SM Energy Co (SM) 2006 Q3 法說會逐字稿

Good morning.

My name is Jody, and I will be your conference operator today.

At this time I would like to welcome everyone to the St. Mary Land & Exploration third quarter 2006 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] I would now like to turn the conference over to Mr. Brent Collins, Director of Investor Relations.

Please go ahead, sir.

Thank you, Jody, and good morning to all of you joining us by phone and online for St. Mary Land & Exporation Company's third quarter 2006 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 the volatility of oil and natural gas prices; availability of economically attractive exploration and development and property acquisition opportunities and any necessary financing; the pending nature of the Mondak acquisition of properties in the Permian Basin and the ability to complete the acquisition; the uncertain nature of the expected benefits from the acquisition of oil and gas properties and the ability to successfully integrate acquisitions; lower prices realized on oil and gas sales resulting from our commodity price risk activities; unsuccessful exploration and development drilling; the imprecise nature of estimating oil and natural gas reserves; uncertainties inherent in projecting future rates of production from drilling activities and acquisitions; drilling and operating service availability; uncertainties in cash flow; the financial strength of hedge counter parties; the negative impact that lower and oil and natural gas prices could have on our ability to borrow; litigation, environmental matters, and the potential impact of government regulations.

Additionally, St. Mary will use the terms "probable" and "possible" reserves in this conference call, which SEC guidelines prohibit from being included in filings with the SEC.

Probably reserves or unproved reserves, which are more likely than not to be recoverable, possible reserves, or unproved reserves, which are less likely to be recoverable within probable reserves.

Estimates of probable and possible reserves, which may potentially be recoverable through additional drilling or recovery techniques are, by their nature, more uncertain than estimates of proved reserves and, accordingly, are subject to substantially greater risk of not actually being realized by the company.

With that, the company official s on the call this morning are Mark Hellerstein, Chairman and Chief Executive Officer;

Tony Best, President and Chief Operating Officer;

Dave Honeyfield, Vice President and CFO;

Jerry Hertzler, Director of Business Development;

Dennis Zubieta, Manager of Reservoir Engineering; and Brent Collins, Director of Investor Relations.

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

Thank you, Brent, good morning.

I am pleased to report record quarterly earnings, discretionary cash flow and production for the third quarter of 2006.

St. Mary had third quarter 2006 earnings of $55.9 million, or $0.88 per diluted share compared to $27.3 million, or $0.42 per diluted share a year ago.

If one excluded the noncash aftertax gain on a previously announced Section 1031 exchange and the benefit from changes in the value of the company's net profits plan, net income was $0.83 per diluted share.

We had record discretionary cash flow in the quarter, which increased to $140.5 million in the third quarter of 2006 from $125 million in the same period of the preceding year.

Production increased to a record 23.2 bcfe, which is 3% higher sequentially and flat in percentage terms year-over-year.

Our realized gas price for the quarter -- or -- total price for the quarter was $8.33 per mcfe, which 3% higher sequentially and 1% lower year-over-year.

Unit costs increased 14% over the same period last year driven by a $0.33 increase in LOE offset by a $0.04 decrease in production taxes.

G&A on a per-mcfe basis was flat compared to the same period last year.

DD&A increased to $1.72 per mcfe, up 7% from the same period a year ago.

Our cash margins for the quarter were $5.97 per mcfe, which is 4% higher than that of the preceding quarter and 6% lower year-over-year.

Obviously, costs are affecting everyone in the industry.

However, we are beginning to see firm examples that lead us to believe that some service costs, while now decreasing, are at least beginning to flatten out.

On the acquisition front through September 30, 2006, we had spent approximately $22 million on acquisitions.

This includes roughly $10 million related to the Section 1031 exchange we closed in the second quarter.

Subsequent to the third quarter, we closed several smaller niche acquisitions in the mid-continent, Rockies, and Permian regions.

Yesterday we signed a purchase and sale agreement with several private parties to acquire oil and gas properties in the Midland Basin for $250 million.

This transaction is the largest in the company's history.

These properties are in the Permian Basin and target the producing intervals of the Sprayberry.

The highlights of the transaction are as follows -- it's 100% operated with average working interest of 95% and net revenue interests of 71%.

