SM Energy Co (SM) 2005 Q3 法說會逐字稿

Good morning.

My name is Sarah and I will be your conference facilitator today.

At this time I would like welcome everyone to the St. Mary Land and Exploration third quarter earning conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks there will be a question and answer session. [OPERATOR INSTRUCTIONS] Mr. Hanley, you may begin your conference.

Thank you Sarah, and good morning to all of you joining us by phone and on line for St. Mary Land and Exploration Company's third quarter 2005 earning conference call.

Before we start I need to read the following statement.

Except for historical information, statements made during this conference call including information regarding the business of the Company may be forward-looking statements.

These statements involve known and unknown risks, which may cause the Company's actual results to differ materially from forecasted results.

These risks include such factors as uncertainties in cash flow and reserves, oil and gas operating risks, volatility of oil and natural gas prices, the need to replace reserves depleted by production, competition, and the potential impact of government regulations, litigation and environmental matters.

The Company officers on the call this morning are Mark Hellerstein, Chairman, President and Chief Executive Officer;

Doug York, Executive Vice President and Chief Operating Officer;

David Honeyfield, Vice President and Chief Financial Officer; and myself, Bob Hanley, Vice President, Investor Relations.

I will now turn the call over to Mark.

Thank you, Bob.

Good morning.

Despite the impact of hurricanes, for the fifth straight quarter we have shown a sequential production growth.

Third quarter daily production is 6% higher than the June quarter and 22% higher than September of '04 quarter.

Although we've seen cost increase somewhat, margins have increased more rapidly.

Net income for the quarter ended September 30 of '05 was $27.3 million, or $0.42 per diluted share, compared to 22.6 million, or $0.36 per share for the September quarter of 2004.

Net income includes the effect of non-cash after tax expense of 35.3 million or $0.53 per diluted share in the third quarter and 4.8 million or $0.07 per diluted share after tax in the third quarter of '04 for the change in the estimated liability for future payments under our net profits interest bonus plan.

Net cash provided by operations increased by 103% to $116.6 million.

Production increased 22% to 251 million cubic feet equivalent a day, production increased 20.1 million cubic feet a day at the Bakken Play, 21.3 million cubic feet equivalent from new wells completed in 2004 and 2005, 13.2 million cubic feet equivalent at the Constitution Field due to the Paggi Broussard Well, and 17.5 million cubic feet equivalent due to the Goldmark , Border, [Woeld] and Agate acquisitions.

Northeast Mayfield production has been growing once again and was 22.9 million cubic feet equivalent a day for the September quarter compared to 20.5 million a day for the same period last year.

Centrahoma production is up 1 million cubic feet per day, Judge Digby production is up $1.6 million a day and James Lime production has remained relatively flat compared to the prior year quarter.

The average realized price increased 55% to $8.43 per MCFE while our cash margin increased 64% to $6.36.

Included in our realized price is a net hedging loss of $0.37 per MCFE for the September, 2005 quarter, compared to a hedging loss of $0.70 per MCFE in the prior year quarter.

Production expense excluding taxes increased $0.19 to $1.07 per MCFE.

Taxes increased $0.19 also due to higher prices.

DD&A increased $0.47 to $1.60 per MCFE.

And G&A increased $0.13 to $0.42.

The DD&A rate will continue to increase as we replace low cost reserves with new reserves found or acquired in a higher cost environment.

Our estimated cash portion of tax expense is expected to be 80 to 85% for the full year due to the high level of earnings growth.

The estimated liability for the net profits interest bonus plan increased by $54.9 million due to rapidly escalating record oil and gas prices.

The Company records the liability under this plan by estimating future payments and generally using a 15% discount rate.

Price assumptions are currently formulated by applying a price to the unhedged volumes that is determined by calculating a rolling average of actual prices realized from the prior 24 months together with the adjusted NYMEX strip prices for the following 12 months.

Hedge prices are used for the percentage of forecast production that is hedged.

We have not only seen actual prices increase dramatically over the past two years but the one year NYMEX strip increased from $7.76 per MCF per MMBTU to $12.70 for gas and $59.18 per barrel to 67.09 for oil from June 30 to September 30.

