SM Energy Co (SM) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2010 St.

Mary Land & Exploration earnings conference call.

At this time, all participants are in a listen-only mode.

We will be facilitating a question-and-answer session toward the end of today's conference.

(Operator Instructions).

As a reminder, this conference is being recorded for replay purposes.

I will now turn the presentation over to Mr.

Brent Collins, Director of Investor Relations.

Thank you, Grace Ann.

Good morning to all of you joining us by phone and online for St.

Mary Land & Exploration Company's first quarter 2010 earnings conference call.

Before we start, I'd like to advise you that we will be make forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance.

These statements involve risks, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday, our presentation posted to our web site for this call, and the risk factors section in our 2009 10-K that is filed with the SEC, as well as our form 10-Q that will be filed later today.

We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Additionally, we may use the terms probable, possible, and 3-P reserves, and estimated ultimate recovery, or EUR, in this call.

You should read the cautionary language page in our slide presentation for an important discussion of these terms and the special risks and other considerations associated with these nonproved reserve metrics.

The Company officials on the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Wade Pursell, Executive VP and Chief Financial Officer; and Brent Collins, Director of Investor Relations.

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

Thank you, Brent.

Good morning, and thank you for joining us for the St.

Mary quarterly call.

After a few brief remarks, I'll turn the call over to Wade Pursell and Jay Ottoson for their respective financial and operational reviews.

As noted in our press release from yesterday, we have a presentation available on our web site that we'll be referring to during the call this morning.

Let's begin with slide three of our presentation, which I'll use to address some of the highlights that I'd like the listeners on the call to walk away with today.

First, we had another solid quarter and a strong start to 2010.

Despite closing our Rocky Mountain divestiture packages early, production for the quarter exceeded the high end of our production guidance.

This was led by strong results in our south Texas and Gulf Coast region, where the Eagle Ford Shale program is performing nicely, as well as our mid-continent region.

On the cost side, we met or came in below almost all of the items that we provide guidance on.

As I alluded to earlier, we closed the two packages of Rocky Mountain oil assets in the quarter, and the proceeds will be used to fund a portion of our capital program this year.

In spite of the divestiture, our bank group maintained our borrowing base, at $900 million, at our most recent redetermination in March.

In yesterday's press release, we provided information regarding our carry and earning agreement.

It covers a portion of our East Texas Haynesville position.

We believe that this deal is very positive for the Company.

It provides us with an opportunity to de-risk a large portion of our Haynesville Shale position, with minimal capital exposure, while freeing up capital to increase activity in the Eagle Ford Shale.

Jay will discuss this in more detail in a few minutes.

We are executing well in our business plan for the year.

Our activities and our key programs are meeting or exceeding expectations.

While the forward natural gas strip is challenging, we had assumed low gas price when was we prepared our 2010 business plan last fall.

Accordingly, the majority of our capital program was already geared toward oily and ridge gas projects, and we have not had to make any significant changes to this year's plan.

As a result of solid production performance year to date, and additional capital we will be deploying in the Eagle Ford Shale, we are increasing our production forecast for the year to a range of 98 to 104 BCF equivalent.

And this increase will be done without increasing our capital investment budget.

which will remain at $725 million.

Before turning the call over to Wade, I will comment on the status of our ongoing transformation.

We have transitioned from a company that was short of drilling inventory just a few years ago, to one with a number of high potential, multi-year projects.

We are continuing to make strides in testing and proving up the various portions of our inventory.

I'd also like to add that through actions like divesting of noncore assets and the Haynesville agreement we are announcing today, we are preserving the strength of our balance sheet at the same time.

Our goal over these past couple of years has been to position the Company, where we can provide consistent annual growth and solid returns for our stockholders.

And I have never been more confident in our ability to do that than I am today.

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

Thanks, Tony.

Good morning.

Late yesterday we released our first quarter earnings release and financial highlights.

I'll touch briefly on some the more important aspects of the announcement.

I'm going to start on slide five, which shows our quarterly performance in areas we guided on.

Starting with production, production for the quarter averaged 286 million cubic feet equivalent per day, which was over the guidance range of 255 to 278.

As Tony mentioned, this was achieved even with the Rocky Mountain oil transactions closing early.

I'm not going to tell you much on costs, given that we came in at or under the majority of costs that we provided guidance on.

On LOE, the increase in costs that we anticipated didn't materialize to the degree that we had planned.

We also divested higher operating cost properties earlier than we forecasted, which has a downward effect on LOE per unit.

Looking at cash, NPP G&A, the impact of the Rocky Mountain divestiture, and slightly higher realized commodity prices resulted in higher payments than we had guided.

Payments from this legacy program are quite sensitive to prices we receive from production.

There were not a lot of unusual items this quarter.

