SM Energy Co (SM) 2004 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 to welcome everyone to the St. Mary Land & Exploration third-quarter earnings call.

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

After the speakers' remarks there will be a question-and-answer period. (OPERATOR INSTRUCTIONS).

Thank you.

Mr. Bob Hanley, you may begin your conference.

Thank you, Sarah, and good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's third-quarter 2004 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 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 online this morning are Mark Hellerstein, Chairman, President and Chief Executive Officer;

Doug York, Executive Vice President and Chief Operating Officer;

Dave Honeyfield, Vice President of Finance; and myself, Bob Hanley, Vice President Investor Relations.

I'll now turn the call over to Mark.

Good morning.

After fighting production declines over the past few periods we're pleased to see a 5% increase in production over the June 2004 quarter.

We achieved this entirely through the drill bit.

Our production is down a modest 1% from the third quarter of last year, but because of our stock repurchases, production is up 6% per weighted share outstanding.

We believe we should continue to grow production in the fourth quarter and beyond as a result of both our drilling activity and production from announced acquisitions.

In addition we are continuing to advance development at our CBM projects at Hanging Woman and Atlantic Rim.

Net income for the quarter ended September 30, 2004 was $22.6 million or $0.71 per diluted share compared to $13.8 million or $0.41 per share last year.

Results reflect a 7 % decline in diluted weighted shares outstanding from 35.828 million shares to 33.186 million, as a result of the acquisition of the 3.38 million shares acquired from Flying J in early February, partially offset by shares issued on option exercises.

We also repurchased 489,300 shares at an average cost of $33.39 during this September quarter.

Discretionary cash flow increased by $19.7 million to 71.5 million.

Production decreased 1% to 19.0 Bcf equivalent.

Production at Judge Digby declined 0.4 Bcf to 0.8 Bcf, but has outperformed engineering estimates.

Northeast Mayfield declined 0.4 Bcf equivalents to 1.9 Bcf equivalent due to the flush production last year and the few new wells so far this year.

We have a fairly large backlog of wells in the completion phase and expect the fields production to begin increasing once again.

Offsetting these production climbs (ph) were increases in production of 0.5 Bcf equivalent at Bakken play, 0.2 Bcf equivalent at Vermillion 273, 0.3 Bcf equivalents at Spider, and 0.3 Bcf equivalent at the Hyers Field.

The average realized price increased 21% to $5.43 per Mcfs equivalent.

Unit costs increased modestly as production expense, including taxes, increased $0.02 to $1.27 per Mcfs equivalent.

LOE actually decreased $0.6 per Mcfe, while taxes increased $0.08.

DD&A increased $0.05 to $1.13 per Mcfe, and G&A expense remained flat at $0.29.

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.

Last quarter we began to show separately the non-cash adjustment associated with estimating the value of future payments derived from future net revenues associated with the net profits interest incentive plan.

Such adjustment increased by 6.8 million to 7.5 million for the quarter due to rising product prices and a lower discount rate.

We recently announced the signing of agreements to acquire for cash a total of $97.5 million of oil and gas properties in three separate transactions, with proven reserves totaling 69.6 Bcf equivalent and probable reserves of 28.4 Bcf equivalent.

Doug will describe each of these acquisitions in more detailed as well as our drilling results for the third quarter.

Thanks, Mark.

Good morning.

I'd like to update you on several of our key projects, beginning with Northeast Mayfield in western Oklahoma where we have three operated drilling rigs and are participating in nine nonoperated drilling wells.

In addition we eight wells currently being tested or completing.

I will go into a bit more detail than usual at Northeast Mayfield.

In the westernmost area of our leasehold position, the St. Mary operated Dobson Ranch # 1 had an initial rate of 7 MMcf per day from two commingled Upper Morrow zones.

The Lonsdale # 1 and the section immediately to the South has logged similar pay in the Morrow.

BP is preparing to spot a Morrow test in the section immediately west of the Dobson Ranch.

And Chesapeake is approaching TD in this section of the southeast.

All of these wells are the first wells in their respective sections.

St. Mary's interest in these wells ranges from 11% to 38%.

We are encouraged by the early results in the Morrow on our western leasehold.