A rapid escalation in price has a two fold impact.

First for pools in pay out cash flows and the resulting payments under the plan increase.

For pools which have not paid out the higher prices will cause pay out to occur earlier, resulting in additional payment periods as well.

Beginning in 2006 there will be caps on the amount that can be paid to an individual with plan years beginning in 2006.

You should note that other companies have overriding royalty income incentive plans that do not show up as a liability.

For the nine months ended September 30 of '05 we had record earnings of $100.7 million or $1.55 per share compared to 65.9 million or $1.03 per share in 2004.

Our nine-month production volumes are up 18% and our -- or 22%, I believe, and our net cash provided by operations is up 92% to $302.1 million.

Our forecasted volumes for 2005 are 87 to 85 BCF equivalent compared to 75 BCF equivalent in 2004.

We estimate that we lost .4 BCFE in the third quarter and will lose .7 BCFE in the fourth quarter as a result of hurricane damage.

Doug will now update you on our larger resource plays including the Bakken, Hanging Woman, Northeast Mayfield, Atoka Granite Wash, and Cromwell, as well as other plays in the Centrahoma area and other significant drilling activities.

Thanks Mark.

Good morning.

I'd like to review our third quarter operating highlights beginning with the Centrahoma area in Coal County Oklahoma.

We are currently drilling our first horizontal Wapanuka test in Coal County.

The Wapanuka is a thick, gas bearing limestone formation that we believe is an excellent target for horizontal development.

It will be approximately one month, perhaps slightly longer, before we have test results.

Our second rig arrived on location in Coal County this week and has spud the Fair 3-5, our fourth horizontal Cromwell test.

St. Mary holds a 100% working interest in this well.

Since the last update we have begun selling gas from two Cromwell tests, the Lanette 44 had an initial rate of 670 MCF per day and the Josh K 4-6 had initial rate of 800 MCF per day.

The Company's first horizontal wood shale producer, the Ann Bay 2-7 had an initial rate of 1.4 million cubic feet per day and is stabilized at 650 MCF per day after producing for approximately 80 days.

We plan to continue to refine our drilling and completion techniques in each of these formations in order to optimize the development of our sizeable acreage position.

Also in the Midcontinent we continue to see excellent results in the Company's Atoka and Granite Wash play at Northeast Mayfield.

As previously released, our 3 months recent completions all had initial rates of 5 million cubic feet per day or greater.

The focus area for the Atoka and Granite Wash covers 24 sections where St. Mary holds an average working interest of approximately 30%.

We now have enough well control in this 24 section area to begin to project a development plan going forward.

Initially, we expect a drilling spacing of 80 acres, with the possibility of future down spacing to 40 acres.

Current expectations call for 3 operated and 4 to 5 nonoperated drilling rigs active throughout 2006 in this play.

As Mark mentioned, net filled rate at Northeast Mayfield averaged 22.9 million cubic feet equivalent per day in the third quarter of '05, which compares to 20.5 million cubic feet equivalent per day in the third quarter of '04.

Moving to the Rockies, the Bakken play continues to be extremely active.

St. Mary participated in 5 Bakken completions in the third quarter including the Alvin 24 X 28 which IPed at 310 barrels of oil per day, the Merrill 3 C 21 H which IPed at 320 barrels of oil per day and the [Rall] 11 X 24, which had an initial rate of 240 barrels of oil per day.

The Company continues to keep 2 drilling rigs operating in the play with 1 of the rigs being shared with the conventional vertical Red River program.

Given the Company's acreage position in Richland County, it is expected to continue this 2 rig program through the end of 2006.

In North Dakota the Company continues to evaluate its sizeable acreage position by utilizing existing well bores for reentry to the Bakken dolomite.

As previously discussed we have seen mixed results from the reentries.

However, because of our lower costs associated with reentries versus grassroots wells our North Dakota program has generated positive returns.

At this point we cannot say definitively whether we believe grassroots wells can be economically extended deep into the North Dakota Bakken dolomite trend.

Our plan for North Dakota is to continue to evaluate the Bakken dolomite using reentries of over 20 remaining well bores, while modifying drilling and completion techniques in hopes of improving production rates.

