Operator:

Good afternoon. My name is (Lou Ann) and I will be your conference facilitator. At this time I would like to welcome everyone to the Forest Oil 2005 Year End Earnings conference call. All lines have been placed on mute to prevent any background noise.

After the speakers’ remarks there will be a question and answer period. 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. Thank you.

Mr. Redmond, you may begin your conference.

Patrick Redmond:

Good afternoon. I want to thank you all for participating in our fourth quarter 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 27(a) of the Securities Act of 1933 and Section 21(e) of the Securities Act of 1934.

These forward-looking statements are subject to all the risks and uncertainties normally incident in the exploration, development, production, and sale of oil and gas. We urge you to read our 2004 report on Form 10-K for a discussion of these risks that could cause our results and plans to differ materially from those in any forward-looking statements we may make today.

I will now turn the call over to Dave Keyte. Thanks.

Dave Keyte:

Thanks Pat. Welcome to our conference call coming to you from snowy and very cold Denver.

Between the hurricanes and the spin off and all the hedging accounting nonsense in this quarter, it was a difficult one to analyze and I apologize for that. At the risk of grossly simplifying things let me explain what the quarter meant to us and it was really the tale of two companies.

As to Spinco and that refers to the assets that are going to be going to Mariner in a couple of weeks, it was a quarter where production and costs were heavily impacted by the worst hurricane season on record. Obviously all of you are well aware of this phenomenon and the results of Spinco and the amount of deferred production are basically in line with other companies with Gulf of Mexico assets.

However notably Spinco also began to ramp up its capital program to give it momentum into 2006. And that demonstrates some of Mariner’s influence on the operations of the business. The results from that capital spending were very good and many discoveries were made as Craig will talk about later including a deep shelf well. And since some of the discoveries were not at T1

at year end some of the reserves were not booked by Forest at 12/31/05 and therefore Mariner will get those in ‘06.

Also of note, all of the costs for repair, at least for book purposes, the charge for our deductibles of $10 million, $8 million of special assessments from OIL which is our capital insurance company for the hurricane damage incurred by Spinco have all been recorded on the books at Forest. And so all of the repair costs will be covered by insurance and those assets will move over to Mariner with a clean slate from a hurricane cost perspective.

So I think that even though the Gulf of Mexico operation was severely impacted as were others, the assets showed some good signs of initial capital spending by Mariners guys and as well the assets were primed for them to take over operations as clean as they can possibly be.

As to Remainco which is the rest of Forest Oil that Craig and I continue to be associated with, its operations were relatively unaffected by the hurricanes except for widening price differentials in our gas product. And production continued to increase with capital on target and costs continuing to be under control, amazingly so in some cases.

We are especially happy with the results of our multi-year, multi-rig assets and those are primarily Buffalo Wallow and Wild River and with the initial successes that are being shown at Haley.

So with that kind of an overlay let me now attempt to walk you through the numbers. But before we get to that let me just comment on the pending Mariner transaction. The Mariner transaction is in its final throes. The Mariner stock should begin trading on a when-issued basis. I think the last information we had was February 21. at that time Forest Oil will also begin

trading both regular way with the due bill and ex dividends at February 21 so next Tuesday.

In addition the transaction is expected to close on March 2 and begin Mariner regular way trading and Forest ex-dividend trading on March 3. So the time is near, the details are fast and furious at this point. But assuming that the shareholder vote at Mariner does go as planned, the transaction should be completed on March 2.

At closing but prior to the spin Forest will receive an estimated $175 million to $200 million cash payment from the subsidiary that is going to spin off to Mariner. Therefore Forest debt pro forma for the spin which is important when we start thinking - talking about what Remainco looks like in 2006, is about $650 million to $675 million at year end.

We believe that Mariner with 644 Bcfe of pro forma proved reserves and over a million net acres in the Gulf, an excellent deep water track record, and significant liquidity in its float, will be the premier Gulf of Mexico focused independent in the U.S. We’re anxious to see them perform, wish them every success. Craig and I will become Mariner shareholders and supporters of this fine company and management team.

Now before Craig discusses the operational highlights and the 2006 plan for Remainco or onshore Forest, I’d like to review the fourth quarter and the year combined operations.

There’s a lot of noise relating to hedge accounting in our earnings. I’ll do my best to reconcile this for you. During the quarter we incurred realized losses on our hedges of $118.6 million. Of that amount
$103.5 million was recognized through the income statement. About $35 million in other and

about 65 - or I’m sorry, about $68 million through the oil and gas revenue line item.

$15.2 million will be recognized in the first quarter. We encourage you to model that in the first quarter of ‘06. This deferred amount was required to properly match the loss that was realized with the related deferred production which was hedged in Spinco.

I know that’s all pretty complex and I again apologize for it, but unfortunately that’s the FAS 133 rules we have to work with. We also had unrealized mark to market gains of $53 million which we adjusted out of earnings.

In the fourth quarter production was down 23% over the fourth quarter of 2004 to $386 million a day and down 11% sequentially reflecting the effects of hurricanes Katrina and Rita.

Spinco production or the Gulf of Mexico production dropped to $104 million a day, a 40% sequential decrease. But Remainco production increased 6% over the third quarter to $283 million a day.

In the fourth quarter company wide leased operating expenses increased dramatically again reflecting hurricane related issues. Overall Forest’s direct LOE increased to $1.53 from $1 last year. Spinco was $2.21, almost 300% increase over last year.

But Remainco held up like a rock. Direct operating expenses were $1.29 per Mcfe, up only 4 cents from a year ago. Remainco’s cost control has been excellent in 2005. We expect only modest increases in 2006 as new, low cost

production continues to be a larger share of our production base and helps to offset the cost inflation in our base properties.

G&A expense was up $2.4 million or 25% compared to a year ago. Virtually all of that or $2.1 million related to salaries and benefits, both of which have increased substantially. It is simply more costly to maintain a staff than in 2004 and turnover has become even a greater issue this year even with these wage related increases. The remaining amount of the increase relates to increased external audit costs which despite being a year after Sarb-Ox implementation continue to escalate.

Interest expense was essentially flat for the quarter both against last year and sequentially. The company maintains similar overall debt levels and floating rate components of that debt remain small at 15% to 20%.

EBITDA for the quarter was $150 million, discretionary cash flow about $135 million or $2.16 per share. Both of these measures were impacted dramatically by the loss of Gulf of Mexico volumes, cost of Gulf of Mexico operations, and increased differentials throughout the company in gas caused by the hurricanes.

CAPEX for the quarter was $181 million. That’s a very large number for us and probably the largest quarter since Craig has taken over as CEO. While Remainco capital costs were $120 million and in line with prior quarters, as previously mentioned we began to ramp up the Spinco capital dramatically showing again the initial influences of the Mariner business model.

Spinco increase which was undertaken with the approval of the folks at Mariner was related to the deep shelf and other wildcat wells which were ultimately successful when they were completed in 2006.

In summary the fourth quarter was very challenging from the perspective of the hurricanes. However there are several highlights. One, Remainco was a rock during the quarter delivering excellent organic growth and maintaining its low cost structure. The time consuming regulatory process and transitional matters for our Mariner transaction worked throughout the quarter and are largely now completed.

Spinco’s increased drilling program was successful and that should help add to Mariner’s growth profile. The mess created by the hurricanes was largely addressed and while specific timing remains uncertain the path to restoring momentum in production in drilling operations is now clear.

