SM Energy Co (SM) 2008 Q2 法說會逐字稿

Good morning.

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

At this time I would like to welcome everyone to the St.

Mary Land & Exploration second quarter 2008 earnings 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)

Thank you.

I would now like to turn the call over to Mr.

Brent Collins.

Thank you, Michael.

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

Mary Land & Exploration Company's second quarter of 2008 earnings conference call.

Before we start, I would like to advise you that we will be making 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 a discussion of these risks, you should refer to the information about forward-looking statements in our press release from yesterday, and the risk factors section of our 2007 Form 10-K/A.

We will 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 3P reserves, and estimated ultimate recovery, or EUR, on this call.

Probable reserves are unproved reserves which are more likely than not irrecoverable.

Possible reserves are less likely to be recoverable than 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 true reserves, and accordingly are subject to substantially greater risk of not actually being realized by the company.

EUR means those quantities of petroleum which are estimated to be potentially recoverable from an accumulation, plus those quantities produced therefrom.

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; Dennis Zubieta, Manager of Reservoir Engineering; Mark Solomon, Controller; [Mark Branham], Senior Attorney; Matthew Purchase, Treasurer and Budget and Planning Director; and Greg Hahn, Director of Investor Relations.

I will now turn the call over to Tony.

Good morning.

Thank you for joining us this morning for our second quarter earnings conference call.

Yesterday we released our quarterly earnings press release and financial highlights.

I will provide an overview of our year-to-date performance, as well as a few thoughts on St.

Mary's transition efforts and direction, followed by comments on our second quarter financial results.

Jay Ottoson, our COO, will then provide some comments on our current operations, and then I will wrap up with some concluding remarks.

Looking back at the first six months of 2008, we have had a very strong first half.

We are executing on a number of the goals we set out in our business plan at the beginning of the year.

Production is exceeding our plan, and cash flows are strong due to the better than anticipated production growth and higher commodity prices.

We have made great strides in hiring and getting our organization staffed for growth.

Most importantly, we have been working to improve our portfolio so that we can grow faster and more efficiently.

Divesting in non-core assets and instilling a culture of operational excellence has been, and will continue to be, key factors in helping us move towards that goal.

Moving to the financials, I am going to focus my remarks on the second quarter's results.

Production for the second quarter 2008 was 28.6 BCF equivalent, which beat our guidance of 26.0 to 27.0 BCFE.

Production was up 10% year over year, and if you adjust for the significant divestiture which closed in the first quarter of 2008, our production actually grew 15% year over year on our retained properties.

Reported net income for the second quarter was $33.6 million.

Diluted earnings per share for the quarter was $0.53 per share.

Adjusted net income which adjusts for non-recurring and significant non-cash items was $80.8 million or $1.29 per share, which is in line with the first call estimate.

There are two significant adjustments this quarter, the non-cash charge related to the change in the net profits planned liability and bad debt expense resulting from the bankruptcy of SemGroup, a company which purchased a portion of our crude oil production.

The after-tax adjustment related to the NPP liability was $43.3 million or $0.69 per share, and was the result of an increase in forecasted prices for oil and gas as of June 30th.

The after-tax adjustment related to the SemGroup bad debt expense was $6.3 million or $0.10 per share.

I will discuss the SemGroup issue in more detail in a moment.

Discretionary cash flow for the quarter was $211.9 million or $3.38 per diluted share, which is $0.30 higher than the first call estimate.

Lease operating expense including transportation was $1.63 per NCF equivalent compared to $1.37 a year ago, and was higher than we had guided for this quarter.

In the second quarter we had several unplanned major well workovers, one at the Judge Digby Field in the Gulf Coast and a couple at the Constitution Field in Southeast Texas.

That drove LOE up for the quarter.

Like others in the E&P sector, we are also seeing increases in recurring LOE that we believe are being driven by strong commodity prices, high levels of activity, and some limitations of services and by supply firms to keep up with demand.

Production taxes for the quarter were $0.95 per MCF equivalent and were driven up by the strong commodity prices that we saw in the quarter.