Net Bakken production averaged 3,080 BOE per day in the third quarter of 2005, which compares to 2,720 BOE per day in the second quarter of 2005, and 860 BOE per day in the third quarter of 2004.

The Hanging Woman Basin CBM play in the Powder River Basin is producing in excess of 3 million cubic feet per day of gross gas and continues to exceed the forecast rate at this stage of development.

Currently there are approximately 122 wells producing, 36 wells drilled and waiting on completion, and 65 locations permitted but not yet drilled.

Planning and permitting is in various stages on over 300 additional locations.

In the ArkLaTex we continue to evaluate our leasehold position at Garrison Field in Shelby County, Texas; while we continue to develop our James Lime acreage at Spider Field in Desoto Parish, Louisiana.

Development is also continuing at a rapid pace at Elm Grove field in Bossier Parish, Louisiana.

In the Permian, we have drilled our last water injector at the Sugart Delaware unit and we are preparing to move from water flood pilot to full water flood.

We have moved drilling rig from Sugart bark to the Parkway Delaware unit, where we will continues to drill infill producers.

Company wide we continue to focus on finding new opportunities in our core areas which exhibit low hydrocarbon risk and have a components of repeatability.

With our substantial leasehold presence in the Rockies, Midcontinent, ArkLaTex, Permian, and Gulf Coast we are exposed to emerging plays and technologies which will allow us to continue our growth.

In addition to new plays, we will continue to accelerate development of existing inventory in this high price environment, while keeping a watchful eye on cost increases and the associated economics.

With that I will turn the call o back over to Mark.

Thank you, Doug.

We are pleased to reap the benefits of high prices and growing production.

Our challenge is to create value from this point forward.

We have an outstanding inventory of quality, multi-year growth plays including the Bakken, Hanging Woman, Atoka Granite Wash at Mayfield, and Centrahoma at a time of high oil and gas prices.

With a large acreage position and talented people we continue to generate new ideas, which we expect to add to our inventory of quality plays.

With that we will open it up for questions.

[OPERATOR INSTRUCTIONS] Your first question comes from the line of Ellen Hannan with Bear Stearns.

Morning Mark.

Morning Ellen.

I apologize I got on your call a little late.

I just wanted to see if I could get a little color on Doug's comments on the Bakkan play over into North Dakota .

Do you think your recent results are condemning that acreage somewhat, or can you elaborate a little bit on that?

Doug do you want to go ahead?

Absolutely.

Ellen, we talked I think on the last call about our reentries to date averaged about 125 barrels of oil per day as an initial rate.

Candidly, that's not sufficient for what it takes to drill a grassroots wells.

With cost increases single lateral wells are up to about $3.2 million, and dual lateral wells are now costing about $4.2 million.

So that type of initial rate really doesn't support a grassroots well.

Now there are some complicating factors, whether you can extrapolate the initial rate from a reentry and say that's all a grassroots well will do, not necessarily, and we talked about some of our reentries have been in sections where the Bakkan shale had previously produced and caused some depletion.

We talked about how in North Dakota the dolomite is much more highly fractured, it's more naturally fractured than it is on the Montana side.

But basically with what we've seen to date, when you move further into North Dakota it's not obvious to us that grassroots wells -- the economics are going to work given the cost.

As you get just barely into North Dakota, say just across the Montana North Dakota line, what we term as our Mondac area where we have a sizeable acreage position, there is a well that was, we don't operate, but it's immediately adjacent to our acreage, we actually have an interest in it ,but it is just now flowing back and it is a grassroots well.

I think that's probably going to support grassroots development in and around Mondac, but as you move further into North Dakota I think the reentry program -- we need to see some better results from our reentries before we go out and start drilling grass roots wells.

Thanks very much.

Your next question comes from the line of Brian [Kuzman] with RBC.

Hey guy how is it going?

Morning.

Quick question on the Woodford shale well.

Results on that well are not as good as Neufield was reporting.

Is that a geology/location issue, or is that a completion issue or how do you guys feel about your acreage?

We think we have a great acreage position.