During 2005 several milestones were achieved to position us for the future. Two very significant multi-year, multi-rig assets showed excellent results and now form the cornerstone of Remainco. These two assets, and that’s Wild River and Buffalo Wallow, combined to increase from $30 million a day to $60 million a day in the last nine months.

The Mariner transaction transforms the company, provides our shareholders with a dividend with significant value, the result of two excellent E&P platforms for our shareholders to own on a tax efficient basis.

Third, the cost structure of Remainco proves itself to be reliable and showed only slight LOE inflation. It had organic S&D costs of about $2.35 per unit while its PUD percentage decreased. Our leverage was reduced to 33% from 35% a year ago and we were able to increase total reserves 10%.

Overall 2005 was a terrific year for Forest Oil. It certainly provided clarity on the strategic focus of the company under the new management team as well as its operational capabilities moving forward.

Moving forward the company intends to pursue measured acquisition activity which provides multi-year opportunities and execute the multi-year, multi-rig programs as efficiently as possible.

Financially the company had a great year with record earnings, discretionary cash flow, and EBITDA. This is particularly gratifying in a year where our offshore operations struggled for several months. The year was a good one overall for Forest. However since the Gulf of Mexico assets are anticipated to be in the very capable hands of Mariner in a couple of weeks, we’ll focus our comments on Remainco results.

In 2005 we invested $600 million in Remainco and added 278 Bcfe of reserves at an all-in cost of $2.16. We increased our proved developed percentage to 75% within that reserve base.

Since our release last night we have received some questions about the nature of revisions that were included in that number. Let me be clear — these are not price related revisions. They are the results of our exploitation program. The proof of that is the decrease in our PUD percentage which if they were price related would be increased.

Leased operating expense for 2005 in Remainco was $1.24 per Mcfe versus $1.11 in 2004. Transportation costs were 16 cents in both years and production taxes were about 7% of revenue in both years. Therefore all-in production costs of $1.80 in Remainco in 2005 compared to $1.60 in 2004.

Remainco production increased 11% in 2005 to $271 million a day from $244 million a day in 2004. The growth was driven primarily out of our successful exploitation of acquired assets and that continues today. The fourth quarter Remainco production was $283 million a day and is on a nice trend line.

With reserve replacements from E&D spending of 154%, organic production growth of 8% and only investing an estimated 75% to 80% of Remainco’s EBITDA, we believe the go-forward business model for Remainco is extremely solid and the growth profile is highly visible.

With that I’ll turn it over to Craig who will give you much more detail in the operations of the company.

Craig Clark:

Okay thanks Dave and thanks to those listening in to the call. We appreciate you listening in today as we cover our year end results, the Mariner transaction update, and most recently our acquisition in East Texas. I guess y’all will get the three-for-one special today.

Although this really illustrates the pace at which we’ve changed this company at the end of only our second full year, our team has become adept at doing multiple tasks at one time for the benefit of our shareholders.

At this time last year we publicly stated that our primary goal for 2005 was to begin to unlock the intrinsic value of Forest Oil shares for our shareholders. We believe we are in the beginning to do that although we’re not finished as shareholders. In fact as we align our shares and even work harder for our shareholders — all shareholders.

There was a lot happening in our company in the fourth quarter as well as today. The highlights are probably too numerous to mention. While most

folks including us spent the fourth quarter of 2005 cleaning up after the hurricanes, we were able to move towards our closing of the Mariner Gulf of Mexico transaction while ramping up our activity on the remaining Forest onshore fields or Remainco as we call it. And we made an acquisition early this year to rebuild the southern business unit.

Our friends at Mariner did a great job working with our folks to get the documents completed and ensure a smooth transition on the expected closing on March 2. The Mariner transaction as innovative for both companies in the way it was structured and the time at which it was completed.

The other major highlights for our company are as follows. We had records in net income, cash flow, EBITDA for the year. For the first time ever revenues exceeded $1 billion. We replaced 190% of all production at an S&D cost of $2.45 per Mcfe. For Remainco we replaced 281% of production at an all-in S&D of $2.16 per Mcfe.

We did lower as was the focus this year our organic S&D for Remainco to $2.35 while our PUD percentage decreased. We drilled 392 gross wells in 2005. Our total project count was around 590 wells including the drilling wells. Both of these are all time records for our company.

We grew the Remainco production by 6% sequentially since the third quarter of last year and now we’ve completed the pieces of the puzzle to create a portfolio balanced in terms of production, reserves, capital spending, development, and exploration.

We were able as Dave mentioned to keep Remainco LOE flat from 2004 despite service cost increases and we’ve now got about a dozen growth areas

in North America where multiple wells can be drilled over multiple years. Most of these didn’t exist two years ago.

We’ve added value with other assets like the undeveloped acreage we’ve got the unbooked discoveries and now our drilling rigs and of course we have our favorable tax position.

Most recently we made an East Texas acquisition which establishes our goal - meets our goal to replace 2006 production and rebuild the southern business unit. And last we moved towards the Mariner closing and we had a few offshore discoveries and were able to take over operations for Chevron on nine blocks.

We have a little more noise in this quarter due to the residual effects of the hurricanes, insurance, hedging, and gas price differentials. Dave went into the reconciliation of these items and their effect on our fourth quarter earnings. Most of this should be eliminated in ‘06 for Remainco except the gas price differentials. They’ve settled down a bit but they are certainly still wider than historical averages. In all this noise we’re basically no different than others except that the offshore items will be eliminated in 2006.

In terms of production for the fourth quarter Remainco was as forecasted at 283 million equivalents a day, 6% higher than last quarter’s average of 268 per day. This is despite having 8 million a day roughly shut in due to the hurricanes. Otherwise our organic would have been even more impressive.

Our Gulf of Mexico production was lower than expected at 104 million a day equivalents because of the lingering hurricane effects. On December 31, 2005 as we said in the press release, we’ve got about 1/3 of our Gulf of Mexico shut in or 70 million a day and as of this week still offline 45 million a day.

Most of our operating platform repairs are completed. So pretty much what remains is either operated by others or related to third party infrastructure damage.

We took over operations from Chevron on our nine Unocal JV blocks on December 1 but no repairs have been initiated prior to that takeover date. These are some of our largest known operated fields. As we previously discussed, we lost only six minimal structures which produced six million a day net in the hurricane. In all told we lost 16 Bcfe net for the storms but we were lucky in terms of permanent loss.

We should also note that our insurance coverage comes from multiple policies and is sufficient in our estimate to cover all our claims over the $5 million deductible per occurrence. Both Remainco and Gulf of Mexico are off to a good start in 2006 with the projects noted in the operations release.

In terms of LOE per unit, Dave went through that but the cost control efforts in 2005 on Remainco offset service cost increases. That was our goal. We are again counting on that in 2006.

Our G&A expense will be higher in 2006 due to the loss of the Gulf production, costs associated with the transition including severance and the expensing of stock based compensation.

I should note that in 2005 all Forest employees were awarded options and/or restricted stocks that are now incentivized the same as management and are completely aligned with our shareholders. Reducing our cost structure particularly G&A is a goal in 2006 and we’ve already seen progress on Remainco DD&A and finding cost in LOE.

In terms of capital spending and drilling activity, we had E&D CAPEX of $181 million in the fourth quarter, $524 million for the whole year on E&D spending for all of Forest.