Estimated net proved reserves are 78.1 bcfe, of which 78% is oil; 45% of which are proved developed reserves; 110 bcfe of additional net probable possible reserves; 70 producing wells with current net production of 16 million cubic feet a day equivalent, which is 78% oil; 60 proved undeveloped locations in approximately 40 lower-risk probable possible drilling locations on 80-acre spacing; average gross reserves per well are estimated at 1 bcf equivalent on 80-acre spacing; potential 40-acre development, which, if successful, may add an additional 168 locations; completed well costs of $1.6 million per well.

Estimated production expenses are $0.65 per mcfe produced excluding production taxes and overhead; a two-rig drilling program with plans to increase to four rigs within 12 to 18 months.

St. Mary estimates 30 wells will be drilled annually with a two-rig program and, obviously, would increase as the rig count increases.

In conjunction with this transaction, St. Mary has hedged the majority of an anticipated first five years of oil production, although a smaller component of the overall value of the acquisition, we have hedged natural gas with swaps over five years and natural gas liquids over the first two years.

Many of you will do a quick acquisition cost calculation and say, "Hm, $3.20 or so per mcf sounds a little high."

If we were talking 7.70 per mcf spot natural gas price, I would agree, but this acquisition is 78% oil, which we have hedged over the next five years between $65 and $68 per barrel, or $11 per mcfe.

In addition, this is not tail production with high LOE.

Most of the wells acquired were drilled in the last three years and consequently have low LOE.

The acquisition also comes with substantial upside potential.

Not only do we add 60 [pad] and 40 lower-risk probable and possible locations, but we believe there may be potential for 40-acre down-spacing, which could add another 168 locations.

The transaction is scheduled to close in mid-December.

The transaction will be financed with bank borrowings, and the company has no intention of accessing the equity markets to finance this acquisition.

With the increased debt borrowings on the credit facility, the company is expecting its year-end debt-to-book capitalization ratio to be approximately 38% and 29% if the senior convertible notes are assumed to be equity.

A third party has a contractual right to purchase up to an additional 20% undivided working interest in the transaction.

This right to acquire must be exercised concurrent with the closing.

All the preceding highlights assume that St. Mary retains 100% of the transaction.

As I mentioned, this deal is the largest in St. Mary's history, but it's really a familiar story.

Acquire through negotiated transaction, high working interest properties with exploitation potential in familiar basins where we can operate.

I'll now turn the call over to Tony for an overview of our operating activities.

Thank you, Mark, and good morning.

St. Mary continues to implement a very active and successful drilling program for 2006.

We currently have 13 drilling rigs operating in our five major producing regions, not including our smaller coalbed methane rigs, and we continue to add to our inventory of drilling opportunities.

We are especially excited with our new acquisition, the Permian Basin, and a chance to operate a two- to four-rig program with a multi-year well inventory, and the potential for significant upside.

Let me briefly share some highlights from our operating regions.

In the Rockies, we had 16 successful completions out of 17 wells during the third quarter.

We currently have one rig running in the North Rockies area, which is focused on the horizontal Bakken play.

Additionally, a rig was just added in the South Rockies area in the Wamsutter field, where we plan to drill four wells by the end of the year.

In our Big Horn Basin oil program, we currently have one rig running and have drilled three wells out of a seven-well program, primarily focusing on the Ten Sleep formation at the Murphy Dome field.

All wells should be completed by year-end.

In addition, the 3-D seismic chute over the Murphy Dome structure will commence next week and hopefully we'll identify future drilling opportunities.

At the Hanging Woman coalbed natural gas project, current operative production has now increased to approximately 12.2 million cubic feet per day gross; 8.1 million cubic feet per day net.

At this time, we have 330 wells drilled with 252 wells producing using two truck-mounted drilling rigs.

With respect to the deeper coals in the Hanging Woman Basin program, we have completed two of the horizontal wells and are drilling a third.

A fourth horizontal well was planned for later this year, and it is anticipated that all four wells will be online by year-end.

Once drilled, these wells will be on pump for some time to dewater the coal seams.

So it may be a while before we can fully evaluate well productivity.

In the ArkLaTex region, we are currently operating three rigs.

In the third quarter we successfully completed 25 wells out of 27 drilled.

In Spider field, we have one rig running, and current production from the field now stands at 11 million cubic feet equivalent per day gross.

We recently completed the horizontal Baker 34-1 well with 100% working interest by St. Mary, which came on production at a rate of 4.4 million cubic feet equivalent per day.