Also in the western portion of the field, the St. Mary operated Juanita #1 in the section north of the Dobson Ranch, IP'd at 3 MMcf per day from the Atoka.

To the northeast of the Juanita, the Apache-operated Davis 120 IP'd at 4 MMcf per day from the Atoka.

In the northern portion of our leasehold the sites 1-8 and Judith 1-7 resulted in disappointing Atoka tests.

In aggregate we've seen mixed results from the Atoka with the recent wells to the west providing encouragement.

The southern tier of our Northeast Mayfield acreage is currently being tested by multiple wells operated by both St. Mary and Chesapeake with results expected from the initial test in early '05.

Elsewhere in the Mid-Continent, the Radtke #1 and Radtke #2 are producing at a combined rate of 17 MMcf.

St. Mary holds a 40% working interest in these wells.

A third well is likely in the first quarter of '05.

In the Constitution Field in Jefferson County, Texas, the Padgee (ph) gashing (ph) at # 3 recently logged 40 feet of net pay in the Venus and Westberry sands and is currently awaiting completion.

The Padgee Brousard # 1 is flowing at sales at a rate of 15.3 MMcf per day and 690 barrels of condensate per day from the harder sand.

St. Mary's working interest is 40% in both of these wells.

Approximately two-thirds of the value of the previously-announced Agate acquisition is in the Arkoma Basin of the Mid-Continent.

This acquisition will vastly expand our presence in Pittsburgh County, Oklahoma, and includes a 36-section contiguous acreage position where we have identified over 60 horizontal (indiscernible) co-location.

Moving to the ArkLaTex.

Activity continues in both the Horizontal James Lime play and the Horizontal Pettit play.

The Company's most recent James Lime well at Spider is being tested at 3.6 MMcf per day.

Four additional locations remain at Spider.

The net field rate at Huxley averaged 8.88 MMcf per day during the month of September.

One location remains at Huxley and should spud in December.

Our first well in the Pettit formation at Driscoll Field, the Weyerhauser # 1 where we have a 95% working interest had an initial rate of 3 MMcf.

The second well at Driscoll is currently drilling.

Three additional wells are planned at Driscoll.

In Russ County, Texas, the Richey (ph) # 1, a horizontal Pettit test, is flowing 400 barrels of oil per day and 700 MMcf gas per day.

St. Mary holds a 50% working interest in the Richey, and has identified two additional locations.

Due diligence continues on the acquisition of the Nemores (ph) assets, which are located primarily in the Elm Grove field of North Louisiana.

There are eight rigs running in Elm Grove, with four of the rigs working in sections where we will be acquiring a working interest.

The gross field rate at Elm Grove is approximately 160 MMcf and it continues to be one of the most active fields in the ArkLaTex area.

While we are acquiring a nonoperated interest, the property is extremely high-quality and the expectation is that we'll be able to increase our presence over time.

In the Permian, we are preparing to spud the first of four additional infield wells at Parkway Delaware Unit where the gross field billed rate is approximately 1800 barrels of oil per day.

The rig will then move to Shugart Delaware Unit to drill four injectors.

In the Gulf Coast, the Dana Bradley # 1, also known as the Astor Prospect, is online and producing 3 MMcf.

The JB Farms (ph) #1, formerly known as the Mermentau Prospect, and the State 37-A1, the Tortuga Prospect, are apparent discoveries and are awaiting completion.

Offshore the remaining 273 B3 where we have a 50% working interest is producing 14 MMcf.

At each East Camera (ph) 56 field where we have a 30% working interest, the JB 5 has been completed and is producing 3.5 million a day and 340 barrels of condensate per day.

The JA9 is currently completing.

Fundington (ph) Resources has indicated that they have identified at least three prospects in the companies fee lands as a result of the recent 3-D seismic shoot, two of which they hope to drill in the first quarter of '05.

We are purchasing the reprocessed data over the Company's 25,000-acre fee land position, and will make a participation election after reviewing the prospects.

In the Rockies we continue to be very active in the Bakken play, with two drilling rigs and two re-entry rigs running.

The dual lateral wells continue to exhibit initial rates in the 350 to 600 barrels of oil per day range.