CD&A increased year over year to $2.67 per MCF equivalent from $2.10 per MFC last year.

Directionally as higher F&D properties have become a larger portion of our production base, CD&A has gone up.

G&A for the second quarter of 2008 was $0.77 per MCF equivalent, which was slightly below guidance for the quarter.

G&A increased from $0.63 per MCF equivalent in the second quarter 2007 due primarily to costs associated with higher overhead count and higher cash payments from the net profits plan year over year.

We noted in our press release that we had two exploratory dry holes in the quarter.

These were non-operated wells in the Floyd Shale in Mississippi.

We had an impairment on crude properties in the quarter related to two wells targeting the Glen Rose Formation in East Texas.

After promising initial results, both wells began producing large amounts of water and became non-commercial.

The non-cash charges related to the increase in net profit plan liability is the result of the significant increase in forecasted oil and gas prices between the first quarter and second quarter of 2008.

The value of this liability is significantly impacted by commodity prices.

However, I would note that oil and gas prices have pulled back meaningfully since the end of the quarter.

We recognized $9.9 million before tax in bad debt expense in order to reserve the receivable from SemGroup for June 2008 production.

Our maximum additional exposure is $6.8 million before taxes for amounts related to oil volumes sold after the quarter in.

These amounts are not material to our liquidity or our overall financial position.

That said, just because we have established reserves for these receivables does not mean that we won't be paid or that we have stopped pursuing our claims for payment.

We are continuously monitoring the bankruptcy process, which has been very dynamic, and are determining the best course of action for the Company.

Clearly the SemGroup bankruptcy is a very unusual situation, and one that we feel is highly unlikely to recur.

We felt it was appropriate to make this adjustment to our adjusted net income.

In summary, we had a solid second quarter, and will be certainly happy to answer any specific questions you may have related to our financial results in the Q&A segment of the call, or you may get with Brent offline afterwards.

I will now turn the call over to Jay for his overview of operations.

Jay?

Thank you, Tony.

Company-wide we are currently running 16 rigs.

I will briefly cover the areas where we are focused and making most of our capital investments.

First, in the Woodford shale we continue to see positive results.

The average EUR for our last ten wells with meaningful production history is approximately 3 BCFE which is an improvement from the 2.7 BCFE average we have been disclosing recently, and clearly better than the results we saw in our first ten wells.

We have two operated drilling rigs running there currently and will be adding a third rig in mid-August.

We also continue to be a leader in drilling efficiency in the play.

In East Texas and northern Louisiana we have two operating rigs running that are focusing on a horizontal program consisting of James Lime and Cotton Valley wells.

This area of the country is also where our Haynesville shale acreage is located.

We disclosed 50,000 net acres that have potential, roughly 10,000 of which is in Louisiana and the balance of which is in East Texas.

We are in the process of building a location for our first horizontal Haynesville well in Louisiana, and will begin drilling there by early September.

The Haynesville is an exciting play and we're happy to be in it.

I should point out that we are already growing production 35% a year, year over year in the AkLaTex with just our Cotton Valley and James Lime programs, so the Haynesville is another added.

On the North Dakota side of the Williston Basin, we are currently drilling our second horizontal Bakken well in Burke County.

Our first horizontal well in northern Mountrail is currently completing.

The pilot hole for that well was drilled through the Bakken, and our logs confirmed the presence of prospective Three Forks formation in that area which is an additional upside for the Company.

We are also completing our first horizontal Bakken reentry well in McKenzie County.

We recently entered into an agreement to purchase roughly 6,000 net acres in eastern McKenzie County and 18,500 net acres in northern Divide County.

We believe this acreage has significant potential for the Bakken and the Three Forks.

The Williston is an active place right now, and we have a lot of exposure there, more than 150,000 net acres between our legacy-owned Elm Cooley/Bertrand acreage and the new acreage positions that we have been building over the last year in North Dakota.

I will note that the Williston Basin is the region where we have had the most exposure to SemGroup as they were a marketer for a portion of our crude production there.

Clearly there are a number of things to be worked out due to the bankruptcy process, and we continue to monitor those cases closely.