At Elm Grove, there are three non-operated rigs drilling Cotton Valley wells in this very successful program.

We are also working with our operating partners to get a better understanding of the productivity and reserve implications from the new coil tubing recompletions targeting the Hoston and Upper Cotton Valley, but we are very encouraged by the initial results including one well that produced at a 3 million cubic feet per day of incremental rate after the recent stimulation.

In the mid-continent, six operated rigs are currently running.

During the quarter we successfully completed 29 wells out of 30 drilled.

At the Mayfield field, we are running two operated rigs and plan to add a third rig before year-end.

We recently completed the Wynona 1-34, St. Mary working interest of 53%, which produced at an initial rate of 4.2 million cubic feet equivalent per day.

In the Centrahoma program, the recently announced Theresa Hampton 1-6 well, St. Mary working interest of 99%, is currently producing from the Woodford shale at 2.3 million cubic feet equivalent per day, and we have also recently completed the Elaine 2-9, 100% working interest by St. Mary in the Woodford at an IP rate of 1.6 million cubic feet equivalent per day, and current production of 1.3 million cubic feet per day.

These wells tested extended areas of our acreage position, and they are substantially better than our earlier Woodford wells as a result of an improved completion design used in these two recent wells.

We are continuing to learn a lot about this play.

As of the end of the quarter, we had increased our acreage position to approximately 30,000 net acres, and we play to continue with two operating rigs in the field.

At the Constitution field near Beaumont, Texas, the Paggi Broussard Number 1, St. Mary 40% working interest, is currently producing 34.5 million cubic feet equivalent per day and 1,600 barrels of condensate per day.

In the Paggi Broussard Number 2 is producing 28.1 million cubic feet per day and 1,500 barrels of condensate per day.

Moving to the Gulf Coast region, which utilizes direct hydrocarbon indicator technology, our exploration program continues its successful track record of discoveries.

We are now five for six this year with the most recent success being at Vermilion 101.

St. Mary has a 25% working interest in this well, which encountered high-quality natural gas pay from a single interval, and we are expecting the well to be online at some point in the fourth quarter.

We have as many as three additional DHI prospects that could be drilled this year, depending on rig and service availability.

On our fee lands, a significant royalty well, the St. Mary 24-1 Sidetrack, which produced initially at a rate over 15 million cubic feet per day earlier this year, has been shut in for several months due to mechanical issue in the well bore.

We do not anticipate production back online until early 2007.

In the Permian, our activity is centered on our HJSA prospect area west of Midland, Texas, and on our Parkway Delaware water flood optimization in Southeast New Mexico but obviously we'll be immediately focused on the closing and transition of our new acquisition in West Texas as we prepare for our 2007 drilling program there.

Based on additional drilling opportunities this year, we've increased our exploration and development budget of 477 million to 492 million.

The primary increase is in the Permian Region, where activity is ramping up due to a new drilling joint venture that was initiated there in the fourth quarter.

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

The third quarter was a successful quarter with quarterly records and net income, discretionary cash flow, and production.

Moreover, we grew these metrics on an absolute as well as a per-share basis.

We think this demonstrates our commitment to growing value for our shareholders.

The Permian acquisition is the largest acquisition in our history and substantially increases our presence in that region -- or in that basin.

The acquisition met all of the criteria we look for in an acquisition, and we're excited to be adding another multi-year drilling program to our portfolio.

We continue to grow in all of our regions and are continually filling the pipeline with new prospects and ideas.

With the solid inventory of prospects in every region, we are well-positioned as we finish 2006 and head into 2007.

With that, I'll turn the call over to the operator for any questions.

[Operator Instructions] Scott Hanold, RBC Capital Markets.

Good quarter, guys.

You know, on the acquisition it looks like you're starting to build some scale in the Permian Basin right now, and it now appears to be one of the larger areas of operation.

So it seems like you're going to focus a little bit more on that.

Can you talk about how the acquisition fits in with your existing asset base; if there's any synergies, and how you're going to go about developing it?

It seems like you're going to be putting more capital to work in this area.

Is it just mainly on the acquired assets or are there some things on the existing asset base that you're going to do to ramp up that area?

This is Tony.

First of all, we have had a presence in the Permian for some period of time.

Our assets there produce very well.

We've got significant upside with our key assets there, as I mentioned earlier.

