could anticipate any information as far as (unintelligible) on the current well that’s being drilled and future timeframe for new wells.

Craig Clark: Yeah, we work, obviously we do jointly the press release and we jointly press release the first well, it came on.

The second well is completing they’re doing the completion and they cracked it and they’ll have some information on it I guess in the next couple of weeks depending upon their work over rig availability.

And the next well is drilling in the horizontal leg and I don’t really know when we’ll have completion information, but there should be — you’re pretty much looking at drilling a well per month using the rig we provided.

Craig Petrassi: And Forest has taken over the responsibility of the actual drilling for those wells is that correct?

Craig Clark: That is correct and we’ve assisted each other on the completions. They are the completions expertise, a gentleman that used to work for another operator in the area that sold.

And then we worked with him on the pipeline closely to the point that the pipeline is at the location even though on the second well as we speak.

Craig Petrassi: Okay and I could just ask a quick question also. Based on some evaluation analysis from some other Wall Street Firms on your newly acquired acreage in Hill County, does this venture represent an opportunity to add some acreage in that area at attractive prices?

Craig Clark: We formed an AMI with them and they’re a mutual interest to add acreage in it. But that’s specifically Hill County anything outside of Hill County we’d be on our own.

Craig Petrassi: Okay, thank you very much.

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

Gil Yang: Good morning. Can you comment just on Barnette where the new acreage is and how much it costs?

Craig Clark: I don’t know the cost. You know I’m a cheapskate so it’s not much. There’s been some around Hill County that we’ve added and the rest of it would be adjacent to our acreage position in Erath County.

Gil Yang: How much do you have total in Erath?

Craig Clark: Let me, I think it’s of the 23,000, I think it’s 9000.

Gil Yang: Okay, 9000 of the 23,000.

Craig Clark: That’s correct most of our acreage is in the Hill County AMI and I think that’s gone up slightly as we’ve added leases here and there. And we’re able to still get — our acreage costs is low because of early entry, but I still think we’re paying less than 500 an acre.

Gil Yang: Okay. Could you talk just quickly about the kinds of things that you’ve done in Katy that have resulted in the dramatic pick up and production there?

Craig Clark: I should let Mr. Ridens answer, he’s the father of the program and operatorship, but it started with J.C’s. group working on, I believe, 75 shut-in wells. Many of which were just restored to production by they’ve done a yeoman’s job of putting all this compression in for low pressure.

So it’s basically the first couple of months was a fix it project with the surface facilities and then we drilled those shallow wells that are half million some of them came in a million a day a piece. They were 4000 feet deep.

And then the Middle Wilcox Wells which we think is the prize before you go deeper or roughly 10,000 feet and they’re coming in at 2 million a day a piece.

So it started with fixer upper recompletions work over which because of the number of shut in wells we’re not anywhere near through all the well boards and the surfaces of (unintelligible) really had to revamped because you’ve got to go back quite a few years before you’re up to 22 million a day gross.

And our goal would be to take from 13 to 26 on our one-year anniversary so we could brag about it, I guess.

Gil Yang: How many wells are still shut in then?

Craig Clark: Do you know the number J.C., it was 75 initially.

J.C.: Yeah, and I think out of that, we’ve probably restored production to six or seven wells. We still have large numbers shut in that have been evaluated for future work with bottom hole pressures and P&Ls and we’ve got a work over a recompletion program that’s ongoing.

Craig Clark: Based on the number of recompletions and restorations, Gil, I think it’s about maybe, I’d say it’d be 15 to 20 of them. We’ve actually had some work on. We’ve run pressures in all of them, but we’ve only had a rig on about 20 of them so let’s say there’s — I’m guessing but I’d say there’s probably at least 50 of them left.

Gil Yang: And how big are they when they come back on line?

J.C.: (Unintelligible) anywhere between 300 Mcfs per day all the way up to an excess of 1 million cubit feet per day (unintelligible).

Gil Yang: Okay and do I mean — having evaluated them do you think that how big, how deep is the pool of restarts that you can have there. Can you do all 75 or is it not really worth doing all 75.

J.C.: No we won’t be able to do all of the wells because some of them we have found completed intervals. We’ve also seen some water in plugs and some of the shallows so at this point it is premature to say exactly how many of those can be reactivated.