We had a gain of $121 million related to divestiture activities.

This primarily related to the sale of noncore North Dakota and Wyoming properties previously discussed.

We reported net income for the quarter of $126 million or $1.96 per diluted share.

Adjusted net income for the quarter, which excludes items that are generally one time or infrequent, or items whose timing and/or amount cannot be reasonably estimated, was $29 million or $0.45 per diluted share, and higher than Wall Street consensus.

We're providing adjusted net income number because we believe it is the most directly comparable to the estimate financial analysts calculate and publish.

Cash flow from operating activities was $154 million for the quarter.

Operating cash flow available for the quarter was $133 million or $2.07 per diluted share, and this beat Wall Street consensus numbers, as well.

Moving to slide six, you'll see that the balance sheet is in solid shape.

Our debt-to-book cap is 19% at the end of the quarter.

As mentioned earlier, we closed on the sale of noncore properties in North Dakota and Wyoming.

Proceeds were used to pay down our revolver, so there's really not much to say, except that the balance sheet is in really good shape.

Jumping to slide seven.

The borrowing base on the credit facility was maintained at $900 million during our most recent redetermination in March.

Bank group maintained that level despite the divestitures that were closed during the quarter.

Currently, we have nothing drawn under the facility.

We will likely draw on the revolver later in the year as part of the 2010 capital program.

You might remember our plan for the year is for CapEx to be equal to operating cash flows plus divestiture proceeds.

So, all things being equal, that means that you should reasonably expect us to end the year with roughly the same amount drawn on the revolver as we had at the end of 2009.

Turning to slide eight, my final slide.

Based on the increased production guidance that we provided yesterday, we're hedged through the remainder of 2010 at our approximate equivalent price of $8.05 on roughly 45% of our equivalent production.

We also have a solid hedge position that covers a good portion of our PDP in 2011 and 2012.

We've actually begun hedging in 2013 with some oil collars and NGL swaps in the first quarter of 2013.

A summary of our hedging position is included in the appendix of our presentation for today's call, and the details will be provided in our 10-Q, which will be filed later today.

I guess I'd conclude by saying that I'm quite pleased with our balance sheet and current liquidity position, and believe the Company's very well positioned with dry powder available.

So with that, I'll turn the call over to Jay.

Thanks, Wade.

I'm on slide ten, which is a summary of the Haynesville carry and earning agreement that we're announcing today.

The transaction can be summarized as follows.

First, the transaction divides our acreage in Shelby and St.

Augustine County Texas into two blocks, a north block which is all in Shelby County, and a south block which overlaps the Shelby/St.

Augustine county line.

This year we needed to drill seven wells in these two blocks to hold our acreage position there, one in the north block and six in the south block.

St.Mary will receive $87 million in carry drilling and completion costs to be used in the south block.

St.Mary will operate all the wells in the south block.

In exchange, a third party has earned the following portions of our interest in the Haynesville and Bossier intervals, 95% in our roughly 8,400 net acres in the north block, and 5% in our roughly 23,400 net acres in the south block.

In total we're giving up around 9,100 net unproven acres in exchange for the drilling carry we are receiving.

We're not selling any production, and we're keeping all the uphole rights.

Carry agreements like this, you should note, are very tax efficient.

We also retain operatorship and control of spending and economic decision making on almost all our remaining East Texas, Haynesville, and Bossier acreage.

We believe this transaction is a real positive for us.

It allows us to de-risk our East Texas/Haynesville position and maintain most of our acreage with minimal capital exposure this year.

It also allows us to shift capital to fund additional activity in our high return Eagle Ford program and make some investments in infrastructure there and in the Marcellus shale program.

All this is accomplished without increasing our capital budget for the year.

If you move to slide 11, you'll see the changes we're making to the capital program as a result of the Haynesville agreement.

At this point, we're maintaining our overall capital program at the same spend level of $725 million.

We're increasing our Eagle Ford shale drilling budget by $68 million, the majority of that increase is slated to be deployed in our partner-operated program, that is the Anadarko JV acreage, where we anticipate significant condensate and rich gas production.

Our actual operated activity level in the Haynesville will be roughly the same as we had originally planned, and costs in that area have been increasing.

However, we're anticipating some reduction in discretionary co-owner operated drilling, based on some recent announcements that have been made.

Combined with the drilling carry we're receiving, our net CapEx in the Haynesville will go down significantly.

In the other drilling category, our current thinking is that we'll reduce spending on some other gas drilling as a result of lower natural gas prices.

This will likely impact several discretionary wells that we had planned in the Marcellus and Woodford shale programs.

Lastly, we're increasing our investment in infrastructure by $22 million.

This increase relates entirely to our Eagle Ford and Marcellus programs.