We've always felt like we had one of the best positions in Coal County in the Arkoma Basin for the Woodford.

It's really, in our opinion, a completion issue or at least that's our initial thinking.

And one thing I can comment on, weve looked at some of the daily rates on those wells and certainly they have higher initial rates.

I think they have a little bit steeper decline profile in our opinion, so as far as the ultimate recovery I'm not sure they will be that dramatically different.

Time will tell but we have -- we used our, the same completion technique on this first shale well that we used on our Cromwell sand stone wells and we think there's a better way to do it.

Candidly, some of the competition to the north has -- they're using cemented liners and we are certainly not above the borrowing some of that technology and doing things slightly different if we think it will improve our production rates.

We plan to that on our next shale well.

Also our first Woodford well we drilled it in an east-west orientation and as we learn more about the fracture systems in the area we probably should have drilled that on a north-south orientation.

So those are two changes we will make, but we are very excited about our acreage position.

We have, as we've talked about on previous calls, we have vertical wells that are economic for our acreage position.

We think we just need to tweak some of our completion techniques.

One of the things we felt was very encouraging about the Neufield announcement was that the wells they drilled appeared to be off structure and that was one of the our concerns was whether the play would move off structure.

That significantly increases the scope of the play that we see on our acreage.

So that was actually very encouraging news from our point of view.

Another question, in regards to the hedge program, can you guys add a little color as to, I mean obviously you guys think that prices have, prices are high.

But you are one of the first companies to actually go out there and implement a hedging program without any type of strategic acquisition or anything like that.

Right.

It was a little unusual for ourselves.

Historically we've always hedged our acquisitions and that's been the bulk of our hedging activity.

We did -- we were authorized by the board historically to do up to 15% of additional hedges when we felt it was opportunistic, but that usually was a fairly small percentage.

We felt like these were very attractive periods and we felt like, one, we wanted to lock in some minimum level of price so we went ahead and did collars instead of swaps so we have some very high ceiling prices.

The gas in particular was asymmetric, and I don't have the exact numbers in front of me, but just for example purposes, not meant to be exact numbers, but if you lowered the price $1 for the floor you can maybe increase the ceiling by $2.

So that we like that asymmetrical portion of it as well.

We feel like we've retained a great deal of upside while protecting the down side there.

Would you see further hedging in the future if prices stayed high or went higher.

We haven't decided that yet, but I wouldn't real rule that out either.

Thank you.

That's all.

Your next question comes from the line of Phillip Dodge with Stanford Group.

Good morning everybody.

Could you give us an idea of when you might be able to -- when you plan to announce your 2006 capital budget and give us a preliminary idea of how much of that would have to include cost inflation for 2006 versus 2005?

We normally do that release in January together with our forecast, which is after we get our engineering done.

So it's usually towards the end of January.

Just based on this year, this year we don't have exact numbers from every region, but we are thinking completed well cost in 2005 compared to a year ago is probably up about 25%.

We are continuing to see some price increases.

At this point I'm not sure I'm ready to speculate on what it will be in 2006, but this year it's about 25%, the prior year was 20%.

And when we get our group together with our budgets we will speculate a little on what it will be, but I don't have that number right now.

Fair enough.

And then Centrahoma could you just go through again how much acreage you have covering the Cromwell, Woodford and the Wapanuka respectively.

We have 36,000 gross acres and over 20,000 net acres and we are adding to that position every day.

We will be growing that and have been growing that.

The Cromwell is present under about -- I am going to talk about gross acres for the time being -- but the Cromwell is present under approximately 25,000 of the 36,000 gross acres.

It pitches out to the south and there is -- you do get to a zero line as you move south.

The Wapanuka is present under essentially under that entire position, and we have data points and production from wells that suggest it's gas saturated over that entire position.

The Woodford shale covers counties.

I mean it's huge in expanse, and as Mark mentioned, the big question for us has always been whether the Woodford would produce off structure and we had focused our initial efforts, our vertical well efforts and our first horizontal well on structure where we would be exposed to more fracturing and perhaps a little -- maybe some sand stones or silt stones that were interbedded.