While our financial exposure to SemGroup isn't material, there are scenarios where we could see a curtailment of a portion of our production in the Williston Basin.

Currently we are moving all our production, but there could be some temporary production impacts for some producers related to the bankruptcy.

In the Wolfberry Tight oil program, we have four operated rigs running at Sweetie Peck, and our partners are operating two rigs at Halff East.

We are continuing to drill and evaluate 40-acre locations in three pilot areas at Sweetie Peck.

The program is working great.

We probably don't talk about it as often as we should.

It's an oil project, has very good economics in the current environment, and there is additional upside potential.

In the Maverick Basin we have two rigs running in our Olmos shallow gas project.

As many of you know, we are also participating with a partner in a program to test the Pearsall and Eagleford shales in the Maverick Basin in South Texas.

We are currently in the process of drilling several horizontal reentries prior to starting on some grassroots horizontal well tests.

We don't have any completion results yet.

If this program is it successful, it exposes us to a large acreage position, potentially 75,000 net acres, at a very low cost of entry.

On the capital and guidance front, I appreciate that many of you want to know what we are forecasting and guiding for the second half of the year.

We have a regularly scheduled board meeting this Thursday where we will be discussing our capital investments for the remainder of 2008.

Unfortunately, earnings season and the board meeting didn't line up this quarter, and we won't be in a position to provide capital and financial guidance for the remainder of this year until after that board meeting.

We plan to update you on that by the end of next week.

With that, I'll turn it back to Tony.

Thank you, Jay.

A couple of closing remarks before we turn the call over for questions.

As many of you probably saw yesterday morning, we have announced that we have hired Wade Pursell as Executive Vice President and Chief Operating Officer.

Wade was previously CFO at Helix Energy Solutions in Houston.

He brings a lot of transactional experience, as well as deep financial and accounting knowledge to the table, and he will be a key contributor in moving St.

Mary to the next level.

He will be joining the company in early September.

St.

Mary has been quietly but effectively transforming over the past 18 months, becoming a more resource play focused company with increased growth potential, higher efficiencies, and a deeper inventory of repeatable projects.

In fact, we are now active in three of the top six resource plays in the country, the Woodford, the Bakken, and now the Haynesville.

I believe we don't get enough credit for that in our evaluation.

Concurrently we have had great success recruiting new leadership and talent to both our management team and our technical and profession staffs.

Our management team is focused on delivering value for the stockholder, and the new compensation plan recently approved by stockholders in May clearly aligns our management and employees with the stockholder.

I am excited about where we are, and a lot of work to ramp up our growth flywheel has now been completed, and we will continue our efforts to grow the company while optimizing our portfolio.

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

(OPERATOR INSTRUCTIONS) Our first question comes from Stephen Beck with Jefferies & Company.

Yes, hi.

Actually, this is Subash.

Question on the Williston Basin.

Have you sort of got a sense of the Saanich or Three Forks potential on the Montana side of the border, and where I think you have a substantial legacy, and if there are any attempts near term to try to drill a well out there?

Subash, I have to say I don't know enough about that to really comment intelligently.

We are going to Billings at the end of this week, and we will be talking about a lot of issues up there and I may know more, but right now I don't have a sense of what the Three Forks potential is on the Montana side.

Okay.

And in the Haynesville, I guess you sort of leapfrogged the vertical part of the R&D process into the--and straight into the horizontal.

And I guess I suspect it's because your neighbors have had success doing it, so why not.

But I'm trying to figure out may in '09, are we still in the R&D process or do you think if things prove out as the last half does as well as you've seen, that you might be in development mode next year?

Probably the first couple of wells we're going to drill I think we will get some core.

We will drill some pilot holes.

We are going to do some science.

I guess our thinking was that we are going to be near production or near some other completions.

And if we're going to be in there spending a bunch of money, we might as well go horizontal and see what we can make.

And I think it was just an issue of trying to get in there and make a completion that was really economic.

Most of the vertical completions don't look like they're that great.

The horizontals have a lot more potential, so I think we are kind of accelerating our process to try to get meaningful production results earlier.

