SM Energy Co (SM) 2005 Q4 法說會逐字稿

At this time I would like to welcome everyone to the St. Mary Land & Exploration Company year end 2005 conference call. (OPERATOR INSTRUCTIONS).

Mr. Hanley, you may begin your conference.

Good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's year end 2005 earnings 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 risk, 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 Operating Officer -- and Chief Operating Officer;

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

I will now turn the call over to Mark.

The year 2005 was highlighted by record earnings, record production and record oil and gas prices.

During 2005 we made significant progress on five large multiyear resource plays, including the excellent drilling results in the Bakken play in Montana, Elm Grove Field in North Louisiana, successful early development at the Hanging Woman Basin coalbed natural gas program, encouraging results at Centrahoma in the Arkoma Basin, where there are three potential large resource plays, and identification of a large resource play in the Atoka/Granite Wash at Northeast Mayfield in the Anadarko Basin.

In addition, we continue to see a hyper competitive acquisition market, growing rig count shortages and escalating costs.

We completed $88 million of acquisitions in 2005.

We grew our proved reserve base by 21% to 794.5 BCFE, and our pretax [TB 10] value of proved reserves grew by 66% to $2.5 billion.

Our finding and development cost for the year was $1.88 per MCFE with a 256% reserve replacement percentage.

We replaced 199% of our production when acquisitions are excluded.

Our proved, probable and possible 3P reserves were 2.5 TCFE at year end.

Our production increased 16%, primarily as a result of drilling activities and the continued extraordinary performance of our Paggi Broussard Well at the Constitution Field.

We repurchased 1.2 million shares at an average price of $24.51 per share, while we saw our stock price increase 77% for the year to $36.81 per share.

Proved reserves per share grew 20% to 11.8 MCFE per outstanding share.

Highlights for 2005 include excellent drilling results in the horizontal middle Bakken play in the Williston Basin, where we participated in the drilling and completion of 26 wells in Richland County, Montana, for approximately $34 million with a 100% success rate.

We continue to evaluate the Bakken resource in North Dakota.

Because the Bakken dolomite thins as the play moves southeast from Montana into North Dakota, we reentered ten existing well bores at approximately 40% of the cost of a new well, rather than incurring the higher drilling costs of drilling grass-roots wells, while we gained knowledge about the play.

North Dakota has produced mixed results that were marginally economic.

We have approximately 80,000 net acres in the middle Bakken Middle Bakken fairway.

Our proved and 3P reserves are 57 and 95 BCFE, respectively, with 81 identified locations to drill.

At the Elm Grove Field in North Louisiana, we participated in 36 wells, spending $7.6 million with a 97% success rate.

The play has moved into the south, where we have larger average working interest, up to as high as 37%.

We have 204 PUD locations, which will allow us to deploy capital in the field for a number of years.

We have been pleased with the performance of our Hanging Woman Basin coalbed natural gas program.

We now have 126 wells producing and dewatering, and 71 wells at various stages of completion and awaiting pipeline connection.

The field was producing 3.7 million cubic feet a day at year end, outperforming our original expectations.

Our proved reserves grew from 8.2 BCFE last year to 25.2 BCFE, and our 3P reserves have grown to 832 BCFE.

We have experienced some permitting and infrastructure delays, but overall we are pleased with the progress of this significant project.

At Centrahoma in the Arkoma Basin in Southeast Oklahoma, we are in the very early stages of applying horizontal drilling technology to develop resources in the Cromwell sand stone Woodford shale and Wapanucka limestone formations.

We control 36,000 gross acres and 20,000 net acres.

We are encouraged by initial results in each of these three plays.

At year end we had 40.7 BCFE of proved and 258.7 BCFE of 3P reserves with 27 approved and 385 potential drilling locations.

At Northeast Mayfield we believe we have a large resource play on over 24 sections in the Atoka and Granite Wash formations.

We have well penetrations in all of these sections, giving us good statistical performance data.

If wells continue to exhibit historical drainage patterns, there is potential for multiple years of infill drilling in these sections.

At year end we had 28.6 BCFE of proved and 176.5 BCFE of 3P reserves with 23 proved and 512 potential drilling locations in the play.

We have several outstanding wells in 2005, although completed in late 2004 the Apache well, where we have a 40% interest, is currently producing 45 million cubic feet equivalent per day.

And an Atoka/Granite Wash well, the Holland 1-12 where we have a 25% working interest, is currently producing roughly 22 million cubic feet a day.

The Ricks 9 Alt 1 location, where we have a 67% working interest at the Spider Field in North Louisiana, had an initial rate of 12 million cubic feet a day as a result of new completion and stimulation technology.

We have also had continued success in our Red River play in the Williston Basin, as well as in the horizontal plays in the Ark-La-Tex region, and growing activity in the greater Green River basin.

Net income for the year was $152 million, or $2.33 per diluted share, compared to 92.5 million, or $1.44 per diluted share for the prior year.

Earnings were $219.7 million, or $3.34 per share, excluding the change in net profits liability.

Net cash provided by operating activities increased 73% to $409.4 million.

Production increased 16% to 87.4 BCFE.