A couple of things happened late in 2005 that caused our CAPEX to be slightly higher. First, CAPEX from rig downtime due to hurricane; the second is that we did have service cost increases; and third, we did consciously accelerate drilling activity on both Remainco and the Gulf of Mexico to get a good start in 2006. I believe this will benefit both Forest and Mariner.

We completed 379 out of 392 gross wells in 2005 with a 97% success rate. Be careful the gross well count is inflated by the low working interest San Juan unit wells which were roughly half of the 392 which is 196 of them. So 196 wells were also on our core properties. Additionally we did over 200 major operations projects in ‘05.

These are records by a mile for drilling wells and projects of our company. Our pervious high was last year I believe at 144 drilling wells. This is indicative of our new strategy for Forest where we have ceased our dependence on high risk exploration and now have a high quality, low risk inventory. In fact I think back in 2001 we drilled about 100 wells but spent more than we did in 2005 and now we’ve got triple the well count. That was the plan.

And now we plan to continue our free cash flow model for Remainco spending 70% to 90% of our cash flow on E&D spending in 2006 yet still generating double digit growth for each year. Our reserves on December 31, 2005 for all of Forest were 1467 Bcfe, 1.46 Tcf, an increase of 9% for the year and 190% reserve replacement for an all-in F&D cost of $2.45 per Mcfe.

Our undeveloped portion for all of Forest was 27%. These are solid numbers. What’s more impressive are the Remainco reserve numbers on 12/31/05 of 1161 Bcfe which were up 15% from last year and a whopping 281% reserve replacement at an all-in F&D of $2.16 per Mcfe. If you want to break it out, our organic F&D for Remainco was $2.35.

Our PUD percentage for Remainco actually decreased. It’s now only 25%. So positive revisions reflect the results of exploitation projects particularly on the new acquisition which I noted earlier and are not solely due to commodity price revisions. Our 2006 plan for Remainco will more than replace reserves of the drill bit spending while under spending cash flow.

We may be a little unique compared to some of our peers in terms of our free cash flow focus and capital programs for our size. So all in all a pretty good year for Forest and particularly Remainco with the drill bits and the lowering of our organic F&D costs.

Now I’ll go into the operation’s highlights, most of which are covered in the release. I’ll spend some time after that going over our newest acquisition before Dave does the 2006 guidance.

The western business unit drilled 314 wells with 98% success rate — a record for them. I should note that most of our well activity in western is now done with our own company rigs.

As I noted in our headline, Buffalo Wallow in the Texas Panhandle continues to perform well. We drilled 37 wells in the nine months we owned this thing in 2005 and we’ve yet to drill a dry hole. Net production was 34 million a day equivalents in the fourth quarter, a 70% increase from the pre-acquisition rate.

The plan was to add 10 million a day. We’ve achieved that and going forward you’ll add about 3 million a day per quarter.

I guess the biggest surprise in the fourth quarter was the initial rates of some of the new wells. Using our four to five frac per well program and the commingled Atoka, our average rate in the fourth quarter was double the previous average of 2-1/2 million a day.

However we had one well, the best well ever in the field tested 8.9 million a day which brought up the average. Although I don’t expect all future wells will test this high, we have seen some improvements over the months we’ve owned this field and our average rate from our drilling and completion techniques.

I certainly like the trend I’m seeing. We will now need to upgrade some facilities as the strong wells like these good ones knock off weaker wells. But certainly the rate is above our original forecast.

The fifth rig in our program will start drilling in the second quarter, the sixth later this year, and we have between 50 and 60 wells in the 2006 budget for Buffalo Wallow. In the Greater Vermejo/Haley area we added three more site tracks in the fourth quarter at a combined rate of 8.3 million equivalents a day.

Now remember these are side tracks only. They’re much, much cheaper than drilling new 17,000 foot wells. We have two side tracks currently in progress. Our first two drilling wells are being completed and we had to wait a while before we got them stimulated. I would have liked to have had those results today but we’ll have those probably this month. A third well is drilling at 12,000 feet.

We also added 5,900 net acres in the fourth quarter bringing our position to 36,000 acres. We have about 1/2 dozen wells in the 2006 budget including re-entries for the Greater Vermejo/Haley area.

The rest of the activity in western was focused in the Permian and Rockies. Our shallow program in the central Permian is doing great and we’ve identified about 150 locations for infill drilling. Our offset operators are going down to 20 and 10 acre spacing and we’re only at 40 acre spacing and of course we have water floods involved as well.

The other area that could be a multi-well growth potential for us is in the Rockies where we made an oil well as noted in the release in the Williston. But we’ve got a number of infill locations that have already started in the Wansurrer and Jonah areas of Wyoming.

In Canada they drilled 54 wells in 2005 with 98% success rate. That’s pretty good considering they are do to exploration. In Canada the Wild River production continues to set records as we’re doing at Buffalo Wallow. We put the net production in here to show that it basically tripled since we brought it up from 8 to 25 million a day net with only a two rig program.

There’s also a 25% increase since the third quarter alone after we caught up on the completions and the hook ups we were talking about. A total of 29 wells were drilled in 2005 and again at 100% success rate.

The Evi-Loon area in central Alberta has become another potential multi-well growth area as three shallow pilot oil tips have proved successful. We’ve identified approximately 50 horizontal drilling opportunities on a block that’s 10,600 acres in size. And this is a light oil, not a heavy oil, which receives a good price bump to Canada currently.

We resumed our foothills drilling in Alberta after the weather subsided with two nice discoveries recently. The Waterton 10-30 is a sour gas well, about 15% H2S, it tested 12 million a day equivalents. And then the Narraway 13-2, one of our better foothill shallow wells, tested 5 million a day equivalents right at the first of the year. Both wells should be tied in late this year.

We have three more wells in progress in the Narraway/Copton area and again this is another one of the growth areas for 2006 and beyond. In the Gulf of Mexico we increased capital spending in the fourth quarter to provide the transition to Mariner smoothly. We drilled 12 gross wells in 2005 with an 83% success rate. This activity and associated hurricane costs were the main reasons for the CAPEX increase in the fourth quarter.

We’re also able to assume operatorship of nine blocks from Chevron which were originally in our Unocal JV and were some of our bigger non-operated fields. This also helped expedite Hurricane Rita repairs. We had three nice discoveries in the fourth quarter and early this year at Grand Isle 76, South Timbalier 288, and Ship Shoal 26 plus some good rework results at Gremillion 102. All are noted in the press release.

The Ship Shoal 26 number 14 is a deep shelf test which has a deep - which is a loss pay but also has additional deep objectives yet to be drilled. These projects will give our friends with Mariner a good head start on their assets. We currently have two jack-ups drilling and two jack-ups doing recompletion or remedial work.

Southern business unit drilled ten wells at 88% success rate but they were focused in two areas — South Louisiana and Southeast Texas. They initiated

drilling operations and were able to take over operations to drill two wells at Katy where we have 4,000 acres.

Activity has also begun in West White Lake where we have 6,600 acres and some other operators have made a nice discovery east of our acreage that I think tested around 40 million a day. We do have 3-D and we’ll be evaluating the deep targets as well as the shallow at West White Lake.

The business will have a big increase in activity in southern because of the East Texas acquisition I’ll talk in a minute about.

In our Alaska onshore gas exploration program we were able to get four wells down with three being completed and one well dry. Two of the wells got tested before the weather ran us out of there. The west Foreland number 1 was 4.7 million a day and the Kustatan #1 tested 2.6 million a day. We’ll install additional compression later this year to handle these wells and our current rate is around 11 million a day net.