The re-entry program has allowed new areas to be tested at a reduced cost.

One of the reentry rigs is currently drilling a single lateral from an existing while in North Dakota.

A success in this well would open up additional acreage for Bakken development.

In southwest Wyoming 14 wells have been put to sell and 12 wells have spud since the end of the second quarter.

The wells are predominantly nonoperated and have an average working interest of 24%.

At Atlantic Rim, the company has an average working interest of 10% in five CVM development areas. 24 wells were drilled in the Doty Mountain CVM unit since the end of the second quarter.

Four additional CVM development areas are planned at Atlantic Rim, including a Sun Dog (ph) area where the average well rate of the first 10 wells has exceeded 320 MMcf per day.

Our participation in essentially all the southwest Wyoming projects is the result of the acreage position acquired in the Flying J transaction.

44 wells have been drilled at our Hanging Woman Basin CBM project since initiating our 2004 drilling program in June.

We anticipate having 69 wells drilled by year-end.

Nineteen original stand-alone Anderson Cole wells were combined with deeper zones, using multi-seam completions to provide operational enhancement and cost savings.

Sixteen wells have been deferred to 2005 pending additional wildlife studies.

Seventeen wells should be producing by the end of next week.

The previously-announced acquisition of Goldmark closed on Monday of this week.

They key asset in the acquisition is the operated Four Bear Field in the Big Horn Basin where we expect to improve production performance through workovers, infield drilling, waterflood optimization, and improved recovery techniques targeting the remaining resource of 200 million barrels of oil in place.

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

We are pleased with the progress we've made this quarter.

Production is up sequentially, we have had several significant discoveries, including Vermillion 273 B3 for 14 MMcf, Padgee Broussard for 15 MMcf and 690 barrels of oil per day from the lower zone only, and the two Radtke wells for 17 MMcf.

The Bakken play continues to perform well and we plan to drill several wells this quarter in an attempt to extend the play to North Dakota.

We have drilled 44 wells at our Hanging Woman Basin coalbed methane project, and expect the pipeline to be completed on schedule.

We have signed or closed agreements for almost $100 million of acquisitions.

We are enjoying record product prices and record cash flow.

Our future is bright.

We have a large inventory of prospects, including development of the Bakken and Northeast Mayfield fields.

We believe Hanging Woman will become a major growth asset for the company.

With that, we'll open up for questions.

(OPERATOR INSTRUCTIONS).

Larry Busnardo, Petrie Parkman.

On the Hanging Woman play, in the release you talk about less capital expenditures in the fourth quarter.

Is that related to the deferral because of the environmental studies or the wildlife studies?

Larry, it's really twofold.

That's certainly part of it.

And then the other part of it is our ability to complete these wells using multi-seam completion.

Over 20 of these wells will be completing multiple zones and essentially save over 20 wellbores having to be drilled.

It's twofold; it's the cost-saving from multi-seam and the deferral of 16 wells.

Is the plan -- I know you said previously that the plan was to drill somewhere around 175 to 200 wells next year, does that then come down because of that?

No, we are still looking at a 200-well program for next year.

That's still the plan.

We will still be using multi-seams, but have four areas -- we've actually grown or acreage position over time since we originally talked about the 175 to 200.

We are still on tap for 200 wells.

And then shifting to the Atlantic Rim CBM program.

I'm looking for a little bit more information there.

Did you say a 10 percent working interest that you have?

And also, could you give us acreage position, how many wells planned for fourth quarter and then kind of what the '05 activity is going to shape up to be?

I'm probably not going to have the same level of detail, I apologize.

We basically have an acreage position that came in through Flying J. Its an Anadarko-operated program.

There are five areas that look like they are going to be unitized.

Our interest may be as low as 5% in some, maybe 15%.

The 10% is an average, and until those units are finalized, you really don't know for sure what you are going to have.

We are going to have a position, it looks like, in at least four, most likely five when the units can finalized.

And that's an estimate.

As far as the exact plans, I don't have those numbers today.

Our Billings folks are meeting with Anadarko.

They have asked for a partner meeting next week.

And I think we'll be much better prepared to talk about the details after the partner meeting.

And then just one last one on the Bakken play.