The average realized price increased 49% to $8.14 per MCFE.

Unit costs increased for the year as lease operating expense, including taxes, increased $0.37 to $1.64 per MCFE.

DD&A, including impairments, increased $0.30 to $1.52, and G&A expense increased $0.08 to $0.37 per MCFE.

With our realized oil and gas prices growing more rapidly than costs, our cash margin increased 56% to $6.13 per MCFE.

Net income for the quarter ended December 31 of 2005 was $51.2 million, or $0.78 per share, compared to $26.6 million or $0.42 per share in 2004.

Earnings were $73.6 million, or $1.11 per share, excluding the change in net profits liability.

Production for the quarter was 21.9 BCFE, up 10% for the same quarter last year.

To grow net asset value per share our goal is to economically replace 200% of our annual production.

We have successfully achieved this goal over time, which has allowed us to provide our shareholders a 23% compounded return as of December 31 of 2005, since going public in 1992.

Doug will now discuss our 2006 budget, as well as update you on our larger resources plays, including the Bakken, Hanging Woman, Northeast Mayfield, and the Cromwell, as well as other significant drilling activities.

Good morning.

The 2006 capital budget of $600 million, including $100 million for acquisitions, is $178 million greater than our 2005 capital program.

The drilling budget of $500 million is a $166 million increase from the prior year, reflecting both increasing costs and increasing activity.

The 2006 Rockies budget of $191 million is distributed over several key plays.

In the Hanging Woman Basin we plan to increase the well count to over 200 wells in 2006 from 131 wells in 2005, and expect to spend approximately $50 million.

In the northern Rockies 29 wells are planned in the Bakken, with total expenditures of $47 million.

Our latest Bakken wells have exhibited initial rates of approximately 350 barrels of oil per day on average as we transition from dual to single laterals. $6 million is targeted for the Red River formation.

The horizontal Madison play in the Mission Canyon [aracla] formation has a budget of $24 million.

This horizontal play has been expanding in North Dakota, and because of our dominant acreage position should provide meaningful growth opportunities in the future.

The southern Rockies budget of $35 million targets the [ten sweep] formation, and Fourbear, Murphy Dome, Big Sand Draw and [Queely Dome Fields], as well as additional development in the Wamsutta region of the Green River Basin.

The Midcontinent budget of $172 million is dominated by the Atoka development at Northeast Mayfield, and the horizontal development of the Cromwell and Woodford at Centrahoma. 46 Northeast Mayfield/Atoka wells are planned at a cost of $66 million.

We continue to see good results from our recent Atoka drilling, with initial rates typically in the range of 3 to 5 million cubic feet per day.

At Centrahoma completion techniques continue to evolve, which should help optimize initial rate and recoveries from our horizontal wells.

Our fourth horizontal Cromwell producer, the [Fair 3-5], was turned to sales last week at an initial rate of 1.3 million cubic feet per day into a high-pressure line.

The Ark-La-Tex budget shows an increase of $24 million from 2005 to a 2006 total of $66 million.

We continue to expand our horizontal efforts in the James Lime, Odessa and Pettet, where we're also successfully experiment with new completion techniques.

The Ricks Number 9 horizontal James Lime well at Spider Field benefited from an acid frac technique resulting in an initial rate of 12 million cubic feet per day.

Cotton Valley and [Halston] development has budgeted Elm Grove and Terryville.

Our most recent test at Terryville, the [Coquit] Number 1, had an initial rate of 2.4 million cubic feet per day, a substantial improvement over the average IP of 950 MCF per day in our 2004 drilling program.

The Houston budget of $71 million is dominated by expenditures in the Gulf Coast and Gulf of Mexico. $28 million is budgeted to test two prospects in the intermediate deepwater.

An additional $30 million is budgeted to test low to moderate risk, direct hydrocarbon indicator targets in the Gulf Coast and Gulf of Mexico shelf. $4 million is budgeted in the Permian for additional development in HSA and Parkway Delaware unit.

We are now injecting 6,000 barrels of water per day at the Shugart Delaware unit, where we have 73% working interest, and anticipating field-wide response after having seen successful results from a pilot water flood in 2005.

We continue to experiment with technology across all of our regions and continue to test new play concepts.

Our 2006 capital budget is nicely balanced between low-risk development drilling locations in our resourced areas, and new areas that we expect will result in a future inventory of multi-well programs.

With that I'll turn the call back over to Mark.

We enter 2006 on a positive note.

We are in excellent financial condition.

Oil and gas prices are high, and the long-term outlook is positive.

We have an outstanding inventory of prospects to be drilled with multi-year plays in the Bakken and Red River formations in the Williston Basin, Northeast Mayfield in the Anadarko Basin, Elm Grove Field in North Louisiana, Centrahoma in the Cromwell, Woodford and Wapanucka in the Arkoma Basin and at Hanging Woman Basin.

We've increased our capital expenditures budget to $600 million with substantial growth in organic activity.

Production is forecast to grow to 96 to 98 BCFE.

With that we will open it up for questions. +++ q-and-a.

(OPERATOR INSTRUCTIONS).

Larry Busnardo.