We also added another 18,000 acres in the fourth quarter to our onshore position for gas. In 2006 the program will be focused primarily on shooting additional seismic onshore and then restarting the exploration activity in the summer just like we did last year.

I thought I might mention in terms of international, although it’s not listed in the release, we’ll spud our well in offshore Gabon in the second quarter to test shallow oil targets. I think that’s when the jack-up will be there, only 150 foot of water. And we’ll have a 40% carried interest in the first well.

Our gas tests in central Italy will spud in the second quarter as well as the shallow tests. But our CAPEX spending in international in ‘06 will again be minimal because of the carries or promotes.

Now for our East Texas Cotton Valley acquisition. I’d like to spend some time describing it as we announced it earlier this week and thought we’d talk about it on this call.

This acquisition is perfect in terms of timing and it will be essential in rebuilding the Southern Business Unit. It fits the multi-well, multi-year pattern that has common characteristics of what we’ve purchased over the last two years, certainly in the last year.

It was specifically in a targeted area. Again we called the shots. It involved tight gas formations with multiple objectives infill drilling similar to Buffalo Wallow and Wild River. It’s got both deep and shallow potential. It adds significant developed and undeveloped acreage. Downspacing has been approved in some of the areas.

Potential for operational improvements in drilling completion and compression marketing we think exists and we have a large inventory of development locations that are currently not booked.

It does certainly add another growth area for our company for years to come and the property in 2006 should generate free cash flow using a two rig program.

It meets our goals early in ‘06 to replace reserves through acquisitions on top of the drill bit activity. In terms of this acquisition it should sound awfully familiar. In fact it should sound like Buffalo Wallow. The pattern should

sound familiar. The properties are located in the heart of East Texas east of Tyler, primarily in the counties of Harrison, Marion, and Panola Counties. I even roughnecked on rigs in this area so it’s like going home.

We’ll have approximately 26,000 net acres, 15,000 of which is my estimate for undeveloped. Main field names are called Woodlawn, Blocker, Oakhill, Carthage. I’m sure some of you are familiar with these fields due to the high activity in them currently. Eighty and 40 acre spacing is in progress and has been approved for most of these fields.

We purchased around 13 million a day net equivalents, 110 Bcfe of reserve for $255 million from six private parties. Please note that these were not separate properties from each party but basically buying the working interest owners in these same fields. So operatorship and average working interest will be high. The reserves are 43% proved developed, 57% PUD which looks similar to what we did at Buffalo Wallow.

This acquisition is 90% gas. We have approximately 100 infill locations in the Cotton Valley already plus another 200 potential offsets bringing the total to 300 in inventory. Most of these locations are Cotton Valley sand wells. However there is some shallow Woodbine and Pettit locations.

We have not yet really looked at the shallow potential in the James Lime, Rodessa, Texas Peak, Bossier, and the deep Cotton Valley Lime Smackover. All of these zones produce to some extents in these counties but again kind of like the Atoka which worked out well at Buffalo Wallow.

So that’s a description of the assets. Now what we plan to do with it — we’ll run a two rig program in 2006 and go to four rigs in 2007. The first two rigs are presently in the field drilling. We expect to drill 20 wells in 2006 and 50

wells in 2007. We plan to close around March 1, 2006 so we will have this asset for nine months again like Buffalo Wallow.

We’ll first focus on drilling efficiencies and cost reductions. These wells are around 10,000 feet deep, shallower than Buffalo Wallow, and currently average $1.6 to $2 million apiece to drill & complete.

Next we will evaluate fracture stimulation techniques and commingling additional sand stringers before we add the third and the fourth rigs. Again just like Buffalo Wallow. Sorry, I’m beginning to sound like a broken record.

Our next steps would be to optimize the field facilities and compression and eventually look at the serendipity of shallow and deep objectives I mentioned earlier. We expect to double production by the end of 2007 using the schedule I described. This will be about four Bcfe in 2006 and eight Bcfe in 2007 per our press release. Our LOE is around $1 an Mcfe.

We will formally update our guidance at closing since we have to close with six different parties and timing could change a bit. So another growth play in our company. We’ll go over all these plays at our analyst conference, March 16 in New York City.

And before I turn it over to Dave let me say that 2005 was a pivotal year for this company. I am extremely pleased with the progress. This is a big, big time for our company and our shareholders with the dividend they’re going to receive. I certainly appreciate our employees’ hard work and dedication in building this company and increasing shareholder value. Dave?

Dave Keyte:

Thanks Craig. I’ll go over just the 2006 guidance fairly quickly here. It’s in the press release and I don’t want to dwell on it. I do want to mention a couple of things for people that have to try to model this.

First, it is not clear at this time whether we will account for Spinco as a discontinued operation or not. We hope to have clarity on that topic but it’s still under consideration with our accountant. If it is accounted for as discontinued operations, we will one line its ‘05 and ‘06 results and show Remainco clean for ‘05 and ‘06. If we do not show Spinco as discontinued ops, we will show Remainco pro forma information in ‘05 and ‘06.

And therefore either way you’re going to be able to assess Remainco stand alone in 2006 and compare it to its stand alone results in 2005 one way or the other. For that reason we elected to give you 2006 guidance on Remainco only. Notably the guidance does not reflect the pending Cotton Valley acquisition that Craig just talked about.

Okay with all that, in 2006 we’re guiding to a range of 290 to 310 million equivalents a day. This will provide for year over year growth of 7% to 14%. Acquisitions are providing about 1% of that amount, the remainder being organic. Production expense is estimated at about $200 million. That’s the midpoint of the range or $1.83 an Mcfe versus $1.80 in ‘05. Again the low cost wells that we’re bringing online we believe will offset anticipated cost increases in our base production.

G&A should be between $34 million and $38 million. A new line item in our income statement this year that we will separately state will be non-cash charges for stock compensation pursuant to FAS 123-R. It is estimated that this cost will be $14 million. Notably there will be a charge of about $9 million of the $14 million in the first quarter relating to the spin-off.

The DD&A expense per unit will be reduced to about $1.95 to $2.05. This reflects the spin-off impact on a full cost pool. CAPEX is slated to be between $425 million and $475 million. Forty percent of that number is being spent in Buffalo Wallow, Wild River, and Greater Haley.

Overall 2006 looks like it’s shaping up well. Growth and reserve replacement targets are progressing nicely. We look forward to the public trading success in both Mariner and Remainco. And with that Operator we complete our remarks and we’d like to open it up to questions.

Operator:

At this time I would like to remind everyone, if you would like to ask a question please press Star then the number 1 on your telephone keypad. We’ll pause for just a moment to compile the Q&A roster.

Your first question comes from David Tameron with Jeffries.

David Tameron:

Morning, congratulations on a good year.

Craig Clark:

Thanks David.

David Tameron:

A question for you. In Wild River you mentioned you’ve gone from, you know, quadruple production. Can you talk about with only two rigs running, does that imply that, you know, the wells - can you talk about the (decline) rates up there? Are they doing what you want or are they exceeding expectations? Can you comment more on that?

Craig Clark:

Probably exceeded expectations for two reasons. One is you can see with the lesser rigs you’ve got that kind of rate increase. Of course we’ve been at it, I think we took over in July of ‘04. And secondly, there was a deep well that

the Wiser had drilled that had to be defined that you had to offset that as well. So in terms of the shallow wells, certainly they’re a little bit better than we first thought.