As far as moving into development, I think we will have to drill some initial wells in several different areas.

We announced this well we're about to spud.

We have plans to drill another in East Texas, probably after the first one.

And then we're going to try to move through our acreage position and make sure we have enough data to feel like we can go forward.

I'm very optimistic.

I think we have a lot of prospective acreage.

We like our East Texas acreage quite a bit.

The stuff we have in Louisiana, so we're going to drill this first well in DeSoto Parish.

I think it's in a good area, an area where there has been a lot of leasing activity, so we're very optimistic about it and we will be devoting significant resources to it in our 2009 program I think.

And one final one from me.

Any plans to sort of get in this land grab on the East Texas side?

Well, the land grab on the East Texas side, if you look at the issues in the East Texas side, most of the acreage over there is HPT, so it's a deal-based land grab from that standpoint.

As you may remember, we bought acreage in Panola County in a deal in January before the big hype started.

We have looked at a lot of packages since and haven't really seen anything that worked for us, but we look at deals all the time, and I can assure you we're looking at them now.

Subash Chandra.

Okay.

Thank you.

Thanks.

Your next question comes from John Healy with Forest Investment Management.

Hi, good morning.

Good morning, John.

A couple questions.

So is your availability under your revolving purchase simply 500 minus 295, so it's $205 million available to you at the end of the quarter?

That's true.

But, of course, that number, that 500 number could be adjusted, as well.

Yes.

I mean, but would your bank group allow you to adjust that?

I mean, how easy could you--if you wanted to take that up from 500 to whatever, between 500 and 1.2 billion, is that pretty easy to do with via your bank group?

Currently our borrowing base is 1.4, and yes, we have the capability to ramp that up.

Oh, terrific.

And then regarding this SemGroup bankruptcy, so you wrote off just under $10 million, and you said in your press release there is another just under $7 million of exposure.

What are you writing down to?

I mean, are you making some assumption about recovery or are you just writing your receivable from them down to zero?

We're writing it down to zero.

Okay.

So being conservative.

Good.

Okay.

Thank you, good quarter.

All right.

Thanks you John.

Your next question comes from [Ronnie Eisman] with JPMorgan.

Good morning.

I had a question in terms of the Williston Basin, what are you seeing for drilling and completion costs for the Bakken?

Well, I think your numbers are going to be--it depends on where you are and what your completion technique is.

For the multi-stage packer completion that everybody is running, I think you're probably looking in the $5 million to $6 million range.

If you look at it, a lot of the completions that are being run, though, are the longer lateral, I would say 1280s.

And I think the potential there is you can get those down into the fours.

To be honest, for--I mean, in our program right now, we've only got one or two wells down.

We did a lot of science on them.

I'm not really sure exactly where that's going to end up.

I think long term our objective is to get them into the fours.

I will say though that rig rates are going up and steel prices are going up, and a lot of the stuff you hear from people about costs coming down, down, down in some of these large plays right now, I think you have to be kind of skeptical about it.

We've just seen a tremendous uptick, for example, in steel prices.

A lot of shortages.

Rig rates are going up, so a lot of these forecasts that show, okay, well, costs are going to continue to be reduced in some of these plays, I think we're a little skeptical about.

But in general I think if you're in the fours somewhere for a--so a typical Bakken well, that would be a pretty good number.

And for the more complicated multi-stage packer jobs, I think five to six is probably not an unreasonable number.

And then a similar question in the Woodford, what are you seeing for recent costs there?

Low fours.

Now, as we go east on our acreage, you get deeper and you're going to see AVs in the $5 million to $5.5 million range.

Okay, great.

Thank you.

All right.

Thanks, Ron.

Your next question comes from Eric Hagen with Merrill Lynch.

Hey, good morning.

Good morning, Eric.

Just a quick question on divestitures.

Any update on CBM play, the Hanging Wood Basin play?

At the present time we continue to evaluate and continue the completion of the wells, the large program that we had going last year.

So, I mean, we continue to focus on that play, and will continue in the foreseeable future.

So no plans to divest it then at this time?