We thought that was an excellent position from which to grow, and part of the primary rationale for pursuing an acquisition like what was just announced, we think that that will continue to add significant scope and scale for our business in the Permian Basin.

And we continue to see additional opportunities even beyond where we are today with the new acquisition.

I will note that, as you mentioned, we are building scope and scale there, and as a result we will be initiating a new office in Midland.

This will be rather small in scope to begin with, but as we begin looking at operations, especially with the new acquisition, we thought that it was appropriate and timely to put some key individuals in the Midland office.

Okay, and just in terms of looking at capital spending, and it may be too early to start talking about exact dollars into '07, but at this sort of renewed focus on the Permian, as you look into '07, where do you see capital spending between each of the regions -- uf you could comment on that?

We really haven't put together our full 2007 capital plans.

That will be developed over the next couple of months.

But, obviously, a two-rig program -- capital to support a two-rig program with our new acquisition will obviously be a component of that plan.

And just timing-wise, we normally will announce our capital program for 2007 in late January and, with that, we'll also have our final reserves for the year, and we'll announce that as well as our production forecast.

So all that will come towards the end of January.

Could you comment as far as where you're spending your money?

If you're going to put a little more emphasis on the Permian because of this acquisition and such, is there another area that you might slow activity because of rig availability or cost or economics or just regular running room?

I think you have to look at each of our plays.

As we've talked, historically, it's a touch of a simplification, but we've talked about five specific resource plays a lot over the last year or so, beginning with the most mature, which has been the middle Bakken.

Because of its maturity, quite frankly, that one is starting to end the initial phase of development.

We don't know whether there will be infill possibility or water flood, maybe a number of years down the road, but the initial phase of that is pretty much going to be over fairly soon, and so that one you'll see a decrease in capital next year.

The next one that we've talked about that's also fairly mature is the [umgrow] field.

This is one of the few areas that we don't operate, so we can't really give you a feel yet of what the actual dollars are going to be spent next year, but we've been very, very happy with that field, and it has about a five-year inventory.

There has also been recent success using coil tubing frac in the Hoston and Upper Cotton Valley, and so that's one that we'll see continued increasing activity that we've been very, very happy about.

The Atoka granite wash play at Northeast Mayfield, we also have multi-year inventory there.

That tends to be a little more of a statistical play.

There's a range of wells that come out, but if you look at 10 wells, they tend to average about the same.

That is a little dependent on gas price.

The rate of return is usually pretty good, but you get a lot of your gas very quickly, and we hedged in future prices there.

We would likely do that for next year, which would lock in a good economics.

And then we have several more emerging plays -- Hanging Woman, which we're now, as Tony mentioned, just learning about using horizontal drilling in the deeper pools.

We haven't yet really had results there, but that will certainly have an impact.

Hanging Woman has a tremendous potential, going forward.

We would like to accelerate that, and we're talking about doing that, but there's a number of steps that you have to do to make that happen.

And so that's one we would like to see increased but we haven't announced that or haven't really figured that totally out yet.

And then the final play is really the three plays in Centrahoma, and with our recent success in much better completions at the Woodford, I would expect that would accelerate activity there.

We also had a nice success this year at Terryville, which we would likely see that activity increase as well in the ArkoTex area as well as very successful activity in the James Lime play.

So we have a very nice inventory, and those are filled with other things.

Obviously, if costs remain very, very high and prices drop, some plays get kind of skinny, and you would reallocate your capital, but we obviously look at that when we put together our plan for the year.

And so it's a little early to give you specific numbers by area.

Excuse me -- in addition to that, we've also got our direct hydrocarbon successes in the Gulf Coast area and, obviously, bringing those online later this year, as well, into next year, we'll have certain capital requirements, which we'll have to determine as well.

What is you guys' comfort level of capital spending as far as your cash flow?

Do you want to stay within cash flow or do you feel comfortable going a little bit outside of that?

We actually prefer to go outside of that, if you include total capital budget including acquisitions.

In our modeling that we do, basically, we can grow without raising equity by out-spending our cash flow as long as we have good economics with hit, and we've done that historically, and that is something that you want to do because you really want to grow the business, and we haven't really changed our basic object of replacing 2 mcs or barrels for every one that we produce, and that can come either organically or through acquisition.

David Cameron, Wachovia.

Congratulations on the acquisition.

A couple of questions -- you mentioned the Sprayberry trend, obviously, the name that pops in is Exxon and Pioneers, what kind of pops into the head.