David Tameron:

Okay and in East Texas, you guys acquired this from six different sellers I guess, you put in the press release. Was there one that made up a big chunk of the acreage or was it - is it contiguous acreage? I mean, can you give us some more description?

Craig Clark:

It would not be disanalogous with Buffalo Wallow where it was all kind of concentrated around. But it’s, I would say probably in - if you’re looking at a map - in really three pods and that the names of the field. Blocker, Woodlawn which is the biggest, and Oak Hill. And I would say it’s really kind of in three big pods as opposed to one compared to Buffalo Wallow. And I’ll be happy, you know, I’ll be happy to show you a map when we release the analyst conference stuff.

David Tameron:

Okay, and then maybe a question for Dave. In your NOLs, do any of those transfer to the Spinco or kind of what’s the new updated number for NOLs?

Dave Keyte:

I don’t have that new updated number for the NOLs David. But nothing - none of those NOLs will go to Spinco. Remainco will keep everything.

David Tameron:

So you still have the $700 million type, whatever that amount?

Dave Keyte:

As of ‘04 yeah. I don’t know what the ‘05 number is. But all of that stays with Forest Oil.

David Tameron:

Okay. And is there an expiration, I mean, is there a timeframe on those?

Dave Keyte:

Oh sure. Whatever we put in the footnotes for last year remains the same.

David Tameron:

Okay, I’ll let somebody else jump on and get back in the queue. Thanks.

Dave Keyte:

Okay thanks David.

Operator:

Your next question comes from Larry Busnardo with Petrie Parkman.

Larry Busnardo:

Hey Craig, Hi Dave.

Craig Clark:

Hey Larry.

Larry Busnardo:

In regards to Buffalo Wallow, can you just talk a little bit about the rates that you’ve been seeing, the difference between say the well that’s .5 versus the 8.9 million a day well? Is it primarily just commingling frac jobs? Can you just go into that a little bit more?

Craig Clark:

Well it’s - in our original economics we were assuming about a million and a half to two million a day type well. And I think through the third quarter we were about 2-1/2 million a day. I would attribute that to the completion techniques in the Atoka zone, basically more fracs per well, you know, and be more selective in the zone.

The 8.9 is just clearly a better well and, you know, it’s more or less an outlier. However the trend each quarter if you’ll note in the press release, it has been that the average rate has been increasing. But we are adding the Atoka on every well because it’s very economic in doing a four to five frac per well model instead of the three to four that was previously used. In fact years ago it was even one to two. But that is really an outlier and time will tell.

But that would make your average rate in the fourth quarter be like 4-1/2 million. I think that would be optimistic. So, you know, we’re starting to see the 2-1/2, the 3 million a day type well and that’s markedly better than we first thought about a year ago.

Larry Busnardo:

All right, have you been able to offset that well that produced 8.9 million a day or have you gotten close to it at all?

Craig Clark:

We’re doing it now.

Larry Busnardo:

Okay, how about well costs? With the commingling, additional fracs, has that increased?

Craig Clark:

Yeah, it - well the rig rates have increased. That shouldn’t be any secret but the additional fracs would be the biggest cost. Other than that and we’d be initially 1-1/2 million to 1.8 million per well. I think we’re close to 2 million per well now but obviously the rates are better.

Larry Busnardo:

Okay, shifting over to the Haley area, the three re-entry wells coming on at 8.3 million a day. Would you say that - has that been meeting expectations?

Craig Clark:

Yeah, on the re-entry program we announced three to five would make us happy. Our first wells were five and then the rest of them averaged about three apiece. That’s fine.

We’re basically salvaging well bores that were corroded with the deeper sour gas years and years ago. And that limitation in the well bore mechanically doesn’t allow you the full flexibility of fracing like you do in a new well. But considering they cost way, way less they’re more economic.

Larry Busnardo:

Okay, and what’s the timing on the completion of the two grass roots wells?

Craig Clark:

We’re stimulating them now.

Larry Busnardo:

Okay so would you potentially have results at the meeting next month?

Craig Clark:

Yeah I would hope so. In fact we had to wait for the stimulation because we do multiple fracs on the wells. And the first one took forever to drill because of the drilling rig. But the rest, we completed, set pipe both of them in I think December and have waited on the stimulation and associated equipment. And we did that starting late January or February.

Larry Busnardo:

Remind me what the well costs are for the grass roots wells.

Craig Clark:

Well the one that took longer would cost more but I would say $7 million to $10 million depending on how many fracs you do.

Larry Busnardo:

Okay and just lastly, can you just remind me what you have going on in Gabon again and then the well with Italy?

Craig Clark:

Yeah the Gabon is a 2-1/2 million acre block which we promoted out. This will be our second time or third time to promote it. We got a carry for seismic and a well, the first well only, and we have 40% in operating. We - our cost exposure would go to the point that we either exceeded that well cost or go to a second delineation well.

And we shot the 3-D about a year ago and the rig is becoming available. It’s a jack-up rig in shallow water looking for shallow oil both pre - above and below the salt. But the wells are only 4,000 feet, 4,500 foot deep. But it’s I guess the traction is it’s the largest undeveloped block of acreage off

Gabon, 2.4 million net acres. And if you’ll look at our 10-K this year, the only reason the net changes is because we brought those partners in.

Italy is a shallow gas whole valley basin centered gas. It’s one of the left over blocks I inherited but we termed it perspective. And of course as you may or may know, their gas market has really gone up. They’re actually getting $15 I think over there these days. It’s become quite a dire situation for gas which is favorable to our gas drilling. But it is a shallow well but that will be most of international’s capital for 2006.

Larry Busnardo:

All right, great. Thanks for the update.

Craig Clark:

Thank you.

Operator:

Your next question comes from Subash Chandra with Morgan Keegan.

(Uma Bankatraman):

Hi, this is (Uma Bankatraman) for Subash. I have two quick questions. You mentioned that you would be increasing your rig count in Buffalo Wallow by one rig in second quarter. Do you have some of the plans in the other areas? And if you could give me some kind of a broad range of what the rig count is currently and where you expect it at the end of the year. And I have a follow-up question.

Craig Clark:

Okay, the rig count for all of Forest last year was basically around 20, 22 rigs. It will be the same for Remainco next year but we’ll lose those four rigs in the Gulf to the Mariner transaction but we’ll increase it by about the same amount so we’ll still be running 20, 22 rigs. And that’s kind of a good medium for us in terms of our operations.

(Uma Bankatraman):

And you expect to increase it by four rigs in ‘06?

Craig Clark:

Yes ma’am but the total company will be the same. We’ve just replaced the offshore with some onshore rigs including the Buffalo Wallow in East Texas.

(Uma Bankatraman):

Got that. In your East Texas development, the acquisition, do you have a sense of how much of the capital expenditure is going to be directed towards your spud drilling and how much would actually be directed towards, you know, fresh new well drilling?

Craig Clark:

Well I don’t have the capital number for that. When we give the guidance we’ll give the capital. But I’ll tell you virtually all of it will be on new well drilling.

(Uma Bankatraman):

Okay, one last question. Do you have any broad comment on what you’re seeing on the Bacan acreage in Williston? You mentioned the results from one single well. Do you see anything encouraging or any kind of opportunities? What do you see in that region?