In regards to differentials, there has been a lot of talk about widening differentials in the Williston and MidContinent regions as the influx of Canadian heavy crude has been coming down.

And the Bakken production continues to rise.

Can you comment on that a little bit, how it could potentially be impacting you in terms of differentials?

Yes.

We have definitely same an impact of that.

We are facing the same thing that you're talking about.

We've seen probably the differentials in the Williston increase from about 2.50 to $5 per barrel.

And we're seeing total differential in the fourth quarter of approximately $6 per barrel, the first quarter.

$6 a barrel in the first quarter?

Right.

We have able to basically market our crude, though.

Some people have had trouble moving it; we have been able to do that as a result of our long-term relationships.

How do you see the differentials in terms of kind of this blowout that has taken place right now?

Do you think it is going to be something -- a first-half event?

Do you think it expands out, because there has also been refinery turnaround as well, so part of that demand has been taken away from it.

I think the SunCor refinery had a fire, and I want to say the production -- or the amount of crude they handle is about 60,000 barrels a day.

So that's fairly significant.

And I presume that will get corrected.

There are discussions of adding additional pipeline capacity, as well as redirecting oil direction to add capacity as well.

We think these are sort of shorter term things that a market has to sort of do as production increases; the infrastructure is sure to follow.

So we think it will be an issue probably during the next year, but we think it will be something that will be corrected as we go forward.

In regard to the Centrahoma field, can you talk a little bit about the activity for this year, number of wells?

I don't know, Doug, you may have gone over that;

I may have just missed that.

But a little bit more detail on that?

Sure, Larry.

We have two rigs running right now, and these are roughly 40-day wells, and then we have rate moves, of course.

So it turns out that we can drill about nine wells per rig per year.

So in our base case, obviously, that would give us an 18 well program.

With continued positive results, we will be adding another rig or two.

And I really don't know and can't predict the exact timing of those rig additions.

It somewhat contingent on continued results and obviously contingent on rig availability.

But 18 is kind of a base case with the two rigs we have, and I see that number growing.

And that 18 is what is essentially in our budget.

And how soon do you think -- you have got the two rigs now, at what point do you decide to an additional one?

And then do you think there's going to be difficulty in adding those?

I guess you'll continue to drill through the program and see how it goes, but how is the rig situation?

We were able to secure a second rig late last year, and that was obviously a positive.

And we have very, very good relationships with the drilling contractors in Oklahoma.

We have been operating there for decades.

So I think we have a good chance of securing a rig that can do this work.

We're getting ready to drill a few more key wells in the first and second quarters.

We're going to drill a step out in the Woodford that's about four miles from existing production.

I think success there is going to give us a lot of confidence.

Obviously, we have been watching the activity in the north of our acreage position, which continues to bolster our confidence in the Woodford.

And then ultimately it's a question of what is a prudent development plan when we have at least two, if not three, zones to develop horizontally or vertically.

And we will be working through all those details.

But I think some activity -- some results we will see in the first quarter will strongly influence and give us the encouragement to go ahead and pickup another rig.

As far as whether it's available, I think, because of our long-standing relationships we have as good a chance as anybody of getting an additional rig.

But it's hard to predict the market three months out.

In the Bakken, you talked about the production rates and how you have been drilling more of the dual laterals.

Is that going to be the plan for 2006, focus more on the dual?

And are you drilling any more single laterals?

Actually, it was kind of the reverse of that.

I probably wasn't very clear in my comments.

But we started out drilling dual laterals on a 640 basis, and we were estimating that is kind of on average at about 450 MBOE.

We have been a lot of work -- the Billings folks have done a lot of really high quality reservoir work, and economic analysis, and have determined that we think we can recover about 350 MBOE per single lateral, and we can drill two single laterals per 640, which would improve our per-section recovery from about 11% of oil in place to about 17% of oil in place.

So we're actually moving more toward drilling two single laterals per section.

And we think it's a more effective drainage pattern.

Can you just remind me of the cost?

They are running about $3.2 million completed.

And then lastly, just in regards to the deferred taxes, can you provide a little guidance on that heading into 2006?

Larry, I think that we will see that balance between current and deferred come into line a little better.

And right now we're estimating that current will be about 45% of our total tax liability for 2006.

Eric Hagan.

A question on the Hanging Woman Basin project.

All the wells you've drilled now have you been completing just in the shallow zones?

Had you completed any in the -- and co-mingled in the deeper zones?

Everything that is (multiple speakers) really is in the shallow zones.

We have a pilot in the deeper zones.

And just for everyone's recollection, we kind of break it into shallow, which is a [three coal] package.

There's an intermediate that's a three coal package, and then a deep package of three coals as well.

All of our completions today, the production, with exception of a couple of pilot tests, have been in the shallow.

We do have a deep pilot that we're testing currently.

Our 2006 program is a balance between additional development in shallow and then going back and developing the intermediate package in the existing units that we are producing the shallow from.

But it's safe to say that our current production is certainly dominated by the shallow.

We are going to do, I think, four tests of that Roberts deeper coal.

That's the most problematic one.

It has excellent gas content, but poor permeability.