Not at this time.

Okay, great.

Thanks.

And the second question I had is on the Woodford.

Just an idea of how long it takes to drill a well spud to spud, and then also just spud to sales.

Sure.

Well, your typical well, spud to TD is probably 30 to 32 days for us, somewhere in there.

We drilled them as fast as 25, and we have had some that were more like 40, 45.

As you go deeper it's going to take a little longer than that.

Spud to sales is probably more like two months, and a lot of that is just getting frack dates lined up.

You've got all the flow-back periods, so it takes a while to get that going.

Okay.

Thanks a lot.

Great quarter.

Thank you.

Your next question comes from Larry Busnardo with Tristone Capital.

Hey, good morning.

Good morning, Larry.

First, I know it's early, but do you have any plans for a Three Forks test at this time?

I know it's--again, you've just got a couple of wells that are down right now, but given what you've seen, any plans for a test?

We're going to talk to the Board in this next few days.

I think we definitely are interested in the Three Forks.

We have potential--we are actually participating in a non-op Three Forks well right now, so we're getting data and we're excited about the potential.

A lot of the acreage we bought in Divide County, that's a Saanich play up there, so we're in the play and we've been buying acreage to be in the play.

We need to get with the Board and talk about capital and rig count in the Bakken, and I think we'll be able to give you some more color on that next week.

Okay.

Would that be potentially this year or would that be--when you talk about the program, would that be the '09 program or is that earlier in this year?

Well, I think we certainly have potential to drill a well or do some completion work in the Saanich Three Forks this year.

In terms of the major program, we only have one rig running right now in North Dakota.

And we've got a lot of Bakken activity to do as well as Saanich, so really for us I think to get significantly into the Saanich, we've got to up our rig count, and that puts you back to talking to the Board about CapEx.

So Larry, prior to that, that's a play where we get additional running room as we continue to learn more about Three Forks Saanich as well as obviously completing the Bakken, testing it.

When you think you will have results on that first well?

Is that something that may come out when you come out with the updated guidance, or would it be farther along next quarter?

Are you talking about the first Bakken well we drilled?

Yes.

I think it's going to be a few weeks.

I want to make sure the expectations are appropriate for the well, which screened out when we fracked it.

It's in an area that there has been a couple hundred barrel a day wells.

I mean, I don't think that first well is going to really--it's not going to be a partial-type completion.

So I think it will be a good economic well, but I don't--it's not going to be 1,500 barrels a day kind of numbers.

At the same time, what we're trying to prove up, up there, is that we could develop a large area at lower cost, and that is what we're focused on.

But we won't have results on that well here for a little while.

It was flowing back, making a bunch of fluid here, and we're going to have to rod it up and get a pump on it, so it's going to be a little while before you see an IP number.

Okay.

And then on the acreage that you acquired, can you give us a sense of what the cost was?

Well, we paid about $20 million for the total package, and we actually--obviously we allocated that between the Divide acreage and what we call fair game which is in McKenzie, North Dakota.

Okay.

Okay, thanks.

And then just shifting over to the Woodford, is that a three-rig program or are you going to be adding a third rig?

Are you going to maintain a three-rig program for the remainder of the year?

Yes.

Okay.

And then just in regards to those last ten wells, can you just give us a sense of where those wells were located?

Were those grouped together?

How did they match up with where the initial ten wells were drilled?

Were they interspersed or in different areas?

Well, they're actually in sort of the same area, probably a little bit to the east.

They're more easterly than some of the initial wells we drilled.

I think the big difference between the wells we're drilling now and those are really completion technique.

We've put a lot more horsepower into the completions than we did, put more hole size on the bottom, and I think it's a more aggressive completion.

Generally, though, a lot of these wells are within a section or even in the same section as some of the wells we drilled that had core results.

So I do think it's more an issue of improved completion and drilling technique than it is so much the location of the wells.

Okay, great.

Thanks a lot.

Thanks, Larry.

(OPERATOR INSTRUCTIONS) There are no--actually, we have a question from David Tameron with Wachovia.