Are these properties located near those properties?

What other operators are down there?

Do you have any confidence in the 40-acre spacing, et cetera, that other people are doing out there?

Can you talk a little more about that?

Sure.

Basically, the property that we have acquired is in the same basin as the properties you mentioned -- the typical Sprayberry types of plays.

They're all in the Midland Basin.

Our focus is not on the old traditional Sprayberry types of development plays.

This actually focuses on the Sprayberry interval, which includes three producing intervals of interest.

That would be the Leonard, the Sprayberry, and the Wolf Camp.

Okay, and you talked a little bit about down-spacing.

Yes, in regard to the 40-acre spacing, there have been a few wells that have been drilled on 40s.

In fact, one 40-acre location in the field that we have acquired, the results from that well have been as good or possibly even a little bit better than some of the 80-acre locations, but, again, that's one well, and certainly we don't intend to extrapolate from that, but it certainly indicates that there is prospectivity relative to 40-acre spacing in the field.

Okay.

This was not an auction process, correct?

Or -- I mean, this was a privately negotiated transaction or was this an auction process?

It was privately negotiated.

Have you worked in the basin before, Tony?

Yes, for several years.

Okay, a second question -- obviously, Dominion announced what they announced yesterday.

Anything strike you right away as assets or where they're operating in fields there, et cetera, that you guys might be interested in?

Any regions in particular?

We do know that they did acquire an interest several years ago in the Mayfield field, and that would be a direct overlay to our asset.

We'll have to see how it's actually packaged.

They also have an excellent Canyon gas position in the South Midland Basin they've done very well with.

So, obviously, those kinds of assets would be of interest, but, obviously, we'd have to take a look at the entire thing, which we haven't done at this point.

Okay, and then let me just -- one more question about the Woodford, and then I want to throw something else out.

In the Woodford, you know, you gave us a brief operational update, but my understanding is you've drilled another horizontal well, is that right?

You started a second.

Could you talk briefly about what you've seen from the first well versus your expectations?

Yes.

To date, we have drilled and completed six horizontal Woodford wells, and I would say basically that the first four were a disappointment to us.

We did not see the productivity that we had hoped for.

During the summer, we spent a considerable amount of time trying to learn more from offset operators who had had more success and applied a lot of those learnings in our last two wells.

So we have a total now of six horizontal Woodford wells.

In the last two wells, we have applied basically a new stimulation design based on what we learned both from service companies that were completing stimulating wells in that area as well as from well completion reports from some of the offset operators as well as using an outside consultant who had also provided consulting services to some of the offset operators.

And from a combination of that learning, we have optimized and improved our frac design for those wells, and I think as a result of that, we're starting to see the improved productivity based on that new design.

We have our seventh well that is currently drilling in the Woodford, and then we have an eighth horizontal Woodford well planned for between now and the end of the year.

I'll stop hogging the call here, but just in the Williston, could you give us a quick update on the existing production, what you're seeing, going forward, et cetera -- just a quick snapshot?

Yes, right now in the Bakken, our total current rate is around 19.2 million cubic feet equivalent per day.

We will have drilled or participated in about 30 wells this year, and we have a handful of wells yet to focus on through the remainder of the year.

We have a one-rig program currently focused there.

As Mark mentioned earlier, we are approaching the end of development opportunities in the Bakken, although we are taking a look at infill opportunities, and that is certainly possible.

I would say that's more a mature play for us at this point.

Is it safe to say, along with industry, it's still mixed results on the other side of the Nesson anticline.

The North Dakota side, we just see the trend continuing to thin, and we don't see the same prospectivity there, so right now we have an excellent acreage position on the North Dakota side -- 55,000 acres.

Most of that is held by production, and our plan, at this point, is to let others go out there and do some testing and similar to what we did with the Woodford in Centrahoma.

We intend to be quick learners and look for opportunities that some others can crack the code, so to speak, on the North Dakota side.

Okay.

Also, you had mentioned the Nesson anticline -- there has been some specific successful wells.

It's not really a resource play, but it's much more structurally driven, and we are looking at that and, in that area, there are some successes.

So we view that as really a different kind of play.

It's not the same resource play that Tony was just talking about.

[Operator Instructions] Philip Dodge, The Stanford Group.

A question on the acquisition, the detail, can you give us the estimated cost of developing the PUDs?

Yes, basically, about $1.6 million per well.