So Mark mentioned, I think its great news that the Woodford has now been extended two townships to the north of our position and it's certainly present under our entire acreage position.

So the Woodford and the Wanapaka are present under the entire position.

The Cromwell is present under about 25,000 of the 36,000 acres.

Then perhaps given rig availability limitations how would you plan to allocate your priorities among the three zones?

It's a great question and Mark and I were actually in the Tulsa office yesterday and talking through that.

Every new well of course gives us a new data point and there are scenarios that are -- one extreme scenario would be you drill 4 horizontal wells for each formation in each section.

So you might have 12 horizontal wells per section in an extreme case.

We may drill a horizontal well to the Woodford, which is the deepest horizon and then complete the Wanapaka and Cromwell in the vertical portion of the hole.

Depending on the rate and reserve multiples we get from horizontal wells and looking at the associated cost increase, it may say just go drill your entire position on vertical wells on 40 or 20 acre spacing and comingle all three zones.

We are -- that's a great question and we sure don't have it figured out but it's a good problem to have.

Anyway, it sounds like it's going to last for quite awhile.

Absolutely.

Thanks very much.

[OPERATOR INSTRUCTIONS].

Your next question comes from the line of [Senil Daktar] with [Bremel] Capital Management.

Hi.

You mentioned about some mixed results in North Dakota, is this going to affect your production plans in 2006, can you give some color on that?

We really didn't have or haven't had any proved reserves booked in North Dakota, and as a result none of that has been rolling into our production base or product forecast.

We've always known that North Dakota was a little more speculative.

We talked early on about the fact that the Bakken dolomite thins as you move to the south and east, and how the fairway narrows as well.

So we've always known that area was a little more speculative, and with two rigs running in Richland County at least through the end of '06, possibly now well into '07 we don't see any real production impact.

And one more question in terms of the cost inflation that you are seeing.

In what particular areas are you seeing the most cost increases?

Is it in terms of the rigs or in terms of services or how would you define that?

Rigs in the last couple of months -- for some time now they've been escalating but it's amazing what's happened.

It just seems in the last three or four months.

I was looking at some data yesterday.

In the Midcontinent, for example, we were getting 1,000 horsepower drilling rigs for $7,000 a day in early '03 and the latest rig we contracted -- the latest 1,000 horse rig we contracted for 18,000 a day.

And it seems like the shape of the curve isn't favorable to operators, it's more favorable to the drilling contractors presently because that jump from 7 to 12 or 13 was pretty gradual and that jump from 13 to 18 has happened in a compressed time frame.

We are seeing cost inflation all over.

Not just drilling rigs.

It's services as well.

I don't know that one area or basin is particularly more hard hit than others.

Certainly the Gulf of Mexico jackup market has gotten out of control after Katrina and Rita, but we are seeing cost inflation company wide.

Okay.

Thanks.

Your next question comes from the line of Rahan Rashid with FBR.

Morning guys.

One broader question with so many plays that are multi year plays, would it not make sense, Mark, that maybe like some other operator have talked about seeing if you can go get some rigs from China or something like that and lock in your cost that way?

And then I have a couple of follow up questions.

I mean we are not ruling out anything.

It's something we have a planning meeting coming up in about a month and we are going to talk about different alternatives.

We certainly like seeing the Chinese rigs coming into the U.S. because it does increase the total supply.

And we also like to see some other companies building their new rigs because that also increases the supply.

Whether we actually want to own rigs or not -- at this point in time we are not inclined to do that but I think we have to be open to a discussion of that type of thing.

So I think the fortunate thing on the Hanging Woman play, that's an area where rigs have not really been -- is not really the bottleneck there.

We can probably add rigs there.

So that's one play that is not as restricted.

There is other restrictions on permitting and people and type of thing, but that one really isn't as impacted by the rig situation.

We did just pick up another rig in the Centrahoma area, so we went from one rig to two rigs there.

And is that rig under a long-term contract where you can just kind of --

For the areas we've been in pretty much in Oklahoma and the Rockies we have not had to enter into long-term contracts, just our long-term relationships have allowed us to keep the rigs.

So that's been a favorable position.