And I think both in Oklahoma and Australia they have used horizontal wells to successfully get the reserve.

And so we're going to be testing that as well this year.

So you will be drilling horizontals into the formation then this year?

Correct.

And then, secondly, in the Red River play in North Dakota, can you just give a little more color on that, please, how much acreage you have in the play, and maybe some basic metrics in terms of per well performance and drilling and depletion cost?

In the Red River, we have been there since about 1991.

And it's a little different than say the Bakken play in that we do thoroughly discrete 3-D surveys kind of in the 6, 7 square mile sort of size range.

And so we don't have sort of an inventory of X number of wells that we're going to do in the future, but we have been able to replicate that success since 1991.

And as far as the number of 3-D surveys that we have planned this year, we have seven surveys planned this year, and we have about $6 million of our budget planned for that. (multiple speakers)

I thought your (multiple speakers) was in [Rona], Montana, but you have always been North Dakota, targeting that formation then?

Yes, it's in both.

And the reserves per well have kind of been 250 plus thousand barrels.

Subash Chandra.

This is (indiscernible) for Subash.

I had a couple of questions.

Not to flog a dead horse, but do you have any plans this year for the North Dakota acreage?

If you could give us an indication of what the reentries -- what kind of results you have found with the reentries in the quarter?

We also heard from some other players that average production has been somewhere in the 200 barrels per day range.

Do you have any comments on that?

We're going to focus most of our North Dakota effort in what we call the Mondak area, which is virtually right on the state line of North Dakota and Montana.

That's where most of our capital will be spent.

We've tested several reentries in the Bakken over probably about a 30 or 40 mile area, quite an extensive area, trying to understand that play a little bit better.

We have not had great results, and we've had a wide distribution of initial rates and recoveries.

In aggregate, as Mark mentioned, the program on a whole has been marginally economic, but as we've talked about in previous calls, there are two issues at least that we're finding on the North coast side.

One is we have some depletion from the shale production that has occurred.

A lot of our acreage came in the Burlington, Choctaw and Flying J acquisitions.

And many of those spacing units had Bakken shale producers on them.

So there some depletion from the shale wells.

And the second thing was the dolomite appears to be much more highly fractured, which is problematic to the extent of trying to enhance production rates by fracturing the wells.

When you talk about the North Dakota Bakken, it's not a generic play at all, so I'm sure there have been some 200 barrel a day wells in the Bakken.

But we are playing an extension of the Bakken dolomite fairway from Richland County into North Dakota.

Other people are playing a very different play.

There are some sandstone plays that are going on below the Bakken shale, and it changes pretty dramatically from where we have been focused.

So I'm sure there are some 200 barrel a day Bakken producers in parts of North Dakota, but for us the only place we have seen those type of rates on a sustained basis are in our Mondak area.

And you're drilling a second Woodford well at the time of the last operations update, plus the first at Atoka.

Do you have any early results, or is there anything did you are seeing at least in the Bakken limestone, that is encouraging?

We have TD'ed our second Woodford well, and we were able to achieve a lateral link three times that of our first Woodford well.

Our first Woodford well was about 1,500 feet of lateral, and we drilled it in an east-west direction.

The well IP'ed about 1.4 million a day, and it looks like it's going to make around a BCF.

We have increased our lateral link by a factor of three, and we have drilled the well in a north-south direction, which we think is a much more favorable orientation.

So we should have results on that well.

We have have not fraced it yet.

We should have results on that well in a few weeks.

As far as the Wapanucka tests, we have a well down, and we're just in the very, very ready stages of testing that well.

Because of some increased volumes at Centrahoma, we are having a tough time with gathering -- our gathering system capacity, and we are having a tough time getting wells tested at their full rate.

So we are not really at a point where we have enough data on that well to talk about it.

Is certainly made some gas, but we don't have a good rate on it yet.

Out of the 18 wells that you have got planned for the Centrahoma region, do you have probably a breakout between what your Woodford -- would it be more oriented towards the Woodford wells, or how have you sort of segmented that?

It is going to be more oriented toward the Woodford.

I don't have an exact count for you, but the logic is the Woodford is the deepest of the three target zones.

And by drilling Woodford wells, you get a kind of free look at the Cromwell and the [Watt].

So as we move out to the east, which is where most of our acreage is, we will drill predominately Woodford wells initially and allow us to get logs across the Cromwell and the Wapanucka, and allow us to start to develop a geologic model as we move east.

But it certainly won't be all 18 wells.

If I -- and it's going to also be dynamic through the years as we get results in.

But I would just guess probably, of the 18, about ten of those would be Woodford wells.

Do you have a cash portion for 2005 for your net profit liability plan?

Basically, how much of the liability was actually played out during the year?

It was $20.8 million.

20.8 for the whole year?

Right, and that's included in both G&A and exploration.

(indiscernible)

You gave your production numbers basically for next year 2006 about 11% growth.

Given the kind of drilling programs you have, can you say with confidence that for the rest of the decade you can grow your production by about 10 to 11%?

That's the challenge.

Our goal historically has been to replace 200% of our production.

And, kind of depending on reserve life that equates to about a 10 to 15% growth rate.