As a general comment on our capital forecast for the year, I will say that completion costs are moving higher than we budgeted, and the co-owner activity in our oily plays is higher so far than we anticipated.

We'll continue to monitor the impact of these trends on our capital program through the year and make adjustments as required.

I'm now on slide 12.

As a result of our increasing capital deployment in the Eagle Ford, as well as strong production performance in the first quarter, we're increasing our production outlook for 2010 to a range of 98 to 104 BCFE.

This results in fourth quarter 2009 to fourth quarter 2010 production growth of 15%, adjusting for divestitures.

I should note that we were actually still declining in rate in the fourth quarter of last year due to our decision to reduce spending in 2009.

So this 15% number actually understates our underlying growth rate, somewhat.

Very briefly, slide 13 shows that because we book our gas production as wet gas rather than gas and NGLs, we have more liquids than our reported production would suggest.

Given high liquids pricing in our hedge position, our cash flow for 2010 is not being greatly impacted by the current low price of natural gas.

Slide 14 provides a summary of our planned activity for the remainder of 2010.

I won't really spend time on this slide because I'm going to go into more detail in upcoming slides, but the slide here is a summary for you to refer to later.

I'm now on slide 15, which is a summary of our recent Eagle Ford shale activity.

As we mentioned in our press release from last night, we have been intentionally restricting the rates on a number of our most recent wells in order to protect our completions.

Generally, we're limiting the wells to a rate of about 2.5 million a day of gas rate.

It is too early to say definitively whether this approach has had a favorable impact on our EURs, but we're optimistic about it.

Some of our recent activity has helped us in our efforts to delineate where the dry gas and rich gas portions of the play are located on our acreage.

Obtaining this information is critical to our infrastructure planning.

The condensate yield and BTU content of some of our most recent wells are on this slide.

The well results generally conformed to our view of the play, although we had a bit of a positive surprise in part of the Galvan Ranch area in the south where we had a well with richer gas than we actually anticipated.

Specifically that's the well labeled "C" on the map, the Galvan Ranch 17H.

We currently think that only about 10% to 15% of our total acreage position is going to be in the very dry gas fareway, which is lower than what we had initially thought.

We expect to be drilling additional wells farther to the east on our acreage to delineate that position in the next few months.

With respect to the performance of our previously released Eagle Ford wells, I will say that we've not noticed any decline in the condensate yield to date on our wells which produce condensate.

The next slide is a summary of our position and activity in the Eagle Ford which totals 250,000 net acres.

Really has not changed significantly from our other recent presentations.

We still plan on operating two rigs on our acreage in 2010.

We are seeing a higher level of activity from our partner, Anadarko, on the joint venture acreage.

As I mentioned earlier, a large part of the money we're freeing up in the Haynesville through the deal we just concluded, will be going toward participation in non-op drilling in the Eagle Ford.

Now I'm moving to slide 17.

In the Granite Wash, we're currently flowing back our first well in this portion of the play.

The Wester 2-34H is a Skinner target well and utilized a 10-stage fracture completion in a 4,500-foot horizontal lateral.

We are currently drilling our second well in this area, the McIntyre 2-27H, which is a Marmaton B target.

Our current plan is to drill and complete two other Granite Wash wells in 2010.

We have roughly 32,000 net acres that are prospective for the greater Granite Wash.

Given the multiple potential productive intervals in the wash, this acreage could have a very meaningful number of potential locations for the Company.

On slide 18 is a brief update of our Bakken/Three Forks activity, where we plan to continue operating a two-rig program for the remainder of the year.

We're targeting the Bakken and Three Forks intervals and plan to complete 17 wells.

We're also participating with operating partners in their Bakken and Three Forks programs.

We have 78,000 net acres that are prospective for the Bakken Three Forks in North Dakota.

I should note, that acreage number is up about 10% from the last time we announced it.

On slide 19, we provide an update of some other activity.

I would like to say a few words specifically about the Niobrara.

There have been a lot of rumors and speculation going around about our first well in the play, the Atlas 1-19H.

As we disclosed in our press release last night, we have drilled and set casing on the well but have not yet completed it.

The horizontal section of the well was drilled with a rig equipped to allow underbalanced drilling, specifically to help us avoid losing excessive amounts of drilling fluid due to natural fracturing in the pace section.

As a result, during the drilling process, we actually produced about 13,000 barrels of oil.

If you look at the drilling records for the Silo Field area just north of our well, producing oil like this while drilling was actually pretty common.

However, there's not been much drilling activity in the area for a while, and people apparently have forgotten about that.

We plan to pump a multistage fractured treatment on the well later this month and will then see what kind of a well we can really make.

We have 25,000 net acres now that we believe is prospective for the Niobrara.