Usually also when you even if you have a long-term contract a lot of times you still go with the current rate so you are not necessarily locking in the current rates, or if you try to lock in a fixed price those prices are substantially higher than the current price because the drilling contractors obviously are building in price increase, too.

So when we've looked at that and we've also looked back on whether it would have been smart to lock in rates generally that usually it hasn't made sense to lock in the rates for a long term time.

My concern was just on the availability side, pricing obviously drillers won't give up anything too.

And as Doug mentioned in our Atoka play we had a rig that we had released during a window period that we are just getting that back.

So we are actually increasing in the Atoka Granite Wash Mayfield area from two to three rigs that we operate now.

Going back to the Centrahoma and all these fields here, would it -- how tight are the economics?

I mean, can we afford rig rates and service costs to go up another 20% next year and probably go up the same number the year after and if something like that happens do the economics come in question?

And second, would it be fair to say that -- as we know we don't no yet exactly how the field is going to get developed, how the program is going to shape up, but will you need another 6 months, 12 months to figure out how the Centrahoma, the Woodford and Cromwell all need to get developed?

Would that be a good time frame to keep in mind?

It will take us a while to understand what an average well does in each of these plays.

I think Hanging Woman, that appears to be economic at much lower price decks, much lower finding cost type area, Centrahoma, we need to see what the average wells do.

We are just sort of beginning there and I think if the wells average 1.5 Bs then they can clearly withstand some price -- I mean some cost increase.

If they average 1 B it starts to get a little tighter and a lot depends also on what the oil and gas prices are.

If you use the current strip pricing there's a lot of room to go.

If you use the $7 gas price then it kind of depends on what the productivity of the wells are.

In the Atoka play just looking at the average reserves per well in the 24 sections historically is kind of in the about the 1.3 to 1.4 BCF per well.

And using a $7 NYMEX right now that is giving a range of 27 to 44% rate of return.

With a higher price deck that currently exists, obviously that's a much higher rate of return, but those are very, very good rates of return where they are right now.

There's a bit of room there to go.

Fair enough.

Part of the question was how long does it take for us to get a good feel for this is how the Woodford and the Cromwell will get developed, maybe another 6 months?

We are kind of thinking probably having ten wells in each of them would probably give us a pretty good pattern.

We think a few wells just isn't enough and we are continuing to experiment also as we are learning at the beginning here.

And 10 wells is another what, 3 months, another 6 months?

I would say probably the 6 months\ makes more sense.

I think in total we probably expect to drill ten wells per rig per year.

And so if we're at 2 rigs that would be 20 for the year, but that's in different formations, so it wouldn't necessarily be 20 in Cromwell, it would be spread out among the 3.

Just on the economic side there's an extraordinary amount of compression that would need to be put in or that would add to the costs and then as commodity prices pull back a little bit and put thing in jeopardy, is there anything extra that will go into these wells in development here then we need to be careful or think about as it evolves or -- ?

One of the advantages we have at Centrahoma is we own the gathering system.

We purchase the producing properties from another operator in 2002 and with that we took ownership of an 89 mile gathering system which is a low pressure system.

So that's a big advantage for us.

That's not to say we won't, on occasion, need to do -- set some well site compression, or clearly there will be system expansion that goes on, but we have a built in advantage with owning that gathering system.

Fair enough.

Hanging Woman Basin, 300 permit [indiscernible] locations under permitting and planning, that carries you through next year and beyond that the total development plan is much north of that in terms of number of wells.

What issues would we see or should we expect from environmental/permitting/infrastructure standpoint, any thoughts on that front?

We are focused on the Wyoming side.

I think Wyoming side.

I think a lot of people are aware that in Montana there was a ruling by the 9th circuit appeals court that a supplemental EIS has to be completed to cover phase development before any new permits are going to be issued.

And so that would probably put a couple year delay on the Montana side.

About 70% of our 3 P reserves are on the Wyoming side.

So we do have plenty to do during that 2 year period.

I think it's, I think our industry in terms of people is very tight and so I think being able to accelerate a project is very people dependent and also permitting dependent.

We've been able to get permits on the Wyoming side.