Any update on acreage position there?

I know you had 57,000 acres or so.

Is that still the same?

And I guess on the wells that you're drilling -- I think you said you had a couple planned for the fourth quarter.

Will those go towards proving up some acreage to the East and into North Dakota?

We have two more grass-roots wells that will get drilled before the end of the year on the Montana side.

The 57,000 acres that we have referred to in past calls, that's all in Richland County, and that's a gross number -- 57,000 gross acres in Richland County, Montana.

And that's been where the play has been focused.

As you move over to North Dakota -- I don't have an exact acreage number on the North Dakota side -- but the Burlington acquisition put us in a dominant position in Mackenzie County.

And that's the likely direction the play is going to move if, in fact, it crosses the line.

The well we are testing, the well we are reentering and drilling a single lateral from, will be a key datapoint.

That's in Pierre (ph) Creek Field in Mackenzie County.

We also have a position in Mondac, Bicentennial, several other of the key fields that look like they may be in the fairway for the Bakken play.

Joe Allman, RBC Capital Markets.

On the Hanging Woman Basin, it looks like the permitting issues have slowed you up a little bit, but not too much.

Could you confirm that?

And are you concerned about permitting issues in '05 and beyond?

I think we're definitely learning as we go.

And that's a new part of the world for us.

But I have to say that the folks at Nance Petroleum in Billings have done a great job of managing that process.

They're already beginning to survey for the plan of development for 2005.

They will be submitting those plans early in the year.

We have a nice mix of fee lands, state lands, and federal lands, so most of the areas we're in we can forge ahead on the fee locations while we're waiting to obtain the federal permits.

We've had a few minor surprises along the way, but certainly nothing that's brought the program to a halt.

And certainly nothing that looks like it's going to keep us from achieving our goals in '05.

And you said you expanded the play there.

Can you be specific -- did you buy additional acres?

In what way have you expanded the play?

We have continued to look, as acreage has come up -- I think the net numbers that we provide include everything that's been purchased to-date.

But just over time moving from an initial position of about 120,000 net acres up to about 160,000 net acres, that's the expansion I was talking about.

And that's really occurred over the last 24 months.

One of this particular areas is to the south and east of our main Hanging Woman position.

We call it the river area.

And that's an area that we will be active in, in '05.

It's predominantly fee, so it won't be impacted by the federal permitting process.

But in the Hanging Woman play we're comfortable that we are on top of the permitting issues.

And at Northeast Mayfield, what would you say is your running room there?

At this point how many additional locations do you think you're going to be drilling, and might that expand or you think you're kind of fixed because of your acreage position?

It's an interesting play.

It's a bit difficult to do it justice without looking at a map.

But if you can imagine an area that's about ten miles long and about nine miles wide.

We don't have an interest in every single section in that rectangle, but we have an interest in about 80% of the sections in that rectangle.

And that interest varies from 10-ish percent up to 60% with an average of about 30.

So that paints a picture geographically.

The early development of Mayfield took place in about a nine square mile area, so three by three was where the Crook Sand development was occurring.

What we talked about today, when we went through the early part of the script, was the westernmost part of that rectangle.

That's where we have four wells that are either drilling or logged, or in one case producing.

We talked about the Dobson Ranch area.

So we've established Morrow production at the far western side of that rectangle.

And then moving up the section of the north still on the far western side, we've established Atoka production.

Those wells are the first wells of the section.

And the tricky part of estimating ultimate well count or room to run is will the Morrow be developed on 320s or 160s, and then will you wait to the Morrow depletes to develop the Atoka.

Probably not; they'll probably be additional Atoka wells.

And in the same question -- what is the proper spacing?

Most likely 160.

Potentially we end up with six to eight wells in a section, but that's not a given.

There's a wide range, and I'm not trying to be evasive, but it is tough to put a number out at this point.

But I think the fact that we have established production in these sections to the west and it's first well in the section, suggests that there's a lot of running room in that direction.

On our midyear update in June we identified 66 proven and probable locations at that time.

Just to give you a feel.

That's about two years of inventory.

Are you still looking at -- I think in the past you said something like 4 Bcf per location.