Craig Clark:

We’re not in the Bacan play. That’s actually conventional old reservoir discovery off 3-D. But acreage globally has gone up tremendously and that’s why I believe our underdeveloped acreage and acreage position for our company our size is a large and valuable but I view that as my inventory in year three, four, and five. But I can’t comment about Bacan because we’re not in that play.

(Uma Bankatraman):

Okay thank you.

Operator:

Your next question comes from David Diamond with Wooster Capital.

David Diamond:

Yeah hi, good afternoon guys. Congratulations. My question Craig relates to what additional restructuring is necessary or possible at Remainco? Specifically how do you go about using the, you know, approximately $700 million NOL to realize the remaining value in South Africa and McKenzie Delta Cook with Gabon, etc., none of which the market seems to give you credit for. What are you thinking along those lines?

Craig Clark:

Well let’s just take, you know, the - I guess you can call it the other assets. The most valuable starting at the top is probably the NOLs and that gives us leverage on acquisition and economics. The second one is the land position and quite frankly just based on the last call it’s become increasingly valuable particularly in places like Canada. That’s our inventory. When this one runs out in year five and six or whenever it is.

The next one will be the drilling rigs and that’s my cost hedge. But it also gives me insurance that I can get my plan executed. And then last but not least the international discoveries would be develop or sell them.

David Diamond:

Right, so is that something that we should look for in the future is possibly asset sales?

Craig Clark:

We - I think we’ve sold about $50 million, $60 million worth of stuff. We’ll always have stuff to help clean up. But in terms of monetization, I view monetization of unbooked discoveries the same as bringing them on production. We just have to bring value forward for those assets in 2006 and that’s the go for international.

David Diamond:

Great. Thanks very much, congratulations.

Craig Clark:

Thank you.

Operator:

Your next question comes from Robert Lynd with Simmons and Company.

Robert Lynd:

Good afternoon.

Craig Clark:

Hey Robert.

Robert Lynd:

Craig, do you plan to hedge the volumes associated with the acquisition?

Dave Keyte:

I think that - Robert this is Dave. I think that, you know, we’re going to monitor that. We think that, you know, gas - visibility on gas prices is a little murky right now and, you know, the volumes frankly aren’t that significant to our portfolio for the year so it wouldn’t impact our overall portfolio strategy.

So I think that we’re going to initially wait unless we get some further clarity on - internally on where gas prices may head. But right now I think us like most people on this call, it’s a little murky until we get through winter.

And one more, can you tell me what Spinco’s ‘05 exit rate was?

Craig Clark:

It was in the - wasn’t it in the - I think it was in the S-4.

Robert Lynd:

(Unintelligible).

Craig Clark:

Not total. I’ll - can we get back with you on that one?

Robert Lynd:

Yeah sure.

Craig Clark:

I believe it’s in the S-4 for Spinco and I can’t answer for Mariner but I believe we can get that for you.

Robert Lynd:

Okay thanks, that’s all.

Craig Clark:

Okay.

Operator:

Your next question comes from Gil Yang with Citigroup.

Gil Yang:

Hi, actually this is sort of piling on to that question. Do you have an exit rate for Remainco?

Craig Clark:

No, the only thing we’re going to - we publish is going to be the 283 for the quarter. We do have one but it’s not going to be public, we’re not going to make it so.

Gil Yang:

Okay, Craig, are there, you know, you announced sort of three sort of growth legs to your stool. Are there any other legs are is it just you want to make each leg bigger?

Craig Clark:

Yeah, they’re three legged stools and I’ve got four of them. We figure there about a dozen. I think I sat on one of those stools when I was a roughneck. But the big linchpins, and you know I like to call them (bell cows) is clearly Wild River, Buffalo Wallow, and now East Texas. But I’d say even that Permian location or even the stuff at Evi-Loon and at the analyst conference we’ll allocate that.

And the one thing I want to see is I want to see us spending our capital on the major fields and not spending it all over the place that we can’t, you know, you want to major on the major things. And I think you’ll see that we’re concentrating most of our capital on those fields which would add the biggest value.

But I’m counting up roughly — don’t hold me to this — about a dozen places where we would build multiple wells over multiple years and they’re not currently counted as PUDs.

Gil Yang:

Okay, with your CAPEX budget for ‘06, can you comment on what you expect your reserve replacement to be?

Craig Clark:

Ooh I don’t even know. I’ll tell you the formula I use and you remember this from the old Forest is if we spend a percent of our cash flow we’d like to have that same number. But clearly I don’t know what that is. In terms of replacement we just have targeted a cost level with the capital budget from a known inventory.

Gil Yang:

All right, let me ask a different way. you know, with the let’s say 450 capital spend, if you replace roughly, you know, 100%, 200% of your production you’re going to end up with a 225 or so F&D cost. Is that a reasonable reserve replacement given that kind of spend level?

Craig Clark:

I just don’t think that, you know, we don’t comment on those kind of forecasts and I feel uncomfortable commenting on it. But obviously your math is correct. But, you know, I just don’t think we’re going to get into forecasting reserve replacement.

Dave Keyte:

But our goal is to replace reserves internally.

Gil Yang:

And then last question is can you comment on the EUR for the Williston well that you mentioned?

Craig Clark:

I don’t know yet because we just turned it on and we’ll get some performance for it and put it in there. It’s, you know, a nice little well. But it was generated off the 3-D, it’s conventional, and we’ll see - get some performance for it first and then decide whether to offset it. And we’ll have to wait on a rig for up there as well but I wanted to see some performance for it.

I don’t, you know, it’s not going to be big but it’s nice to have that program as well. Some people don’t think we have anything in the Rockies and we have quite a bit in terms of gas and now that.

Gil Yang:

Are there analogous fields nearby?

Craig Clark:

There’s actually an analogous field nearby and I don’t think the name of it, but it’s a very large field. But it’s the same seismic theory, the same seismic bump theory but - and it’s a pretty good field. It makes a couple of thousand barrels a day. But I think it’s premature for us to estimate that until we see some performance for this well for at least four or five months.

Gil Yang:

Okay, thank you.

Craig Clark:

Thank you.

Operator:

Your next question comes from Duane Grubert with Execution LLC.

Duane Grubert:

Yeah Craig, I wish you’d comment a little bit about philosophy. With your production split at Remainco being kind of 60/40 gas, do you have any vision of where you want that to go going forward? Or is that going to be pretty opportunistic?

Craig Clark:

Well it will get a little more gassy but that’s just a coincidence. You know that I like to have a balance. Right now oil is a little more favorable than gas. And from an acquisition standpoint we like to do both particularly on the oil side because there’s other things to fool with like artificial lift and lifting costs. But we do like to see that kind of balance, 60/40 is fine and we’ll continue with that in terms of how we go forward.

Duane Grubert:

And then a similar kind of question on your PUD philosophy. There are some companies out there that are pretty overt about saying they’re conservative on the PUD booking. You know, I look at your numbers and correctly, you know, the PUD numbers didn’t change very much which is pretty healthy. But how would you describe your PUD in terms of being conservative or unconservative relative to let’s say the acquisition market or other companies that you’ve seen out there?

Craig Clark:

Well it’s certainly a lot more conservative than the acquisition asset market and some people who would drill on book for offsets. We haven’t done that. Basically we drill them up and in fact through the acquisition we drilled them up very early so that any future upside would be there for our shareholders.