You have to go through a process, but we haven't experienced any big bottlenecks or hurdles there.

It's been sort of the normal process.

Okay.

Thank you.

Your next question comes from the line of David [Miazaki] With A.G. Edwards.

Good morning.

Just a quick question on your net profits plan.

Does the liability change that we are seeing this year, is that driven principally by the changes in the price assumptions?

Right.

Exactly.

If you think about it the participants don't get anything until St. Mary gets all of its money back.

So when prices go up two things happen.

If a pool already is paid out, obviously, if the price deck increases as it has you are going to see a much larger amount just because of higher price on that cash flow.

In addition what happens is when prices go up that pay out period gets much shorter and so if, just for an example, if a pool was originally scheduled to pay out say in 2008 and the high prices now make it look like it's going to pay out in 2006 that adds 2 additional years as well as higher prices that you wouldn't have had before so you get kind of a double whammy when prices shoot up as they have.

So looking forward if we assume that prices next year don't escalate the way they did in '05 versus '04 then your expense should be lower.

Exactly.

Okay.

Then looking at last year's liability at the end of the year I think it was around $30 million, how much of that actually gets paid out -- what percentage of that liability got paid out in '05?

Let me give you that.

Again, this year obviously is much higher.

This year we expect on the cash side it will be about a little over $20 million.

Okay.

Then did you say that you were going to amend the program for '06?

Beginning with the pools, the 2006 pool and the future pools there will be a cap on individual payouts.

So once a person gets a certain multiple of their salary, then payments would stop.

Do you expect that to materially change the cash flow payment being distributed off the pools then?

The prior pools aren't really affected so as those wind down the answer would be yes, I think initially you probably won't see a big impact of that.

It's more down the road.

Okay.

Thanks a lot.

Your next question comes from the line of Michael Scialla with A.G. Edwards.

Good morning.

You said in the past that you expect about 450,000 barrels per well in Richland County.

I was wondering if you could give us a sense of what that represents in terms of the oil in place or if you can give us a recovery factor and if you see any potential there for any kind of secondary recovery?

Our volume metrics that we calculate when we look at recovery of oil in place and this 450 MBOE ties to about, its between 10and 11%, to be real exact it's about 10.7% recovery of the oil in place.

I know there are other companies that think the primary recovery will be higher than that.

Certainly people are talking about secondary recovery.

As far as I know there are no efforts underway and I really -- I personally don't have a great feel for whether you would be unitizing this entire area.

For example, some people consider Richland County to be one giant continuous oil field in the Bakken dolomite, and there's probably no reason to believe that it's not.

But whether you can unitize that in smaller segments or whether you unitize the thing almost county wide I don't know the answer.

And as far as I know that's not under way, but assuming it is one big continuous oil field and it's one of the biggest oil fields that's been discovered in the Rockies in several years, one would think that it would lends itself to some secondary efforts.

Now having said that I would also say the Bakken dolomite, the permeability is pretty low, so it may not be a conventional water flood like we think about when we think of secondary recovery.

It's kind of a long winded answer, Mike, but the recovery factor is an easy one, that's 10.7%.

As far as where the secondary goes, it's not real clear right now but there's a lot of oil in place and one would think there would be efforts to increase that.

I might add that one thing that were we are looking at, there are two methods for completing the wells.

There were single laterals with a cemented liner and than we had dual laterals, and in looking -- having had quite a bit of history now it appears that maybe the single laterals might do a better job of recovering the oil and getting maybe better frag placement and there is a possibility of maybe going back in the dual laterals in between them and essentially drilling an infill well and we are looking into that as a possibility.

So that could potentially continue activity even before a secondary recovery.

Okay.

Then on your Hanging Woman play, of the 122 wells you've completed there now, can you give us some kind of sense of how many of those are in the shallow, intermediate, and deep coals?

Almost all of the wells -- almost all of the 122 wells, and when I say almost all, I think there's probably 8 or 10 that are in the deep and all of the balance are all in the shallow of the Anderson Canyon cook.

As we move to the south and the river area we are moving into more of that intermediate, the Wall and the Pawnee, so there are some wells we've drilled intermediate that are not producing yet.