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

Thanks, Jay.

On slide 20, we have a slide that shows the new name for the Company that we have proposed to our stockholders.

We must approve the change in our current proxy process.

The Company has operated under the St.

Mary name in some form since its founding in 1908.

For many years the legacy assets in St.

Mary Parish, Louisiana, were the principal drivers of value for the Company.

Over time, however, these assets have become much less significant to St.

Mary.

As we have transformed the Company and shifted our strategy to become a North American resource play company, we now feel that it's the appropriate time to change the name of our Company.

The name SM Energy honors our legacy as St.

Mary, while positioning us for our new direction, and we will retain SM as our ticker symbol.

For stockholders that are listening to the call, we hope that you will vote in favor of the name change.

With that, I'll move to slide 21 to leave you with some key takeaways from our call today.

First, we had a very strong quarter to begin 2010.

The Haynesville carry and earning agreement is a good, solid transaction that helps us de-risk the Haynesville with little capital exposure.

It also allows us to reallocate more capital for the Eagle Ford shale.

We are executing well on our 2010 business plan, and as a result, we are increasing our production forecast for the year.

As Wade said, our balance sheet is in solid shape, and we are well positioned to fund our future growth opportunities.

With that, we'll turn the call over for your questions.

(Operator Instructions).

And please stand by for your first question.

Your first question comes from the line of David Tameron of Wells Fargo.

Good morning, Dave.

Sir, your line is now open.

Your next question comes from the line of Anne Cameron of JPMorgan.

Good morning, guys.

Congratulations on a great quarter.

Do you think, should we be expecting to more agreements like your Haynesville carry?

Well, I think we'll continue to look at opportunities to improve our economics on any of these plays as well as managing our capital appropriately going forward.

So, Anne, we continue to look at a variety of options.

This just happens to be one that we thought was timely, and very well positioned.

But as those opportunities come about, we'll evaluate them and make the call at that time.

Okay.

Great.

And at this point, do you expect to be able to hold all of your Marcellus acreage, and how many wells does that mean per year in the next couple of years?

This is Jay.

Yes, we'll be holding all our acreage here.

The Marcellus position actually kind of divides into two parts.

There's a part in Keene County which we don't have to drill very many wells to hold.

And the stuff in Potter County which we don't have very many early obligations, but by the end of 2012 we have to amount a pretty substantial drilling program.

So for this year we're in good shape with the two wells that we've talked about drilling, we'll hold all our acreage.

Next year and the year following, we really have to get after it if we're going to hold everything in Potter.

So I think really we're looking at alternatives and depending on what happens with gas prices, we'll make our choices there.

Okay.

Great.

Thanks.

That's all I had.

Thanks, Anne.

Your next question comes from the line of Derrick Whitfield of Canaccord.

Good morning, guys, and congratulations on the great quarter and Haynesville CEA.

Thanks.

On Eagle Ford, you currently have a 34 gross operated well plan for 2010.

How do you see your efficiencies impacting this number, or is it too early to tell based on increasing your activity?

Well, frankly, we're drilling the wells faster than we anticipated.

The completions, though, I think you can expect to drag out a little bit.

So we're still -- we're still stuck on that 34 number.

We'll see where that goes probably in the fourth quarter.

We may have some flexibility.

I'm not sure we can get more wells than that completed, we can probably get more wells than that drilled.

Right now that's where we're sitting, is at the 34 number.

Okay.

And then thinking about your restricted flow rate test, what's the longest test flow that you guys have on production, and how would the current flow rate on that well compare to one of your nonrestricted wells over a comparable period?

The longest well we have on production was the Briscoe G1H which we completed last July.

And it was a short lateral and wasn't that great a well compared to some of our later wells.

Then we had a period of time there, we completed a number of others starting in October.

So really not a lot of data on those.

We started restricting rates on wells at the beginning of this year.

And what you're seeing is what's -- what we would hope to see.

A lot of the wells that we have restricted rates are on are flat line, and they're approaching the point where at the same cume amount of gas we had on earlier wells, they're still flatlining.

At some point in the next months to six months, we would expect to start, hopefully we'll start to see the wells actually cross that decline curve from our earlier wells.

And that will give you an indication that we're doing some good on our EURs.

Haven't seen that yet.

Still too early.

Still on the left side of that curve, but certainly moving that direction.

And I think once we get some data like that and we have, now we have about 20 wells down, we'll start showing more data in terms of what our curves look like now that we have a substantial number of wells.

I think that's probably going to be something you'll see over the next couple of quarters.

Great, thanks for the color.

And then on the Haynesville CEA, are there any provisions in that agreement that would allow for further farmouts so to to speak?

Absolutely.

Are your Hinton and Ironosa wells included in that agreement?