Hi, good morning, and I want to congratulate you on a nice quarter.

Thanks, David.

Tony, and I apologize, I've been juggling conference calls, so I apologize if you covered this.

But I know your guidance isn't going to be forthcoming until you have a board meeting, but can you talk about the way you structured the portfolio?

What type of growth do you think is achievable kind of on a longer term, two to three-year outlook?

Yes.

David, our focus going forward is to be able to deliver double-digit organic growth on a year-to-year basis.

And so obviously that's part of the transformation we're making is continuing to deepen and optimize and strengthen the portfolio.

So we're excited about where we are.

We've got a lot of running room, and we're going to be focused on double-digit organic growth every year.

Okay.

And do you have that portfolio constructed today or do you need to add--obviously everyone is always looking to upgrade their portfolio, high grade it, but do you need to do anything or are you in a position today where you sit?

I think we're in a great position today.

We're in three of the top six resource plays.

Those resource plays will continue to be a focus for us, and certainly we'll be looking to add to that inventory with other resource plays and opportunities that we see.

And some of that we're pursuing as we speak, so to me that's how you continue to grow and deepen your portfolio and pursue that double-digit growth.

Okay.

And I'm throwing down one more level here.

You guys are running I think I read 15 or 16 rigs.

We're running 16 rigs.

Is that a good run rate over the next 12 months?

Do you need to accelerate, decelerate, or what's your feeling on that?

Well, David, I mean, I think we're going to be picking up rigs.

My general sense is we're going to be picking up rigs, and I say that in some trepidation knowing that the rig market is tight and costs are going up.

But you may recall what my competitors are telling you, they're going to pick up rigs, too, but generally I think if you look at our portfolio right now, especially with the addition of the Haynesville.

Honestly, the Haynesville by itself could be three years of drilling inventory for us as a company if you think about how big it could be to us.

So clearly we have free cash flow.

We have tons of great places to invest money.

I think we're only really constrained by how fast we can go and really be--one of the focuses, and Tony is absolutely right, and we're really focused on having a very efficient stand and improving the efficiency of our growth rate.

And we're going to grow faster, but we're going to more efficient about it, too.

So you're right, we're optimizing the portfolio.

We're going to be--we'll dump so low-end stuff, and as we add more really exciting higher-end lower-finding costs up, we'll just continue to high-grade the program.

But generally I think you can see we have more growth in front of us in terms of higher rig rates, higher CapEx going forward.

Okay.

And the rig market, the tightness, you're talking primarily over 1,000 horsepower type rig rates, 1,500, those type of rates?

Yes.

We've seen 12% to 15% increases in rig rates just in the last two or three months.

Okay.

We're starting to see a lot of people talking about rigs moving to East Texas, and we've had comments from people in West Texas about wanting to pull rigs to move to East Texas, so you see rig rates increasing pretty much across the board.

The Bakken rig, it's very tight in the Bakken as well, so I continue to be--I'm very optimistic about the plays and I really like the portfolio we're building.

I think this is going to be a really interesting time with everybody saying they're going to increase CapEx.

But directionally, yes, we would intend to be adding rigs with these resource plays.

All right.

Thanks.

Appreciate it.

All right.

Your next question comes from Jack Aydin with KeyBanc Capital Markets.

Hi, Tony.

Good morning, Jack.

Good morning.

A few questions.

The Floyd shale, you have two dry wells.

Are you giving up on that area, and how much acreage do you have there?

Jack, we've got 22,000 acres there.

We have an earn-in arrangement where we can earn a lot more.

We participate in a couple of coner wells that if I mentioned who drilled them, you would know them, as part of that earn-in arrangement.

In fact, those wells were pretty experimental, and we really weren't that surprised at the results we got.

But if you look at the well bores now, they don't have a lot of utility so we decided to go ahead and dry hole them.

We haven't given up on the play.

Okay.

It's a big area, and I think there are some opportunities in other places, and we may very well spend a little more money there.

At the same time, I think everybody understands that the Floyd is not the premier shale place.

Potentially some of the other ones are, and I think there's some more research frankly that needs to go into making it commercial.