Is that a rough --

It varies weather we're talking about Atoka wells our Morrow wells, as does the cost.

I think one thing that is becoming apparent is even in areas that may not have wonderful Morrow potential, we can drill and complete the Atoka for roughly $2.5 million.

So 2 to 3 Bcf type wells work extremely well.

The deep Morrow, especially when you get into the lower Morrow, those are $6 to $7 million wells.

And you need 5 plus Bcf to make those work.

It's going to depend -- and it's obviously interesting, but also a complex area when we have over 20 identified pay zones, and how many of those get stacked up in any given well varies from area to area.

I think the Atoka reserves will be at the lower end of that range and the Morrow reserves will be at the upper end of that range.

Ellen Hannan, Bear Stearns.

Mark, just a couple of questions.

Have you formulated a capital budget yet for '05?

And have you done any further hedging for '05?

We have not done capital budget yet.

We are in that process right now.

Usually what we'll do it once we get our year end reserve report, we'll put that out together with our capital budget, usually in late January.

So that's when you can expect that.

We've done a little bit of additional hedging.

Obviously we've hedged three acquisitions for a couple of years on each of those.

And we've done a little bit of opportunistic hedging.

In total with both swaps as well as callers for 2005 on the gas side, we're hedged and just over 12%.

And then on the oil side, we're hedged in 2005 about 13%.

One other question.

Could you tell us what the cost per well, and what you think you reserve recoveries in the Bakken are?

The cost per well for the duel lateral wells is about $2.7 million, completed.

Typically it varies, but on average if you want to use about a 350 NBO (ph) number that's probably good.

Some of our peers think that that number is considerably lower than reality.

But that's a number that we're comfortable with.

David Tameron, First Albany.

Question for you, on the CapEx budget, how much of that is cost?

Obviously costs are going up everywhere, but how much of that is cost and how much is increased activity levels?

The budget is a combination.

We did look at several wells in each of our regions, based on AFEs for the same type of wells in the beginning of the year versus now.

And except for the Gulf Coast our costs look like they're up about 20% or so.

Gulf Coast actually looked flattish to even down.

But that might depend on -- we don't have as good a well-by-well comparison there.

But I think that 20% number is a reasonable number from the beginning of the year.

Is that particularly true in the Mid-Continent, Mark?

Correct.

Second question.

Of the acquisitions you acquired, which one is the crown jewel of the three, if there is one?

Which one stands out?

Do you care to comment on that?

They are all great.

Of course.

Actually, I can give you a little color on each if that would be helpful.

Give you a little bit more than what was in the script.

The Agate deal was a bit unique and it was a corporate deal.

And the assets were in the Williston Basin and the Mid-Continent, particularly the Arkoma Basin.

So that gave us a bit of an advantage.

The thing that we really liked about the Arkoma, and I think this really exhibits the versatility in our Mid-Continent, is we were historically deep Anadarko players up until a couple of years ago, and the Tulsa guys felt that in order to meet their growth goals they needed to expand into the Arkoma.

We did that in our Cole County property which we've talked about quite a bit in the past.

And that's turned into a great property for us.

We have now about 70 contiguous sections.

We own the gathering system.

We have multi-pay and we have big plans for Cole County.

And they've continued that expansion now with Agate into Pittsburgh County and to a similar geologic setting, with its multi-pay, some of the similar formations that we play in Cole County.

But also has a horizontal coalbed methane play that's very active.

And we'll be growing into that.

It's a great natural expansion in the Arkoma Basin in Pittsburgh County.

And then the 70 wells that we picked up in the Williston were very complementary as well.

That was just a wonderful fit, and a deal that we're just thrilled to death to have.

The Nemores deal is a little bit different due to the extent that it tends to be lower working interest and non-operated, but it's in a field that we've wanted to be in for five years now.

And we've tried to get in in various ways.

Again, it is non-operated and the interest varies from 5 to 30%, so we don't have ultimate control over it.

But the operators were very, very comfortable with, there are three privately-held very-well-managed firms that will be operating on our acreage that we have historically had a relationship with.

We're thrilled to death to be in Elm Grove finally, and we hope to expand our present with this first up.

The Goldmark deal is totally different, as they all three are very unique.