Yes, they are.

And we're still in the late second quarter completion?

Yes.

The Hinton's actually been taking over, the operations on the Hinton well, which in the north block, have been taken over by the party who executed the deal.

We're currently on our, drilling a well called the Crockett on the southern acreage.

So we'll have the Crockett and the Ironosa to complete.

The other party will be completing the Hinton.

So we're still on schedule essentially with the same plan we had.

Our interest in the Hinton well goes down to 5%, because it's in the north block, and we'll have 95% of the wells in the south block.

And just touching back on this provision in that CEA, would they be of similar value, or again if you guys can comment, that's fine.

Well, we made very sure, we asked to be very, very sure that on our southern block acreage, that we were not in any way limited to be able to sell down again or to sell out of our acreage position.

And we set up an agreement that does not interfere with our ability to make the economic decision that's we need to make going forward.

Okay.

One last question, guys, on the Bakken.

Are you guys able to offer any updates on your Divide county wells?

Not particularly.

And I think the wells are fine.

They're good wells.

That area of the play, Three Forks wells up there are not an overpressured area.

You don't get huge IPs.

I would say that in general we probably had longer flow period without having to get an artificial lift on the wells than some previous wells in the play up there.

So we're encouraged by that.

But they're not big IPs in that particular part of the world so it's not a big press release event.

Okay.

Thanks for your time and taking my call, guys.

All right.

Thanks.

Your next question comes from the line of Welles Fitzpatrick of Johnson Rice.

Good morning.

On the 7,000 net acres in the Bakken is that from additional leasing, or is that just lease exploration management?

A little bit better than you guys had thought?

Well, it's additional leasing that we've done over the last few months.

Okay.

That's part of the reason we've been a little bit shy in terms of sharing a lot of detail because we have been leasing in the area.

Okay.

And with regards to the incremental infrastructure spending, you said Eagle Ford and Marcellus.

Is a majority of that targeting the JV with regard to the Eagle Ford?

Yes, it is.

Okay.

Great.

That's all I have got.

Thanks, guys.

Your next question comes from the line of Subash Chandra of Jefferies.

Good morning.

Want to clarify the Q1 production numbers.

You said that I guess south Texas Gulf Coast and the mid-con, did I get that right, the three areas that contributed.

And if you could maybe provide some concept of scale, was it evenly divided or was there one particular area that did better than the others?

Well, it really is -- those are two areas, the south Texas and Gulf Coast is one region, and mid-con is the other.

The outperformance really originated in two specific areas.

First of all, the mid-con, we completed a well, a couple wells late in the year and early in the year in the Woodford shale, which significantly outperformed our expectations.

So that was -- that was a big chunk there.

The most, I would say most of the out-performance has really been in the Eagle Ford.

I think we conservatively estimated our rates there.

And we've gotten to a higher level than we expected faster than we thought.

And so we've outperformed our Eagle Ford rate forecast pretty substantially in the first quarter.

Okay.

Thanks.

In the Haynesville deal, does this carry now satisfy the 25 wells, the next two years, 25-well obligation, or is there a timeframe, some term period for this carry to be -- after which it expires?

Well, it doesn't satisfy our drilling obligations, because we still have to drill the wells.

But what it does do is it reduces, because we actually are pushed off some of the acreage to a third party, the 9,100 acres we left, our obligations get smaller.

Essentially we have a 5% interest in that area.

A 95% interest in the south.

We still have to drill the wells to hold the wells in the south.

It reduces our commitments from around $200 million next year to around $140 million or so.

So it takes a big chunk of committed drilling or obligatory drilling off the table for next year, as well, but not all of it.

Okay.

So the number that you put in for this year, which is in the communication, the adjustment for Haynesville, is what it does for you this year, and then next year it's another $60 million reduction?

Right, yes.

Of course, giving up the $60 million, you give up the acreage, too.

Yes.

Okay.

The restricted cash I guess, the $36 million.

So I guess that will be put into lease acquisitions?

That's correct.

Yes, that's what we were able to identify, about $45 million of the divestiture proceeds that we could utilize in 1031 exchanges.

Yes.

And has that already transpired --

It has, it's ongoing.

Okay.

Then finally, in the Niobrara, how is this going to be different than, say, the Bakken?

Well, I think the big thing we've seen so far at least in the area we're in is there's an extensive amount of natural fracturing that changes, changes how you have to drill them.

And potentially changes how you have to complete them significantly.

Not clear to us yet whether the Niobrara is a sweet spot play or whether you're going to really be able to develop it on an extensive acreage basis.

So you're right.

It's very early days.

But it is very different than the Bakken, at least the well we've drilled so far, is very different in the sense that you have big, open, natural fractures.