Yes, so just --

You can do the math that we have there.

Calculate that from the total wells, the percent that are PUDs, and then times 1.6?

Yes, exactly.

About 96 million.

Okay, and then I wanted to ask you on the Vermilion 101 discovery, what you estimate as the initial deliverability?

We haven't brought that well online, so we haven't done any estimates as far as productivity from that well.

We are anticipating --

But it is coming on in the current quarter?

Yes, we expect that to be connected and producing by the end of the year.

Michael Scialla, AG Edwards.

On the Hanging Woman, you said you'd like to accelerate that play.

What needs to happen there?

Is it primarily on the regulatory side, or do you need to see more on the geologic side at this point?

I think it's a variety of elements, certainly permitting continues to be an area of focus.

In order to make sure that you have your plan of development in place, you have to get in the queue, you have to plan quite a bit ahead.

We've currently got a two-rig program, as I mentioned earlier.

If we accelerate that to three or four rigs and, obviously, there's that many more applications for permits that have to take place.

In addition to that, we have done an extensive field study based on the wells that we've drilled already, and so we have been able to high-grade and prioritize various areas of the field, and those would certainly be of immediate interest if we were to accelerate the program.

In addition to that, in this case, we don't think that rigs will be an issue.

These are smaller truck-mounted rigs, and they are available.

There are other constraints that we need to consider, and that would be technical resources.

This is not a homogeneous play.

You have to go out and do technical work as you continue to develop the field, and the folks up in Billings have an excellent staff, but, at the same time, if we accelerate this program, in all likelihood they'll need additional technical resources.

I guess if I'm understanding you correctly, though, there's not necessarily a bottleneck right now that's holding you back.

It looks like you can get permits that would support a three- to four-rig program, and you may need to staff up a little bit, but it's something that looks like it's viable at this point?

We think so but, obviously, the folks in Billings are working that right now, and part of their 2007 planning will be to come back and share with us a detailed plan for an acceleration case.

I can tell you that on the Montana side, that does remain a constraint on federal acreage just because of the supplemental EIS that we're awaiting.

But the bulk of our acreage and estimated reserve, 70% is on the Wyoming side.

So certainly we could concentrate our efforts there.

Okay, and your Granite Wash play -- can you tell us what the completed well costs and reserves are running there now?

You said it was pretty much a statistical play at this point, I guess, if you need to break it into a couple of horizons, if you could.

We look at our Northeast Mayfield -- currently, we're looking at completed well costs from 4 million to 4.4 million, and these would be Atoka completions, which is the focus of our development there.

And we are looking at somewhere around 1.3 to 1.5 bcf per well, kind of ultimate recovery.

You get back about half your reserves that first year, so it's a little different profile than other things, so it has a higher finding cost, and that's one of the reasons your rate of return is actually usually very good.

It's really -- you want to maximize your return on investment and, to do that, it needs a little higher price to do that, and so if you're looking at strip pricing, you know, in the $8 range, that works well.

Is that 1.3 to 1.5 gross?

Yes.

Yes.

Is that play -- is there some variation in the [tranning] area there?

I guess I've heard the industry be a little bit more -- or is the industry maybe just being more aggressive with their numbers?

Do you think that's pretty typical of that play, in general, aside from -- or -- outside of your acreage holdings?

I think we have about, what, 52 sections, is that about right -- 48 sections?

It's in that range.

I don't have the numbers in my head, but it's a substantial area that we're in, and it does include some of the plays you're probably thinking of.

There have been a couple of extraordinary wells to the south in that Buffalo Creek --

Buffalo Wallow?

Buffalo Wallow.

No, it's not Buffalo Wallow, it's Buffalo something.

But that was an extraordinary well, but it was a very specific fault block.

They tried offsetting that, and it really didn't work, but that's sort of an isolated -- that was closer to the major fault to the south and has a little different geology associated with it, but I would say the rest of the play, I would think, we're pretty similar to the other people.

We've got about 26,000 gross acres in the play.

Okay, and then one final one -- in your James Lime play, are you looking at that differently now that you've had the success with Packers Plus.

Is there maybe more opportunity there to add acreage?

What does the opportunity set look like, going forward, there?

The simple answer is yes.

We continued to be encouraged with our completion so far in the James Lime, and we continue to look for additional acreage opportunities, and we have added significant acreage based on our completion success, so far.