All of the producers are, with the exception of about 8 or 10 wells are in the shallow, the Anderson Canyon cook.

One thing just some further comments, which also addresses part of the question earlier about permitting.

Of those 300 or so wells that we're in the process of beginning to permit, about 100 of those are simply infill wells and the existing pods that we've already drilled to the shallow, basically going on same locations and adding an intermediate well.

So about 100 or so wells would be just essentially going in and twinning the shallow wells except taking it down deeper to the intermediate.

That would be a big chunk of our '06 program.

So I would assume permits for those might a little bit easier to get.

It should be a lot easier.

The critical path would be the Wyoming DQ and water discharge but as far as the surface permits it should be relatively painless.

So if you can get -- it looks like I guess bottom line is you have pretty good chance to ramp activity in '06 versus '05 there?

Yeah, we sure want to go through our budgeting and our planning at year end before we commit to a number of wells.

But I think I'm comfortable saying that there is no reason to believe we wouldn't at least repeat the number of wells we drilled in '05 and there is reason to believe we might do something greater than that.

But we need to kind of get our plans all laid out before we commit.

Then on the current rate did you say you were doing 3 million a day roughly right now.

Right.

Would you care to venture a guess at what you might exit the year at?

I don't have -- I really don't have a good guess on that.

I should be able just to connect the dots and take the incline and run it out to the end of December, but I honestly haven't done that.

Okay.

And then just one final question on the Northeast Mayfield, with that many rigs running -- I think you said you plan on 7 with nonoperated rigs included, does it look like you could -- would you expect to be back ramping production in '06 from the 22.5 million a day that you are at right now?

I would sure like to believe that.

And with the -- and it's going to depend on the quality of wells we are making.

We are on, we are having a great run right now.

I think we pointed out the Holland well, which we have 25% of that came on over 14 million a day.

It's wells like that just have a tremendous impact.

But certainly we will take as many of the 5 to 6 to 8 million a day wells as we can get as well.

If we continue -- they are not all going to be that way, but if he we continue on average making wells, on average in the 4 to 5 million a day gross range net to us that should certainly ramp up our -- that should grow production in '06.

One final follow up on Northeast Mayfield.

What do you see as a split between Atoka and Granite Wash at this point as far as the drilling?

What we are doing, Mike, is commingleing them in the same well bore.

And that's a little bit of a change that's really happened just in the last 5 or 6 months.

We were just drilling purely Atoka wells and the last 3 or 4 we've operated we've had some nice Granite Wash development and we've been able to comingle the Granite Wash with the Atoka.

So as far as the reserves we think are going to be dominated by the Atoka, but the Granite Wash sure is a nice addition for very, very little incremental dollars.

Great.

Thank you.

Your next question comes from the line of Brent Collins with Petrie Parkman.

Good morning everyone.

Morning.

Wanted to see if you could comment a little bit on the Permian program.

Do you have anything -- I know you have the water floods, do you have any other programs or exploration potential there?

That's really been our focus, Brent.

We had such great results at Parkway and we took that fill from about 300 barrels a day to about 1700 barrels per day.

And Shugart is a look alike, same interval, same flood properties, same reservoir quality.

And its just a township or so away.

So we would like to think we could see some similar results at Shugart.

That's been our focus.

But we have not been active explorers.

We haven't chased the [Morrow] or [Strahn] using 3 D. We haven't really -- we've been a little more focused on exploiting our existing property base than we have on exploration.

We have participated in several attempts to acquire additional producing properties in the Permian in the last couple of years, but haven't been successful.

That's all I had.

Thank you.

[OPERATOR INSTRUCTIONS].

Your next question come from the line of [Senil Daktar] with [Bremel] Capital.

Just on the hedging program, do you think that you are going to unwind your hedging program at some point in time given the high prices for gas or are you going to continue with that?

There's no plans to unwind the existing hedges.

Okay.

Thank you.

[OPERATOR INSTRUCTIONS].

At this time there are no further questions.

Again, thank you very much for attending the call and we will talk to you next quarter.

This concludes today's conference call.

You may now disconnect.