The Big Horn Basin, as many of you know, is a very prolific oil-producing basin, the 10-Sleep (ph) formation is the primary producer, the 10-Sleep in Posforia (ph), a big thick section that holds a tremendous amount of oil in place.

And a recent addition to our tentacle staff in Billings had some ideas about Big Horn Basin fields from his previous employer that had done some great work in this area.

And felt that the Four Bear (ph) field could benefit from some of this technology.

We identified it, went to the owner, ultimately made a deal to buy the company.

And feel like with just a minor improvement in recover with the amount of oil in place in this field, it could be a great asset for us.

So that's a little color on each one of those.

Hopefully that's helpful.

At Four Bear there's about 200 million barrels of oil in place and about 10% has been recovered so far.

And we think that can be increased significantly.

Philip Dodge, Stanford Group.

Good transition.

I'm interested in a little more detail on the Four Bear field -- How much money you would plan to spend there?

Has the previous owner been spending any money on it before the purchase?

And what level of production improvement you might aim for over the medium-term?

Actually, you identified on of the key things that appealed to us about Four Bear.

The Goldmark Group was a group of individuals and certainly they had good experiencing in the area, but they will admit that they did not put a lot of capital into the field.

And kind of lived through the mid-80s, and I think they've owned it since roughly '87 and the '90s, and lived off their cash flow.

But really didn't have the capital to commit to a major program.

What we have planned initially, we are in be process of permitting five wells for '05.

And we have those locations in the process of being permitted.

Ultimately, with waterflood enhancements, workovers, perf (ph) additions, and then some innovative ideas on tertiary recovery, which would be on down the road, we think there is substantial volume upside.

I don't have a great near-term number for you, but I think doubling the field rate in the next 12 to 24 months certainly feels achievable.

The other question I had was on the coalbed methane, the 17 wells that are coming into production next week.

What was the de-watering time at those wells and is the predictive of future de-watering time.

I think the peak rate varies from zone to zone, but I think it's kind of in the 11 to 18 month range when we see peak rate.

I know in the pilot on one of the Anderson wells we're seeing about a 70 Mcfs a day gas rate from one well, after being on for about two and a half or to three months.

Now that was the best well, so I wouldn't expect it from all these.

But I think we'll start seeing gas relatively quickly with peak rate probably a year or so out.

What kind of volume would you expect in 2005 from those and additional wells?

We don't expect a huge volume in 2005 yet, as far as being really meaningful.

It's probably really the next year that you start to see some material volumes. 2005 we would expect to start recognizing some meaningful reserves though.

Dan Morrison, Aperion Group.

Most of mine have been answered, but a quick question about the Bakken.

You said you have two rigs running and two recompletion rigs.

You'd talked previously about one and a half rigs, kind of having to share one at the Red River Sea play.

Is that now fully dedicated to the Bakken?

One of those rigs will be jumping back over to drill a Red River well in January.

But then it's expected to come back to the Bakken.

It's maybe not 100% of the time, but it's more than one and a half.

Okay.

Good.

What's the prospect for taking up either another drilling rigs or another recompletion rig?

It's something that's got a lot of discussion.

And candidly, rig availability in Williston has been difficult if not impossible.

But there are alternative possibilities to get iron moved up from a different state.

We might be able to move a rig up from Texas.

But we have yet to get a commitment that will have accrued to man the rig once we've moved it up there.

But that's continuing to get a lot of discussion and continues to be worked.

But it's a difficult situation right now.

Jack Aydin, Keybanc Capital.

Most of the questions have been answered, but I have two questions.

In Elm Grove, how much room do you have to acquire additional interest or acreage in that play?

We're going to pick up an interest in 22 sections in the heart of the play.

Candidly, the way we we'll pick up additional interest is if we're able to acquire someone's producing property interest.

There is not room to grow by going in and picking up leasehold.

The play is leased, so if they grow it'll be by virtue of the fact that we are able to buy out one of the other work interest owners or one of the other operators.

The Big Horn area, you mentioned the 200 million barrels in place.

What would be the incremental costs to raise your recover rate from the 10% and up?

What kind of cost are you looking at?