Why do you think that -- because some operators are now saying that perhaps we need to find those sweet spots where there is natural fracturing, et cetera, and so let's be analog that in the Bakken that we can go into an area without those natural characteristics and then do some that perhaps in the Niobrara, they're going to be required from the get-go.

Do you have to find multiple fields?

Do you have any thoughts as to why that might be and if that is in fact the case?

Well, I think it relates to at the end of the day, can you break the rock and create these massive fracture systems that we create in a lot of other rocks.

It's -- just different -- different rock.

The matrix is different, where you have natural fractures, extensive natural fracture systems, it can be difficult to stimulate the rest of the rock.

Where you don't have any natural fractures, the rock may be so tight or may not be fracturable.

So it's just a very different system geologically than, say, the Bakken.

And I think -- and there's different portions of the Niobrara play.

You have this portion in essentially the northern DJ then the part in Congress County, which is a whole other, the Niobrara but really a different play there, too.

I think it's very early.

All of us have concepts of how this thing is going to work or not work, and we have to see how this plays out.

I think the real question for us is, can you effectively stimulate a well that has all these big, open fractures in it.

And if you can, then that, I think that opens up the play quite a bit for us.

If you're going to have to depend on natural fractures to do all the work for you, then clearly you've got to be where the natural fractures are.

It may actually be that you're better off from a fracturing standpoint to be in less, slightly less fractured rock, so that you can actually get out there into the matrix and break some stuff.

We'll see.

But that's yet to be determined.

It's still so early.

Very early.

Yes.

A lot of potential.

A lot of potential here, but it's still very early, and, you know, this is our first well in the play.

Yes, no, that -- that explanation actually helps quite a bit.

And one final one for me on the Eagle Ford, what's the best explanation as to where one might find dry gas, wet gas, or oil?

Well, it's the depth to which it was buried at some point.

And if you think about the deepest, the stuff that was buried the deepest was the hottest, and it gets cooked the most, and that's where your dry gas sections will be.

And the areas that were not buried as deeply are less mature.

And they have -- they have the oil.

So it basically follows at some point depth of burial.

It's not current depth necessarily, but depth of burial when the hydrocarbons were being generated.

It's not where you are, I guess I'm scratching my head on some of these 10 or 14,000-foot Eagle Ford wells where there's condensate rich or might even have oil in it.

Sure.

It's not necessarily where they're at depthwise today, it's where they were at depthwise when they were generating hydrocarbons.

Right.

Okay.

Yes.

Perfect.

Thank you very much.

Thanks.

Thank you.

Your next question comes from the line of Mike Scialla of Thomas Weisel Partners.

Hi, guys.

Good morning, Mike.

Wanted to ask a few more on the Bakken.

In terms of the 17 wells that you plan this year, how many of those are going to be in Divide county versus Williams and McKenzie?

It's four or five in Divide, I think, Mike, and the rest are -- most of them are in the Baredan area in McKenzie.

We have a few in Williams.

Do you have any update on -- you had some nice rates that you reported on about three ports of the Bakken the last quarter.

Do you have any longer term rates on those wells?

Mike, they all declined -- they're making, 400 to 600 barrels a day kind of numbers, pretty regular.

Okay.

And those, if I remember right, those are long laterals, and you did kind of 14 to 15 frac stage, is that right?

Our approach is a little different.

If you ask our guys they'll tell you they're pumping more stages than that.

We say we'll pump 10 stages, but then we'll pump diversion in the middle of the stage.

So we try to get essentially a 20-stage frac in a 10-stage tip.

We're pumping a lot of fluid, so we're pumping as much fluid as a lot of the guys who are pumping the higher multistage jobs.

And we've pumped a version in between the stages to try to get that effect without having to spend all the money.

These 30-stage fracs are costing a lot of money.

And we're trying to get that same effect without having to spend that extra whatever million dollars.

So yes, typically we're drilling the long laterals, 10,000-foot laurels.

Putting a 10-stage frac with intermediate stage diversion.

We think of it as a 20-stage job with essentially the same amount of fluid as anybody else would pump in 20 stages.

And that's essentially our cookbook right now.

Now we're looking at the data coming in on the higher stage count wells.

We have a lot of wells in inventory here.

If we see over time that stage count is really significant in terms of, as opposed to just the fluid volumes, then we'll move to our higher stage count.

We would like not to have to do that, because the costs go up substantially when you do that.

I will also say that we don't -- we do manage these wells, we're not trying to pull them real hard up front.

We're not really interested in trying to get press release rates on IPs here.

We don't set up our equipment for that.

We don't -- we're trying to protect our completions.

So we're not pulling these wells super hard, and our experience in looking at them is after 30 to 60 days the rates aren't that different anyway.

So that's kind of how we have been managing the program.