And we have been able to achieve that over the prior decade, and it is certainly our objective to continue that.

We have more multi-year plays and a better inventory that we have ever had, so we certainly are optimistic about that, but as far as guarantees, the nature of the business is that you are always looking for the next thing that nobody else has done.

In terms of the pricing now, will the gas prices [high rate] they are below $8 per MCF.

Do you think that you plan to enter into more hedges, given where the pricing is trending right now?

Or it doesn't concern you at the stage, or are you looking at prices might be getting higher?

We took action, actually, when prices were at a much higher level, primarily in October, although we did some little bit later of that as well.

But we hedged about -- on the gas side about 33% of our gas for this year.

That includes some collars which kind of -- because they vary quite a bit by quarter, but they have fairly good floor prices.

Our average sort of breakeven point -- the breakeven point of our gas hedges right now is about 12.25, I guess.

So when it’s below 12.25 we start to make money on those hedges.

And then we also, sort of in anticipation of production from the Atoka play, we hedged about two-thirds of that gas using swaps.

And again we did that in a little more favorable gas environment than we are in today, just because that would lock in superb returns on that play.

So we tried to anticipate that.

We also really did the same thing on oil, kind of at the same times.

And we have about 59% of our oil hedged.

And on the oil side, it's about $56 a barrel is where sort of that breakeven point is.

You had mentioned about the -- or you grew your results by 21% in 2005.

Does this stand evenly for both oil and gas, or is it the reserves for gas are much higher than the reserve's replacement of oil?

If you look at our total reserves, we're about 52% gas.

That is kind of a reversal from last year, but we had been about half and half for several years.

We got a little more gas in reserves primarily because of some of the things we did at Elm Grove and at Centrahoma and at Northeast Mayfield this year.

Sort of moved that needle a bit more to the gas side this year.

But we tend to look at the economics of any individual prospect based on -- we make our decisions based on economics, not whether we're looking for gas or oil.

And over the years it sort of has balanced out.

On the change in net profits planned liability, what is the number that you are looking for 2006?

Because, obviously, this is a number which is quite variable quarter to quarter.

Could you just give us some kind of a guidance on that?

We have not given a specific number, but we are very confident it will be substantially less than the number it was last year.

Last year sort of got driven up by two things.

When oil and gas prices sort of skyrocketed, two things happened is -- because the net profits pool doesn't begin to pay out employees until Saint Mary has gotten all of its money back, when those prices moved up very quickly, the payout period shrinks, so you have more years of pay out that you would have had otherwise.

And then in those years and in future years you're also getting higher prices.

So you sort of get a double whammy.

And we just don't expect that we'll see that sort of price increase this year.

And we expect that that number won't be of the same order of magnitude as it was last year.

But we don't have an exact number because it will depend on what prices are.

Jack Aydin.

A little bit of clarification on taxes.

What do you expect the tax rate for 2006 to be?

We expect the effective rate to be somewhere in that 37% range.

And then of that, I would expect about 45% of our total tax provision to be current.

The second question (multiple speakers) --.

One of the things that tended to make our current taxes higher this year is the fact that we did have that large change in net profits liability, and that is not currently deductible.

And so in a way, we have understated our total earnings on our income statement sort of of relative to taxes.

Could you elaborate a little bit -- you got an IP of 2.4.

What kind of running room do you have in Elm Grove and Terryville, one?

Two, how much that will cost?

Two, is there a possibility of down spacing on -- at what level -- acreage level are you drilling that well now was on?

Doug is going to get the exact cost numbers.

We have five sections where we have interest at Terryville.

One of those sections we have about 13% interest.

Two of the sections are over 40% interest, and two of the sections are over 60% interest.

So we think we can space that on 40s, so we think we have a lot of running room at Terryville.

And Elm Grove we actually disclose previously.

We have 204 PUDs already booked at Elm Grove, and in 3P reserves we have 247 wells.

At Terryville that well costs are 2.5 million, and at Elm Grove they are 1.7 million.

David Tameron.

Congratulations on a great quarter.

A question for you.

Just going back to the [kenny] Woodford, another large operator in Oklahoma City whose conference call this morning (multiple speakers).

Their comments when asked about the kenny Woodford was that they can't figure out what all the chest pumping is about, I think was his exact -- wait a minute, I will give you the exact quote.

He said they have been in every horizontal well in the play, and they just don't think it is economic at this point.

How would you guys respond to that from what you have seen?

Well, I think in most plays it depends on where you are at.

But I'll save this, we had a vertical well in the play that we've talked about before, talked about it for several quarters, that continues to perform extremely well.

It's going to make at least 0.6 of BCF.

So after having watched that well produce for what is coming upon a year now, I'm pretty confident that we can make a play in the Woodford just on a vertical basis.

Our first horizontal well that we've talked about, the [Ann Bay], that well only had 1,500 feet of lateral.

It was drilled in an east-west orientation, which is not the most favorable orientation.

And it's probably going to make about a BCF.

And we had a couple million dollars in the well.

We now have a well with three times that much lateral that we're getting ready to complete.

And so far our track record is everything we have done in Woodford has been economic.