Our pilot program is testing a lot of concepts and as we get further down the road with that pilot program, I think we’ll be able to speak more accurately to the overall total.

Gil Yang: Okay, all right thank you.

Operator: Your next question will come from the line of Sebash Sundra with Jefferies and Company.

Sebash Sundra: Yeah, hi I want to apologize I bounced there a bit so I might be repetitive here, but what would the Alaskan volumes in the first quarter.

Dave Keyte: I think the Alaskan volumes in the first quarter were about 27 mln (unintelligible) that’s — and those are sales volumes. So they’re missing 113 barrels on that number.

Sebash Sundra: In East Texas some more — may be some more guidance here with this low pressure gathering system is this is a situation where maybe some of the older wells were pushed off line from some of the newer wells so is there a series of wells that are shut in there that will now commence production and if that’s a situation can you put some numbers to it?

Craig Clark: I think that in most of the gathering was — it was probably some compression needed, but also because of the older contracts, we were paying higher fees and getting lower net backs.

So the driver in the program was not restoring wells, it was getting lower fees and better NGO recovery and we’ve seen that. We do get the benefit of added compression centrally, but in our case, our wells were so new we weren’t having any bucked off. That does apply for all said operators like maybe Houston Ex.

Forest this stuff is mostly new, so I would say ours is not knocking off the wells, ours is bringing wells on so that they’ll produce longer and better rates, but more importantly, it’s going to lower our LOE and increase our net back. That was the driver and hook up times. We see that situation even in the (unintelligible) for Houston Ex.

So compression for us and Houston Ex particularly Houston Ex will be a big, big initiative in 2007 in the Arco Tex and South Texas area.

Sebash Sundra: Eastern Canada — any update there on some of the expiration programs?

Craig Clark: Well all our stuff - is if we’re East in Canada, it’s Eastern Alberta. And most of our stuff is central in West Alberta, but the expiration stuff that we’ve been

doing in Canada is primarily — is in the foothills of Alberta and up in the north, but not in the territories and we do not operate in Quebec.

Sebash Sundra: Okay, got it. And one final one. The — looking at the assets at Houston Exploration, you got I guess asset teams that have been reviewing this stuff, so after you signed the I guess the definitive you’ve had full access to the assets I presume?

Craig Clark: Yes, including due diligence, the field people, great visits and we went through all their properties and we went through all their inventories well by well. And that’s all normal, but it also would help in the transition in the course and it’s great because we get to know their people in the process. So yes, we’ve had full access.

Sebash Sundra: Great, thank you much.

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

Ray Deacon: Yeah, hey Craig I was wondering with the wells you drill to the south of Buffalo Wallow is it too early what the quantify what the impact can be on the 722 (unintelligible) of the potential you see in the area and also if you have any plans to drill any Hunt and Springer Wells in the near term.

Craig Clark: The first question is that 650 locations, and I think the slide you’re reporting to potential was at the end of 2006. So yes, those locations will add to that list, but I don’t know until we get the offset wells drilled, how many.

We don’t have any wells in any of the sections so that’s why I’m hedging that — and as you know the only place we assume for 20 acre down spacing was Buffalo Wallow proper. All the other offset areas have only assumed 80 or

160 spacing so there’s even in fill spacing on top of what we showed, so I don’t expect that number to go down. I expect that locations to go up.

Ray Deacon: Okay got it.

Craig Clark: And your other question was what Ray?

Ray Deacon: Really just do you have any wells planned to test the (Hunt and Springer) and also it sounds like the Katy Field is doing better than you thought and I wasn’t sure where that was in the potential in your prospect inventory, like what would you say the potential is there for the Katy Field.

Craig Clark: In the case of the Hunt and Springer yes, but we were offset and leased some acreage in the south just for those prospects.

Ray Deacon: Right.

Craig Clark: But we wanted to get 3D on it and we’re just getting that now. I don’t know that there’s prospects there, but yes if there are we’ll drill them. We’ve got the rig out there to do it.

As you know, our deep rig J.C. is pretty excited about a 7 million a day well, kind out in the middle of nowhere so we probably see it — we’ve had to pry him away from that rig for Hunt and Springer.

The Hunt and Springer wells were offset to us to the south and we’re 5 million a day so you know it’s easy to see that seven’s better than five, but it needs the 3D to identify those targets.