And I think if you look at some of our bigger competitors, people with significant incentive to manage their program well, a lot of them are managing their programs very similarly.

And what are those costing you right now?

Oh, 5 to 5.5 in that range for well cost.

And you're using --

Sorry?

You're using sliding sleeves for those?

Yes.

We've been using sleeves generally.

And where do you stand on the big debate between ceramic versus sand?

Well, we don't believe that ceramics are worth it at this point.

Again, you don't have a huge amount of crushing going on here.

I've heard the argument about conductivity.

It's a lot to pay for that.

Again, that's one of those things that's very difficult to prove, but very easy to see the cost.

And sometime when we have a chance we can talk about how all these things happen together.

There's a lot of this focus on IP, high spending, all this stuff seems to happen all at once, and I think you've got to really think about this.

If you've got a significant amount of inventory out there to rush out and start spending very large amounts of money without really doing some thought, doing the science, seems to us to be a way to spend a lot of money in a hurry.

Okay.

And one last one from me.

I am always one of those guilty of jumping to conclusions on the rumors on the Niobrara.

Can you tell based on what -- the data you have so far, how that compares, your well might compare to Silo Field, and if you have the fracture intensity would you try and complete that with unstimulated, any thought on that?

Well, if you look at the Silo Field results, a number of wells in the Silo Field made significant quantities of oil while drilling.

As much as 11,000 barrels or so.

But if you look at the EURs of those wells, they weren't very good.

They do well initially.

It's not a particularly overpressured system.

They would produce a lot of material while you're drilling, swap out fluids with you while you're drilling and then after you complete them, they'll flow for a while.

But then they really don't have great EURs.

So I think it is really important that we can stimulate these wells.

And get to the nonfractured part of the rock and see if we can improve upon the natural fracturing in order to get significant EURs and really make it an economic play.

I think that, again, there's the issue in the area where you're heavily naturally fractured to have this heavy natural fracturing, that stimulation is challenging, and we still think it's really important to making a decent EUR well, it may be that there are other parts of the play that are less naturally fractured.

It may be easier to pump a stimulating completion in.

So it's not yet clear where the sweet spot is.

Is it in the area that's most naturally fractured, or maybe is it off a but in areas that aren't so naturally fractured but that are more capable of being stimulated?

So again, if you look at the average well in the Silo Field, the wells' EURs aren't that, and yet they made quite a bit of oil during drilling.

So very early days.

Clearly there's a bunch of oil in the system, okay.

That's a good thing.

We have technologies today we didn't have a while back.

As we look at the rock and we try to understand the physics of it, we think we can make some progress here.

But this is exploratory work.

And, yes, the rumor mill had been pretty wild on this.

A lot of it is I think people see us hauling oil off location and assume we're completed and making a bunch of oil.

And that's not been the case.

That's great, Jay.

Thanks.

Sure.

Your next question comes from the line of Gordon DeWitt of Wells Fargo.

Good morning, guys.

Good morning, Gordon.

Just quick question for you on the Marcellus.

Just kind of wondering where this fits in on the priority list as far as across your portfolio and wondering if this could potentially be a source of cash flow should you choose to spread capital toward the Eagle Ford-Rutherford areas in the future through either potential JV or divesting your interest altogether I should say?

Well, first of all, Gordon, we like the position that we have in the Marcellus.

We think it has significant potential.

We've got some testing to do, obviously.

To fully realize and understand the value associated with that position.

So we're going to drill two to four wells there this year.

And that's going to be part of the testing, as well as lease-holding.

And then with success there we have the opportunity to ramp that program up significantly.

I should note that, and Jay mentioned this in his comments, that we are applying some capital there this year for infrastructure.

So we are positive enough about the play or we wouldn't be investing that capital.

But we think it sets us up well for, you know, long-term programs.

And we'll see how the testing goes.

If it's highly successful, that may be one that we would want to self-develop and proceed with.

If we see ourselves with higher priority projects, then certainly we can look at options to exit JV, do a number of things with our Marcellus position.

But we like the area.

We like the position we're in.

We just have to do more testing.

Have to fully realize and understand the value associated with that position.

All right.

Thank you very much.

All right.

Thanks a lot.

Your next question comes from the line of Brian Kuzma of Weiss Monthly Strategy.

Good morning, guys.

Hey, Brian.

Brian.

I'm sorry if you guys already talked about this.

But I wanted to make sure I understand the rationale for the restricted rates you guys are doing in the Eagle Ford.

Sure.

Well in general, you know, we think that it makes a lot of sense to restrict rates just to reduce the amount of crushing you have after completion and the embedment that you see.

If you look at the Haynesville it's particularly apparent from the wells we participated in, Coner wells, that it had a significant impact.