We are very excited about this next well we're getting ready to test.

We have noticed some chest pumping as well from other people.

I don't try to follow that or get in and analyze whether it's real or not.

We try to stay focused on what's happening on our acreage, and we have two very economic wells, one vertical, one horizontal.

And we are very, very excited about the third.

We might also mention, on the one horizontal well that we did do the completion technique -- we used a port system, and the shale sort of expanded and clogged up the ports.

And where another operator used a cemented liner, they solved that problem.

And so we're going to be actually completing it a little bit differently.

That actually adds a little to the cost, but clearly solves that problem.

So our expectation is this next well should perform substantially better, particularly that together with the longer length.

And you mentioned earlier -- you said a well came out at 1.4 million today?

Yes, That was our first horizontal Woodford well, the Ann Bay.

And you expect to get a BCF out of that?

Yes.

And what was the cost on that?

That well we got down really quickly, and it was between 2 and 2.2.

I want to say it was right about $2 million completed.

Your role, Doug -- or Mark, I guess it is more to you.

Have you guys make any progress with finding a replacement for Doug?

Where do we stand on that?

Yes, we haven't come to the conclusion of that process, but we are very far along in that process.

I suspect in the next 30 days would be when we would probably conclude, but I can't guarantee that.

And my read is it is likely to be someone from outside of St. Mary's right now?

Yes.

Well, no, actually, that isn't a fair statement.

Maybe yes, maybe no, I can't say that.

[Havel Machelivo].

Just a question kind of more on a macro olevel.

You guys operate in multiple areas are in the country, of course.

Can you just talk about where you're seeing the most oil service cost inflation, particularly as it concerns day rates?

I think the most dramatic thing we've seen has been jack up rates in the Gulf of Mexico from 35, 50 thousand today, 12, 18 months ago to rumors of 150,000 a day.

I mean, that's pretty dramatic.

But clearly we've seen substantial increases in all of our areas.

I think our 2003 day rates in Oklahoma, 4,000 horse rig we were probably in the 8, $9,000 a day range, and we are probably in the 17 to 18,000 a day range.

So I think doubling of day rates is fairly common across most of the regions.

And the Gulf of Mexico stands out, whether you are looking at jack ups or semis, probably more on a triple or quadrupling in some cases.

But we've seen cost inflation across all the regions.

We have built that into our 2006 budget.

We have built into our economic evaluations, but it something we sure continue to watch.

[Rayon Rashid].

Just a couple of follow-up questions on Woodford, first.

I think that unnamed Oklahoma operator mentioned that 4 to 5,000 MCF is kind of what they are thinking the F&D costs will be.

But on this last lateral that we are talking about, the tripling of your first one, the horizontal well, what kind of costs are we talking about for this well?

And in terms of maybe potential reserve per well, some thoughts on that front?

It's looking like that well it's going to be probably more in the 2.5 to $3 million range, when the dust all settles.

And it's only our second data point, and I don't know if it's fair to say, if you have three times lateral you get three times the reserves.

But clearly, having a longer lateral and having more well bore exposed to formation is a positive.

I'm not going to speculate at this point on what the ultimate reserve is going to be.

I think you'll be able to make a pretty good judgment of that from the initial rate.

And after we've had at least, say, a month's worth of production, we will have a better feel for that.

But clearly, what expect a higher reserve number from a longer lateral.

This is an important well for us, and we'll just have to watch it and see what it does.

Any reason why the relationship won't be linear?

And also does most of your acreage lend itself do you think to horizontal development, or we will just have to wait and find out?

I think most of the acreage lend itself to horizontal development.

We need to get some additional penetrations further out to the East.

We now have acreage covering part or all of about three townships, and we need to get some additional penetrations out to the East.

And as far as why it wouldn't be linear, I think it's a question of effectively stimulating the entire length of the well bore.

But if it's not directly linear, it shouldn't be 0.5; it should be maybe 0.8 or 0.9.

But we'll just have to see what the well does.

But from existing technology, is there a big risk that you won't be able to frac it appropriately throughout that stem, I guess?

We don't think there's a big risk of that.

Hanging Woman Basin, real quick -- just, please, where is the production right now?

How many wells do you in PUD to be completed?

At year end, which is probably very similar now, it was 3.7 million a day.

And it tends to come on in chunks.

We have got an area called River, our expectation is that in the next month we will bring on -- I think we had 42 wells that will be coming on sort of in a whole.

Kind of awaiting pipeline and some infrastructure, but our expectation is that will -- the infrastructure will get in place and the permitting will get in place in about a month.

And so we would expect -- obviously, there's a little dewatering time, but we would expect that what sort of have a ramping effect on the production.

So the month is, what, a dewatering time or--?

No, it's really to get the facilities in place to get things turned on.

The wells have already been drilled.

So the chunks is just basically simply because of the infrastructure requirement?

Yes.

And is that kind of what you have to do, batch complete it or you can --?

Right, right.

On the deep pilot that's going on, did you mention that this is the first one?

And what would give you comfort from the signs that you have so far?

And what do you want to see from a productivity standpoint from these wells to get more comfortable with the potential that you've talked about in the kind of middle crunch?