Okay.

So in the Maverick Basin, you've got 75,000 acres in the East Texas area.

Did you drill a well or you're planning to drill a well, and what are you trying to accomplish there?

I think what we have said repeatedly is that we are earning in to a potential 75,000 acres through drilling wells.

That's a three-year program in which we'll spend about $8 million a year, and then I think that our third year is about $10 million.

So it's a long-term drilling arrangement.

At this point in time, we don't own the acreage, and we don't get it unless we drill.

So are you in your first year or second year?

We're in the first year.

The first year?

Okay.

The second question, you had legacy production in the Bakken--not in the--in the Williston Basin before.

What is that production running at now, and is there opportunity to go reenter some of those wells for the Bakken or Three Fork or Saanich?

Well, in terms of potential reentries, yes, there are potential reentry opportunities, and I think if you--XGO just bought acreage.

If you look at their [Heddington] purchase, what they bought was a lot of what we owned in that Elm Cooley/Bertrand area, and if you read their press release and talked to them about it, they're talking about a lot of down spacing and infill and recompletion opportunity, and we agree with all that.

And we have about 111,000 acres I believe in Elm Cooley/Bertrand area.

In terms of total production, Brent doesn't have a number here.

Jack, I'm going to get back to you on that.

He will get back to you on that.

Okay.

Final question for me, in Divide County, North Dakota, did you hear anything--have you heard anything, anybody else drill anywhere else that they have Saanich and Three Fork potential, if somebody else drilled?

Yes.

Could you name them, if you don't mind?

Well, I'm not sure I have the data here.

We can get back to you on that, too, Jack.

But yes, there are Saanich wells producing in Divide County.

Okay.

Thank you.

Jack, before you leave, one comment on the Floyd shale and also in the Maverick Basin with the Pearsall and Eagleford shales.

I think what you're seeing there is a significant change for St.

Mary.

I think those are excellent examples of where we're looking to get into some of these new plays earlier rather than later.

Rather than waiting for the plays to come to us, we're going in, exposing some minimal capital, but allowing us to test and have exposure to significant acreage positions.

And with success, certainly that's one way to continue to grow our portfolio.

And obviously the key there is once you've done your testing, to make sure that you decision those wells, and if it's not working then you get out promptly, and if it is you have an opportunity to ramp up your development in those plays.

But those are two key examples of what we're trying to do to get in earlier in some of these key resource plays.

You are transforming the company, Tony.

That's the plan.

Yes, thanks.

Okay, Jack.

Thank you.

Your next question comes from David Epstein with Advent.

Hi.

I just wanted to get your thoughts on all the supply growth coming on and your view of gas prices and how it influences your CapEx program.

Well, basically each year certainly we stay tuned to what's happening in the commodity markets, but we don't try to forecast pricing.

That's not what we do.

When we build our capital programs, we focus on minimal pricing criteria to make sure that all of our projects are able to achieve those minimal hurdles on pricing.

And then we build our capital program using that as kind of a floor.

Do you know what that minimum pricing is that you assume?

Yes.

Right now basically we have used the 70 and 7 floor for our current program, and then certainly we adjust that as we see changes in the market.

Thank you.

You bet.

Thank you.

There are no further questions at this time.

Gentlemen, are there any closing remarks?

Just a couple of comments.

First of all, I would like to thank those that were listening in this morning, and those with questions, we certainly appreciate your feedback and input.

As I mentioned earlier, we are very excited about the state of our portfolio at this point.

We have some key resource plays that we are very active in and continue to grow in those plays.

Also we're excited to have our new CFO coming on board in a month or so.

And part of our job early on is to have Wade get out on the road, have a chance to meet many of you.

If you get a chance and you're coming towards Denver, we certainly invite you in to meet with Wade and to have a chance to get to know him.

At any rate, very strong through the first half of the year.

We're excited about where we are, and our job now is to execute--continue to execute on our business plan through the rest of this year.

With that, we appreciate you calling in, and we'll talk to you next quarter.

Ladies and gentlemen, this concludes today's conference call.

You may now disconnect.