And, you know, we tried to be conservative. And it was our objective to determine the real what I call organic F&D for Remainco because we want to know as much about that as we can because that’s what Dave and I will have to manage. And but I do think that’s more conservative particularly in an asset sale situation.

Duane Grubert:

Okay and then finally, could you comment on liquids extraction markets? I see your Canadian liquid has changed a little bit. Is that a function of processing being turned on and off or changing mix or what is that?

Craig Clark:

I don’t think it’s changing mix Duane. I do think it’s favorable to process right now and our VP of Marketing, Blaine Walker, has done a great job throughout the company trying to get those type of processing options. It’s certainly more lucrative today to convert that into (NDL). And we will actually have that as a go in ‘06.

Duane Grubert:

Okay great, thank you.

Craig Clark:

Thank you.

Operator:

Your next question comes from Ray Deacon with Bank of Montreal.

Ray Deacon:

Yeah hey Craig. I wanted to ask about the - about Alaska. What’s - did you have - where do you - how many more wells do you think you can drill by the end of the year and, you know, what’s the success rate been so far?

Craig Clark:

Well let’s see, I think the total number, I think we were four out of five last year. And in terms of the number it will depend on the seismic but I think he’s got about a half a dozen wells in his inventory. And a couple of them are pretty shallow but, you know, we basically are - for the shallow wells we try and not do it in the winter because it just takes the cost per shallow well and literally doubles it.

So we’ll start in the summer and get as much done. We still have to complete that third well and do some additional testing on it in the summer, but we did set pipe on it before we got run out of there. So I’d say half a dozen. And their budget is only up this year because of the land and seismic.

Ray Deacon:

Okay, got it. And in the Haley area, what’s your acreage position now? I think you said in the third quarter it was up to about 30,000 acres.

Craig Clark:

It’s 36,000.

Ray Deacon:

Oh 36,000.

Craig Clark:

We added about six so that ought to be right math.

Ray Deacon:

Okay, got it. And a quick one for Dave — is there anything you could be doing to get hedge accounting on some of these hedges going forward to avoid the, you know, kind of noise in the numbers?

Dave Keyte:

Ray frankly I think we’re looking at almost going the other way, eliminating hedge accounting so we just mark to market everything to get it all in one pot. I think that, you know, the risk of hedge accounting and the associated lack of transparency around it makes it problematic for everybody including us. So hedge accounting probably isn’t worth - the flame isn’t worth the candle.

Ray Deacon:

Right.

Dave Keyte:

So I think that, you know, this particular mess in the last two quarters really was caused by the hurricane doing some strange rules that we have to follow. But to answer your question, I’m actually leaning the other way although it has not yet been decided.

Ray Deacon:

Okay, gotcha.

Dave Keyte:

And to note Ray, that - we’re not short physical. Our hedging policy prohibits that. We were not short physical in the storms. They just deemed that if you did not have that gas at that particular index point that you would come out of

hedge accounting. We obviously had plenty of physical gas to back that up on the same pipes but that’s just what they decided.

Ray Deacon:

Okay, got it. All right, thanks a lot.

Operator:

Your next question comes from John Robertson with Lehman Brothers.

Jeff Robertson:

Afternoon Craig.

Craig Clark:

Hey Jeff.

Jeff Robertson:

With your experience of owning rigs in the Permian and the efficiencies you’ve seen from that, does that make you more inclined as you look at East Texas and perhaps Canada and the other areas where you’ve got a lot of drilling inventory to want to own your own rigs to try to maximize your efficiency?

Craig Clark:

That’s an option in East Texas, probably not Canada. But in - but the answer to that would be that is an option.

Jeff Robertson:

In East Texas Craig, are those - how long do you think it will take you to catalog the different formations and do the work to identify where you do have overlap in addition to the Cotton Valley with some of these other sands that are prospective out there?

Craig Clark:

You know, it will - because of the multi-pay concept compared to Buffalo Wallow it will take you longer but you’ll certainly need to do while you’re drilling these wells some additional logging and testing. I doubt if we do the deep initially like the Lime or the Smackover.

But we ought to take some data points and there’s actually even some plans for things like Pettit and Woodbine. But it’s not blanket, don’t misread me. But I think it will take longer than Buffalo Wallow which is just a simple matter of adding the Granite Wash zones and drilling the Atoka.

But in step order we will talk about the drilling times, then we talked about the completion intervals. And currently most of the wells have the lower Cotton Valley only and not the upper. Our first task will be to commingle those and then work on the frac. So in step - but I think the commingling is a bigger issue than serendipity right now because it’s currently being done by others.

Jeff Robertson:

Okay, last question, at Buffalo Wallow is there an update to the amount of drilling locations both probable and possible that you think you have now with all of the drilling you did last year plus what you’ve seen other operators do?

Craig Clark:

The - I think the original number in Buffalo Wallow proper was 376 and that looks like a good number less what we’ve drilled. We had set some activity offset which would add to that, but that’s not based on any 20 or 40 or 80 spacing. It’s just other additional wells. And I think we’ve added some acreage in there as well but I can’t think that. But the number now, and we’ll update that at the analyst conference, is approximately 420.

Jeff Robertson:

Okay, thank you.

Operator:

Your next question comes from John Herrlin with Merrill Lynch.

John Herrlin:

Yeah hi, pretty much everything has been asked. Some quickies — you mentioned basis differentials. What are you seeing now Craig and would that inspire you to lock in more transportation or hedge more?

Craig Clark:

When we do - just as a caveat, if we do acquisition hedging or whatever we do, we do the basis with that. We do not have any naked basis trades although they probably would have been favorable and they’re not - obviously they’re not effective hedges. But that is an option. We used to do that in the Rockies when we had more gas there.

What we’ve seen is they blew out in all the areas and they’ve come back in - not in line. For example the Rockies was up to $4 and now it’s $1.80. Mid continent was up to $3 and now it’s down to $1.50 as well as Permian — still not in the historical average.

Houston Ship Channel is $1.20. That’s way, way, way out of line. And then Louisiana, depending on what point, east LA is like 30 cents and of course that’s never a differential. But I think you’d have to evaluate that.

But until they come back in line you wouldn’t want to do any basis hedging because it’s heavily dependent on when this infrastructure is going to return because people are fighting for pipes to get the gas across.

But I’m glad I don’t have my gas all in one place. In fact Canada has behaved mildly which offset some of that. But clearly they all blew out.

John Herrlin:

Right, okay next one for me is on inflation. Typically you’ve always been pretty aggressive when oil filters cost went up. You’re saying because of your concentrated approach that you can minimize some of the cost Craig. One, is that really super realistic? And what is the biggest escalation for you? Is it the frac side, the rig side, what is it?

Craig Clark:

It’s rigs and we’ve programmed I believe between a 10% and 15% increase. In fact I think we started doing that in the third quarter. And our future development costs went up a little bit which brought the DD&A up. But we tried to program that in anticipation for the cost but it’s mainly on the capital side with drilling new wells — not in my opinion on the frack or on the lease operating expense side.

John Herrlin:

Okay thanks.

Craig Clark:

Thank you.

Operator:

Your next question comes from David Tameron with Jeffries.

David Tameron:

Hi, just a quick follow-up. On the revisions and the reserves, that’s 46 Bcf. Could you give a breakdown of that?

Craig Clark:

I don’t have a breakdown. I can say that first it was mildly affected by price but offset that by higher cost. Most of that came from the onshore people. In fact it was pretty much all western and Canada. And it’s practically all on the acquisitions and those several hundred projects which are recompletions or water floods or enhancements.