We have tested the deep coals in a few different wells and have consistently seen water rates that underwhelmed us, frankly.

We haven't been real happy with the water rates, which are of course directly indicative of permeability.

In the current pilot we are seeing similar water rates.

So we need to change our technology, as Mark mentioned earlier.

I think this is the key to unlocking the deep coal maybe horizontal wells, or some other technology.

The shallow and the intermediate coals out here have produced in the basin, and we have a lot of analogies and a lot of history that shows what they are capable of doing.

Really, the deeps, the Roberts and the Kendricks and the [Namcos], those are coals that there hasn't been a lot of activity in, so we're kind of pioneers in those.

But we haven't seen vertical well water rates that really give us tremendous encouragement.

We're probably going to have to use a different technology.

And which ones are the intermediate coals, again?

That would be like the [Wall], the Pawnee, the Brewster Arnold.

And what you are saying is there is enough analogy that is nearby industry-wise that you feel comfortable with that set of goals?

Absolutely.

Anything different that you think you'll need or the industry uses from a completion standpoint? (technical difficulty) get inside that could or could not be an impediment, something along those lines?

I'm sorry?

Anything from a completion standpoint?

Is there anything kind of that could come in the way of continued development of the (indiscernible)?

What is the risk on the intermediate development side, whether it's infrastructure or completion, whatever it might be?

I think, again, with all the history and the intermediate coals, we feel very, very confident proceeding with that.

Is just a question at the pace at which we get the wells drilled and hooked up, really.

And you are drilling the first pilot on your acreage in this intermediate side, is that correct as well, or do we have production from there -- or wells there?

We will be infilling a lot of the units where we have completed the shallow coals.

We will be going back into those units and going onto the existing well pads and drilling and completing the intermediate coals.

It's almost like a -- it's not really an infill program, but it's just we're going back and twining almost the shallow wells for the intermediate package.

That will be a big part of our 2006 program.

Why attempt it now and not maybe a few months to get the better feel for what you intermediate stuff would look like?

Why wait this long, I guess?

Well, when you have nine coals and in three packages, you have to come up with some type of development plan that makes sense.

And what made the most sense to us was focus on the shallow initially, get those producing, get those permitted, get all the water handling facilities in place.

And then going back and drilling the intermediate wells on the same pads, using the same water infiltration ponds and so forth, it's a very, very simplified permitting process, and the infrastructure is in place.

The well pads have already been built.

That's a development plan that made a lot of sense to us.

There's a limit to how many seams you can effectively take in one well bore.

And it's impossible to, at least in our opinion, it's infeasible to try to produce the intermediates and the shallows in the same well bore.

I think we exhibited some technology to even be able to effectively produce three seams, all the shallow seams in the same well bore by using the Packard technology we've talked about.

But there's a limit really to what we can do with that.

And what made the most sense, and I think it's been a very good decision, was to focus on the shallow, get the infrastructure in place, and then go back and develop the intermediate.

Last set of questions on the same subject, economics.

Could you remind us the F&D?

And how should we think about, as this becomes a bigger component of your production, what would happen on the LOE side, quite a bit of compression?

And just in terms of realized prices, what kind of differentials should we expect on a go-forward basis?

Where does this gas, or when does this gas guess get sold -- at what point?

The F&D costs on Hanging Woman -- and this is on a 3P sort of unrisk basis, because that's kind of how we get our reserve report.

It's in the $0.60 to $0.70 per MCFE.

And so you have to understand that is sort of an unrisk number, but that's what that number is.

And LOE, just some thoughts on that?

How much is it costing you now, what would it go down to?

We will get that for you in a moment.

And that $0.60 to $0.70 F&D, if your deeper coals don't work out, how much escalation should we think about on a, and I am going to call it a 2P basis rather than 3P?

I'm not sure I can answer that off the top of my head.

I do know the Roberts is approximately 20 to 25% of our 3P reserves.

As far as the monthly LOE, per well it is about $1,100.

And that includes compression costs and everything else inclusive?

I don't think so.

We can follow up off-line.

We lose about a little over $0.50 of MCF for sort of transportation and those types of costs.

Michael Scialla.

On your 100 million that you have budgeted for acquisitions, is there anything in your production guidance for acquisitions?

It's about 2 BCF.

So you are looking for kind of high single digit organic growth for 2006?

Yes.

And then on your Paggi well, is there any more drilling to be done there, either development or any other exploratory wells that you could drill on that trend?

Sure.

We have actually approved an AFE for an East offset to the Paggi well that should be drilling by the second quarter, and we are pretty excited about that.

And then there's a Southeast offset.

We just got a new 3 seismic survey in, and studying the amplitudes in the faults and trying to make sense of it, there may be another offset to the Southeast as well.

What kind of reserves do you think you are going to see out of the Paggi well?

And remind me of what your interest in that well is.

It's a big number.

But as you can imagine, when you have a well has has been making 35 to 37 million a day for almost a year now, plus 12 to 1,500 barrels of condensate, it's a big number.

We did a lot of detailed reservoir work at year end, and it's -- well, again, when you have a well that's making a BCF a month and hasn't shown much pressure decline, you can come up with some really big numbers.