But there you have a significantly higher closure stresses, and it's somewhat of a softer rock so it makes a lot of sense.

In the Eagle Ford, I think in the deeper portions of the play, I think, it's pretty obvious, I think, to us that protecting your completion by limiting your rate makes a lot of sense.

I think the -- in the shallow portions where we are, it's not quite so obvious.

But I think we saw some of this early on in, say, the Galvan area where we had some rates that were artificially restricted due to infrastructure.

Some of our better wells were wells that we had actually had limitations on our ability to flow them early on.

But I think there's some pretty strong indications in the data you're seeing from a couple of these plays where you have , the rock, you got Calsat, Eagle Ford, similarities with the Haynesville.

You're starting to see areas where I think protecting your completion, similar to the way we used to do in the old sandtrap days makes quite a bit of sense.

And there's some data now starting to support the idea that maybe that works.

I think some of the really hard rock shale plays like the Barnett -- I know I've heard people say, it doesn't matter, you should just rip the wells.

And it won't change their performance.

It may just be that in some of these may be a little softer rock shale plays that it does make a difference.

We're hearing the same thing in the Marcellus.

Limiting rates up there makes a big difference to some of the performance there.

So all these play aren't created equal.

And I'm not saying that anybody did anything wrong anyplace else.

I think it makes sense in Eagle Ford to try this early on and try to really understand whether or not protecting that completion by just not drawing it down so hard, whether that will really add EUR.

As I said, we're optimistic.

We had some of that early data that indicated that maybe it would be a factor.

And so far so good on what we've done.

So we'll see in the next six months or so how it really works

I got you.

And like how long do you expect that you can keep the wells flat at like 2.5 million a day?

Well, that's the question, isn't it?

I mean, how long can you do it?

We keep -- all we're doing, we set the well at 2.5 million a day and keep bumping the choke until the choke gets all the way open.

Once the choke's open the well will go into decline.

But, it's going to vary on every well.

And we have a number of them now that have been flat at that rate for quite some time.

So as I said, though, we haven't had any that have actually crossed the curve from -- on a cume gas basis.

A rate versus cume plot yet.

But we're certainly anticipating that we will see some of that.

Okay.

And then you kind of mentioned that some of the wells that you did this practice on, perhaps was on intentionally earlier performed better.

I'm curious like what does that mean in terms of wells you completed in November presumably.

They were all like six million to eight million a day type wells.

What's the range six months later, the benefit of perhaps the restricted rate?

Well, if you remember, one of the quarters I don't remember which quarter it was -- we had announced a well that was producing a seven million a day, and we said we couldn't produce it at a higher rate because we were limited on infrastructure.

It was third, fourth quarter --

Fourth quarter.

One of the wells in Galvan.

That's probably one of the strongest wells we've completed on Galvan if you look at completed EUR forecast on well.

That's really when I refer to some experience, that's really where that comes from, is we had that well and a couple of others that we just couldn't open them up.

And if you look at our current projections of EURs for that well, decline curve, they had some of the higher EURs of the wells we've drilled.

I think maybe I lost a second half of your question.

But that's the experience we're referring to.

Yes.

And I guess I'm trying to get a feel for just like what that means six months later in terms of rate.

Sure.

Well, the wells all come down, to a million a day or in that range over time.

It's just a question of how much gas, there's a tradeoff here, Brian, between you like to have though big initial rates because obviously it's a big PW benefit to have that, right.

If you limit the rate, you don't get all that PW up front, so you have to say, well, I'm going to have to get enough EUR, enough volume out of this well and it had to be pretty early in the well's life in order to make the PW part of that work out, right.

You're trading off early rate, which has a high PW rate, maybe more later rate which has a PW, and that PW tradeoff has got to work for this to make economic sense.

The EUR advantage had to be significant in order for that to work.

But it can be substantial.

Obviously it makes all your other metrics work well.

If you can do that.

So, if you can make a significant impact in your EUR by restricting rates then it makes sense to do it.

The real question is at what rate do you limit it, okay.

Is it 2.5 a day, 2 million a day, 4 million a day, how do you decide on that rate?

We picked 2.5 million a day, and we can vary that over time and see how much difference that makes.

Okay.

And let me ask one other quick -- what's your just gross operate at Eagle Ford production right now?

40 a day, in that range.

Thanks, guys.

Great quarter.

All right.

Thanks, Brian.

Appreciate it.

And this ends the Q&A portion of today's conference.

And I will now turn the call back over to Mr.

Tony Best for closing remarks.

Thank you, operator.

And thanks to everyone for your interest in St.

Mary.

We'll talk to you again next quarter.

Thanks for calling in.

Thank you for your participation in today's conference.

This concludes the presentation.

And you may now disconnect.