That’s pretty much where those reserves are and that was a heavy focus for our folks to do field studies. But it’s not PUD booking. It’s basically from the projects we did primarily in western and primarily on the oil fields.

David Tameron:

Okay thank you.

Craig Clark:

Thank you.

Operator:

Your next question comes from Brian Kuzma with RBC.

Brian Kuzma:

Hey guys, good afternoon. A couple of quick ones — in Alaska, can you remind me again what your gas contract is good for and whether you can ...

Craig Clark:

I’m sorry Brian, I couldn’t hear you.

Brian Kuzma:

I’m sorry. Can you hear me better?

Craig Clark:

Yeah, that’s great.

Brian Kuzma:

I was wondering in Alaska, your Cook Inlet contract. How much gas can you sell if you expand your exploration?

Craig Clark:

We don’t see - the sources for fuel for the oil fields and industry as well as retail, we don’t see a limit to that. It might be somewhat equipment limited if we got it up there. But we have a ready market for it and I believe the price is $3 and $4. And they have had a pretty severe winter unlike the U.S. and they’ve actually been screaming for more gas.

Brian Kuzma:

Okay, and then out near Haley. Have all your wells been in the Vermejo area?

Craig Clark:

No they have not.

Brian Kuzma:

Okay and do you guys see competitor activity kind of branching out into maybe some of your other acreage?

Craig Clark:

Yes.

Brian Kuzma:

Okay. Can you remind me what the costs of the re-entry wells are?

Craig Clark:

A couple million apiece, $2 million to $3 million say and that includes the frac.

Brian Kuzma:

Okay.

Craig Clark:

And we run a brand new string of casing in it because some of the old casing strings were corroded and we do that for the frack. Unfortunately some of the casing strings are smaller and that’s why you don’t get some of the more dramatic rates. You can’t do as big a frack or as big a zone.

Brian Kuzma:

Okay and then final question for me is just on the cost environment, what have you guys seen in terms of rig rates in the past month versus what we were seeing in December? And then I guess a follow-up question is for the properties you guys have if gas prices continue to drop, which properties would be the first ones you guys would start pulling back activity on?

Craig Clark:

Okay in terms of cost I don’t know that there’s any more in the past month than there was last year which saw 40% to 50% increases in rig rates. They all seem to be gravitating toward the same number. I don’t think this past month was any different than any prior month. Certainly as contracts roll off they’re trying to gravitate up to that and our charge is to try and not - we’re not locking in a rate but locking services to prosecute the plan.

In terms of the frac going down, I think we’ve made it pretty clear that our capital program for an asset base this size is low so we, you know, basically maintain that rig count. What would fall out would be primarily a lot of maybe the exploration or some of the shallower stuff where they’re smaller and more sensitive to cost.

But our big programs like Buffalo Wallow, Wild River for example are firm than I think anybody would expect and they would continue on at will. In fact it might even benefit us for cost if it would actually go the other way and save us some money. But our program is pretty much hedged.

Brian Kuzma:

Okay, thank you.

Operator:

Your next question comes from Andrew O’Conor with Wells Capital Management.

Andrew O’Conor:

Any explicit uses or priorities for free cash flow to be generated by - Dave I thought I heard you say 40% to Greater Haley, Buffalo Wallow, and Wild River. Did you dissect the other 60%? Maybe I missed that.

Dave Keyte:

I did not dissect it. You know, it’s really over several fields and we’ll have that at the analyst conference. But, you know, it’s probably, you know, 15 fields are going to get a $5 million to $10 million.

Andrew O’Conor:

Okay.

Dave Keyte:

Andy that’s just because of the, you know, we want to major on the majors and having roughly 40% or half the capital on what was supposed to drive the components of what we published in the organic growth for next year gives me comfort.

Andrew O’Conor:

Okay, and then lastly, would there be a guesstimate for CAPEX at Cotton Valley assuming the transaction closes?

Craig Clark:

Well I think - yeah I think that if you take our well count of 20 and multiply it times the expected cost of maybe $1.7 million to $2 million, you can get to $35 million to $40 million.

Andrew O’Conor:

Okay, fair enough. Thanks.

Operator:

Your next question comes from Pavel Molchanov with Raymond James.

Pavel Molchanov:

Hey good afternoon. A question about your balance sheet. You know, your debt to cap is already in the low 30s. Can you just talk about what you’re aiming to achieve in that regard in 2006 and beyond?

Craig Clark:

I think in 2006 we show post acquisition, post spin-off we’ll probably be in the high 30s again. We are levering up to make the East Texas acquisition. And I think we’re pretty well traveled on our range of 30 to 40% leverage is where we’d like to see the company, 30% on a pre-acquisition basis and 40% on a post-acquisition basis. But we’d like to operate within that range.

Pavel Molchanov:

Thanks.

Operator:

Your next question comes from Gil Yang with Citigroup.

Gil Yang:

Hi, a couple of follow-ups. The half million cubic foot per day well in the Buffalo Wallow area, is that economic on a free drill basis? Or is it only economic once you’ve got the well costs sunk?

Craig Clark:

I’m not following you Gil.

Gil Yang:

Would you drill it knowing it’s going to be .5 (Bs) beforehand?

Craig Clark:

No.

Gil Yang:

Okay what would be ...

Craig Clark:

I’m confused. I don’t have any - the lowest one in the field ever.

Gil Yang:

Not (Bs), the Mcf per day.

Craig Clark:

Oh okay. That would be - unless there’s more water than we would expect that would not be what we target. We still run the economics on 1-1/2 million a day type well.

Gil Yang:

Okay would ...

Craig Clark:

I would think at this well cost that would be economic.

Gil Yang:

Okay, all right. And ...

Craig Clark:

You must be talking about one of the fringe wells that we inherited.

Gil Yang:

Oh you mean the .5 million cubic foot per day is one of the initials wells.

Craig Clark:

Yes we had several wells that in terms of the range that had yet to be completed, one or two that has yet to be hooked up. And what I think that is the wells that we just hooked up that were previously completed.

Gil Yang:

Okay so all your completed wells are higher than that.

Craig Clark:

Yeah our average is 2.4 I believe for the year although the fourth quarter was higher than that. But we hooked up completed three wells at closing and I believe that was one of the wells in the fringe areas called South Higgins or North Higgins which is in the next county up but not in Buffalo Wallow.

Gil Yang:

Okay, and can you comment on the discoveries you made offshore, you know, just what kinds of size of reserves those might have?

Craig Clark:

I’ll let Mariner do the - because they are the ‘06 numbers in their - in terms of the wells. They should be able to hone that down and also in terms of their hookup times. I’m not being coy.

I think the Grand Isle and South Tim and Ship Shoal, they’ll have to see time because that will only be a one well penetration and those reservoirs particularly the Ship Shoal which is a deep shelf well and then I’ll have - they’ll have to answer for the hookup times. But most of those will be ‘06 activity for them to enjoy.

Gil Yang:

Okay, thank you.

Craig Clark:

Thank you.

Operator:

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

Craig Clark:

Yeah, thank you. Before I conclude I want to remind you that we will be having an analyst conference in New York City the 16th of March to discuss Remainco on a go forward basis. This concludes our conference call. I want to thank everyone for their interest and participation in our call. If you have any further questions please feel free to contact us. Thank you.

Operator:

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