But we would probably prefer not to talk about the per well reserve.

I am a little bit uncomfortable with that.

I think you get -- if it stays online for -- at the current rate for another 12 months, it will have made over 25 BCF equivalent.

And we certainly expect it to last much longer than that.

As far as the offset wells, those are prospect by prospect basis.

I'll tell you this; the completed well costs out there -- they are not inexpensive wells.

They are $8 million wells.

So we need to be looking for something in the 10 plus BCF range for us to be comparable with it.

Does that help you at all?

Yes, absolutely.

And your interest?

40% working interest.

Shifting back to Hanging Woman just one more time, of those 3,000 wells in your 3P report, what kind of timeframe do you think you can -- if prices hold -- I guess I'm looking at what kind of bottlenecks you're facing and how long it might take you to develop that?

Are we talking 5 years or 10 years or 10 plus?

I think the goal, of course, is to continue to step up the pace.

And we're going to do something that we hope in 2006 is going to be about roughly twice of what we accomplished in 2005.

And we would like to continue to step up the pace over time.

Infrastructure has been a little slower than we had hoped in some areas, and particularly on the power side has been slower coming into play.

It's no secret that permitting is challenging.

Unfortunately, we have quite a bit of state and fee leasehold that allows us to move our rigs back and fourth while we're going through the process on the federal leasehold.

We do have some Montana acreage which is under a new EIS, which won't be completed probably until 2007.

So I think there will continue to be some permitting hurdles.

There will continue to be some infrastructure hurdles.

It is kind of the nature of the beast in this type of projects, but I think our ability to ramp up 2006 relative to 2005 is a real positive.

But we need to continue to extrapolate that into the future.

Obviously, there's a huge PV impact that we understand very clearly, a 200 well per year program versus a 3 or 400 well per year program.

So we want to move as much of that value forward as quickly as possible.

And is that 3,000 wells contemplate any horizontal wells in your deeper package, or it that assuming vertical wells?

That was assuming vertical wells.

I noticed you've amended your employment agreement here recently.

Is that just something for compliance purposes, or should we read anything into that?

You are not going anywhere soon, are you?

The thing that sort of precipitated that -- the IRS had new rules on deferred compensation, and we had to basically amend my old one for that, so we went ahead and update it.

(OPERATOR INSTRUCTIONS).

Jack Aydin.

Of crude production last year, what percentage was Williston Basin of the 16,200 barrels a day -- the number?

Hold on we will get you that.

I'll ask the following question.

Did you hedge Williston Basin or is it across the board?

We did it kind of across the board.

But oil obviously -- most of our oil in the Rockies, and a good part of our gas is elsewhere.

This will take just a second here.

I have to add a couple of numbers together.

I thought Bob was doing a good job in selling your crude, getting you better prices.

What happened to Bob?

You haven't seen what happened to the other people out there.

Bob did good.

Without Hanging Woman, we did about 37 BCFE.

37 BCFE of crude equivalent?

(multiple speakers) I'm sorry; that's total -- you just want the crude.

I'm sorry, I thought you wanted all of our production.

Just the crude from Williston Basin.

I'm sorry, I misunderstood the question.

Just North Rockies crude, that was 4.1 million barrels.

For modeling purposes, what kind of discount we should use on average for your crude?

About $5 for the year.

Did you hear that, jack?

$5 for the year?

Yes.

[Sinil Atara].

On the reserves, which was (technical difficulty) you did answer my question.

But a year ago the reserves replacement was about 11%.

Was this any unique in this year that you drilled too many wells and you had a high success rate, and that can be continued in 2006, in the future also?

I'm not sure I understood the first part of the question.

I didn't hear it as far as you said last year our reserve replacement was only 11%? (multiple speakers)

Well, if you just look at the reserves year over year per hundred thousand [frac] the increase in 2005 by over 2,000 -- in 2004 they increased by about 11%; in 2005 (multiple speakers).

Both the reserves is what you are talking about.

Okay.

Yes, we grew last year 11%, and this year we grew 21%.

This year we had several fortunate things happen.

It's hard to predict exactly, every year is always a little different.

I think, one, we actually had the Paggi well that outperformed our original reserve estimates.

And so in fact it actually produced our entire reserve estimates already that we had a year ago.

So it obviously had a positive reserve revision there.

We also had very good success in the Bakken play, at Elm Grove, and we added some undeveloped locations at Centrahoma, as well as in the Northeast Mayfield and the Atoka/Granite Wash play.

On the hedging side, are you hedging 2007 or it is pretty much 2006 only?

No, we do have hedges in 2007 as well.

It does go down as you go forward, but on the oil side we have about 41.5% hedged.

And again, a large part of that is collars.

And then on gas in 2007 we have 23%.

Our 10-K will get filed later this afternoon.

It lays out all our hedges in detail in the MD&A.

At this time there are no further questions.

Mr. Hanley, are there any closing remarks?

I just what to think everyone again for following us.

And we look forward to talking to you next quarter.

Thank you.

This concludes today's St. Mary Land & Exploration conference call.

You may now disconnect.