I think it depends on which technique ultimately results in a substantial production improvement.

But it is shallow, Jack.

These aren't deep wells; we're working at 5, 6000 feet.

So, from a drilling costs standpoint, it is a fairly inexpensive place to work.

Some of the tertiary recovery techniques can become a little more exotic, but certainly anything we'd be looking at doing would be less than $10 a barrel.

Some of the techniques we'd be looking to employ will probably be less than $6 a barrel.

It's not horribly complex, and it's certainly not deep.

Do you have a goal where you want to get recovery (indiscernible) from the 10% to what level over the next two years or three years -- do have any expectation goal?

Yes, I think if we could improve the recovery by an additional 5%, I think that would be a substantial volume for us, and something that I think we would be very, very proud of.

What could happen beyond that, I think it is a technology play.

And I think it's great to own barrels in the ground that may not be currently producible with current technology.

But I think some incremental improvement -- I don't know the exact number, but certainly something in the 5% neighborhood should be achievable with current techniques.

But with that oil in place, it lends itself to future technology.

(OPERATOR INSTRUCTIONS).

Larry Busnardo, Petrie Parkman.

On the Hanging Woman play, can you talk about, on the dual completion, number one, the reason for doing those?

And also is that a function of getting better recoveries or is it just speeding up the process?

A little background on that?

And also could you provide well costs and the EURs?

I don't know if you've provided those in the past?

I can certainly answer the first part of it, Larry.

I'm not sure I can nail the second part of it down.

In the Powder River Basin originally all the wells were drilled.

And typically the coal seams were top set, our casing was set right above the coal seams, and the wells were drilled out and completed open hole.

And sometimes they pumped water into them to provide some level of stimulation.

And the conventional thinking was that that's the only way you can produce the coals and the powder.

As time went on, people tried just perforating the casing and trying to produce the well through perforation.

And initially they didn't respond perfectly well.

But over time, and in our pilot in particular, a couple of years ago, we cased across two zones, tested each zone individually, and then tested the zones on a commingled basis.

We had commingled rates that compared favorably.

In a couple of cases we're actually higher than the individual zone tests.

So that gave us a lot of confidence.

And then just over the last couple of years, the offset operators have continued to experiment with multi-seamed completions and have had very favorable results.

So ultimately it's a cost-saving.

We can drill one well and produce two or perhaps three coal seams when our original economics, when we first took this leasehold position, assumed one well per coal seam.

And now we're talking about one well per two or three coal seams.

So it really improves our economics.

The second part of the question, as far as EUR, again that's going to vary -- on well costs, that's going to vary by coal seams.

But we are looking at ballpark-ish range of well costs probably in the 120,000 for the shallowest coals up to maybe as much as 400,000 if we get into a deep coal.

We're not talking about deep;

I'm talking about 2,000 feet and if we get into a deep development.

And per well EUR is probably in the two-tenths to four-tenths of a B type range.

Those will get you in the ballpark.

And you were talking about the economics -- what type of rates are you getting, I guess obviously I'm sure they're outstanding right now.

But say at a $5 of $6 price on gas, what do you see there?

As far as --

Rate to return.

Rate of return, okay.

We really have not given that out.

We, Based on our original economics, kind of go into the play.

It did work with that 375 or so NIMEX price with a single coalbed seam completion.

So clearly in this environment the rates returned are much better.

David Tameron, First Albany.

Larry stole my first questions there about the multi-seam.

Second question for you -- you talked about the service cost increase, etc.

Your LOE looks like it went down quarter-over-quarter -- how did you manage to pull that off?

And second, is most of that cost increase going to show up in the DD&A?

Is that the fourth-quarter uptick?

Can you talk a little bit about that as far as guidance?

Our LOE this quarter was a little less, it was both workover, which I think is probably a big part of it, as well as bringing on a couple larger wells, which bring down your per Mcfs rate.

In the fourth quarter it's a little hard to exactly predict that.

In our forecast we brought our LOE portion of the rate up to kind of what it was the prior several quarters.

But it could be lower, we don't know for sure.

And then on the taxes, because of higher prices in the fourth quarter, that's about $0.13 of that increase from this quarter to the fourth quarter.

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