Is it in and around the Spider area or are you stepping out away from that?

I would say the best way to characterize that is we are looking regionally for James Lime opportunities, which would extend beyond the Spider field.

[Operator Instructions] John Gerdes, SunTrust Gerdes Group.

Tony, if I'm reading you right on Hanging Woman, where we are today, you'd be thinking about continuing 140 wells, CBM wells per annum at present?

I would think that would be our base case.

That's pretty much the pace we've been on.

But like we mentioned earlier, we would like to see the opportunity to accelerate that program.

Just looking at the potential reserves; taking a look at 3,000 potential well locations, you know, to me, that adds up to about a 20-year program.

I think it could be very leveraging and much more meaningful if we were to see that go to more like a 10-year program.

So the probability is you're going work hard to obviously try to begin the process of making that happen in '07, it sounds like.

That's correct.

Shifting gears -- up in the Williston -- the Madison, Radcliffe, Mission Canyon, you're doing some horizontal work in some of those horizons, aren't you, Tony?

Any update there?

At this point, we've seen some good success from our test wells in those horizons.

The team in Billings is looking right now to see how can we leverage that, and is there a way to continue growth in that program?

And I think it's actually excellent timing to consider that.

With their success in those various intervals and as the Bakken is winding down as we kind of see it right now, I think that provides an excellent opportunity to provide more focus and apply more capital in the Madison, [Iscu], and some of the other intervals there.

How many wells do you think you'll get drilled this year in those sections?

In 2006, I don't have a number of wells, but I think our budget, which probably has changed a little bit, but it was $26 million that we had in our budget for 2006.

We haven't lined it out for 2007 yet.

Okay and, Mark, that would be, what?

Maybe 10-ish wells, something like that, possibly?

It's probably not more than that.

Okay, shifting gears to the Woodford.

The recent well result you just mentioned, Tony, where do you go here?

I mean obviously that fifth well was looking pretty good.

This one, the sixth one, was a little bit weaker.

Adjustments, I'm sure you're going to continually adjust, and then the follow-on to that, are you planning to put a third rig in that field prior to year-end?

At the present time, we're going to stay with pretty much a two-rig program.

We will be bringing in another rig, but it's more of a changeout situation where we're upgrading rigs.

So, for a few days, we may have three rigs there, but right now our focus is pretty much a two-rig program.

Looking into 2007, that could change, but, first of all, like I said, we have to continue to learn in terms of this field.

We're encouraged with what we've seen, but we'll continue to optimize and see what else we can do with our frac design.

The initial change in design was basically more than a doubling of frac fluid volume.

We've also significantly increased the amount of profit by more than double in some of these new stimulations.

We're encouraged, but we've still got some things to learn.

Are you doing more stages as well?

You increased the intensity of number of stages you're doing in these laterals.

Not so much the number of stages, it's more fluid volume.

Some of the laterals we've tried have been a little bit longer than in the past.

And then, as well, like I said, the amount of profit that we're putting away is considerably larger than our original design.

What kind of goal would you shoot for to get even more excited about the work you're doing in the Woodford?

Are you shooting for 2-plus million a day type IPs to really make these -- to suggest really putting the rigs to this thing and really ramping?

Well, I think, obviously, that would be an objective.

I think, right now, our near-term objective is to see consistent results so that we feel good about our completion -- or our stimulation design.

And as soon as we have a little bit more confidence that we've got that figured out, I'd like to see us potentially ramp that up.

We are acquiring additional acreage in the Woodford play, so we're certainly encouraged to that extent and would like to see that program expand, if it makes sense, and we feel we can provide consistent results.

Congratulations on the acquisition.

Thank you very much, John.

Scott Hanold, RBC Capital Markets.

Just a quick question on the Permian acquisition -- that third party that has the contract right to the purchase of 20% interest -- can you give a little color on that.

Is it a private or is it a public company?

Do you have any expectations whether or not they'll take that interest?

It is a private concern, and I'd just as soon not conjecture what they may or may not be able to raise as far as the capital, but certainly if they can do that prior to close, then they would acquire 20%.

If they can't, then we would retain the full 100%.

[Operator Instructions] There are no further questions, sir, at this time.

Thank you very much.

We appreciate you all for joining us today, and we'll talk to you next quarter.

Thank you, this concludes today's St. Mary Land & Exploration third quarter 2006 conference call.

You may now disconnect.