So I don’t have any wells in the inventory for that in ‘07, but we just got the 3D. On Katy obviously it moves up in the rank — surprised us last year on rate jumped up in production and again this year.

Let me be clear, the driver for Katy has big four property if you could call it that future is the in fill program and step out program in the middle-Wilcox and then deeper because as you know we have a brand new 3D survey that we shot for Exxon that hasn’t even been touched yet below the middle-Wilcox.

But the middle-Wilcox is the prize because those wells are 2 million a day and these little work overs come in a lot less than that. But, you know, we wanted it to be — if you had to be a big three property you had to come in at 10 million a day net up and the only thing that dilutes Katy from that is we only own half the interest in that field Exxon owns the other half.

Ray Deacon: Right, got it. Just two more quick ones. With THX, will you benefit at all at Sabine in terms of your ability to go after the prospects on that acreage? Is there any overlapping 3D there?

Dave Keyte: No, they have nothing in Louisiana that I’m aware of. They have a smidge of properties in Mississippi, but that’s all the stuff that we have and worked up here from the Weiser acquisition.

Ray Deacon: Okay got it and just on Canada, it sounds like you don’t have enough production history on the Ansell Wells, but clearly the 3D sounds like it’s helping at least to get better production rates.

I guess you know when you see that 150 locations going up based on what you’ve see so far this year in the debasing in the foothills.

Craig Clark: Yeah, the 16 out of 16 ain’t bad.

Ray Deacon: Right.

Craig Clark: But it’s driven off the 3D and the offsets associated with those have proved it up. The two wildcards for Ansell are it’s not multi-zoned completion like Wild River so you don’t give that call to Serendipity and the contribution from the shallower zones light and lack.

They are single zones although they are high rate. I think our partner has talked about them being better. And then the question is with all those sections of land you’ve got, I think you got 25 or 28,000 accrues how down spacing can you do.

For Wild River it was a given because our offset operator which is in Adarko was already down spacing to 160s prior to us even buying the stuff in the acquisition. But it’s so far so good. I do think if we get outside the main field, we need the 3D and Forest acquired that in 2D and 3d somehow most of it’s covered at this time. And it’s marred to the one rig program.

Ray Deacon: Great got it. Actually just one more quick one for Dave. Do you know whether those PHX acquisitions — I mean the hedges were tied to the Niobrara production or were they just Rockies hedges and wouldn’t you look at given the Rocky strip is up to about $8 look at a year, you know, would you to head some of those Niobrara volumes?

Dave Keyte: As far as I know, they have no CIG type hedges. Most of their hedges have been tied into Houston ship channel. That’s something we’ll look at, but I don’t think they have anything in CIG.

Ray Deacon: Got it, okay. All right thanks a lot.

Operator: Your next question is a follow up question from the line of David Tameron with Wachovia.

David Tameron: Hi Craig quick question. You mentioned the new region would encompass Shell does that — am I reading too much into it or does that mean you plan kind of chasing after some of the (unintelligible) that you’re getting with the Houston Ex?

Craig Clark: The — If it proves up into Fayetteville and they are south, then yes that would be in that area. However, that program right now is not designated to do that. I think it’s just likely that through their AMI they’ve got up there that they at least core it.

We had some Shell acreage as you know in Kentucky and Indiana and one other place and yes that will be our Shell business unit as our new ventures group spits them out.

David Tameron: Okay are you guys still trying to get additional acreage at the Barnett. I mean are there opportunities given lease expiration, etc., to do some (unintelligible).

Craig Clark: That would be more in partnering, lease expirations and farm outs. I think I mentioned on a previous call we saw even 2000+ an acre offset the Hill County and of course, we got surrounded by wells at some point.

The acreage prices have not moderated any and in fact have gone east past the thrust in Counties like Ellis and Dallas County.

David Tameron: Okay and then final question. Does Houston Ex have non-op properties that they have a significant position in?

Craig Clark: Very few non-ops. The only non-ops they’ve got of any significance is they’re primarily a non-operation in the (unintelligible) basin.

David Tameron: All right. Thank you.

Operator: And at this time, there are no further questions. Mr. Redmond, please continue with any closing remarks.

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

Operator: Ladies and gentlemen this does conclude the Forest Oil Corporation First Quarter 2007 Earnings Call. You may now disconnect.

END