SM Energy Co (SM) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2010 SM Energy Company earnings conference call.

My name is Jeff, and I'll be your operator for today.

(Operator Instructions)

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

I would now like to turn the conference over to your host for today, Mr.

Brent Collins, Director of Investor Relations.

Please proceed, Mr.

Collins.

Thank you, Jeff.

Good morning to all of you joining us by phone and online for SM Energy Company's third quarter 2010 earnings conference call.

Before we start, I'd 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 by 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, the presentation posted to our website for this call, and the Risk Factor section in our 2010 10-K, as well as our Form 10-Q that will be filed later today.

We also will be discussing certain non-GAAP financial measures which we believe are useful in evaluating our performance.

Reconciliation 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 term probable, possible, and 3p 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 on these terms.

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; Brent Collins, Director, Investor Relations.

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

Thanks, Brent.

Good morning, and thank you for joining us for our third quarter earnings 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 yesterday, we have a presentation available on our website that we will be referring to during the call this morning.

I'm going to start on slide three, where I'll address the highlights for today's call.

SM Energy has had a strong performance so far this year, and the third quarter results were particularly good as we continued to execute well on our 2010 business plan.

We came in at the top end of our guidance for production, and our financial results were better than we had guided for the quarter.

The next key message that I want to make sure people understand is that our production growth is being driven by oil and rich gas.

We all know that the theme of the day is exposure to oil and liquids, and SM Energy has been ramping up this portion of its business.

In fact, our production is now equally balanced between oil, liquids, and dry gas.

Our production ramp is being driven by the Eagle Ford shale and Bakken/Three Forks development in the Williston basin.

Economics drive our investment decisions, and right now the returns are very strong in these two plays of our portfolio.

Looking out into 2011, these two areas will see the vast majority of our capital investments next year as well.

On slide four is a summary of our company-wide production.

One thing that may not be clear to everyone is the quality of our production ramp over the last several quarters.

Because of the divestiture of non-core assets that we have been making over the last few years, the growth in our retained core properties has been masked.

Adjusting for divestitures, you can see how impressive our growth has been.

Something that may not be fully understood is the ramp in our daily oil production, which grew 12% in the third quarter alone.

With respect to the growth in natural gas volumes, I would point out that our gas production has also been getting richer as a result of our targeting higher BTU projects.

The short story here is we are producing more of the products that provide higher realizations.

My last comment on this slide is that this growth in the liquid side of our business has been done organically.

We made deliberate business decisions to get into these plays at low cost over the last several years, and that strategy has clearly taken off in the current market environment.

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

Thanks, Tony.

Good morning.

So, late yesterday we released our third quarter earnings press release and financial highlights, and I'm going to touch briefly on some of the more important aspects of the announcement.

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

Starting with production for the quarter, we came in at 298 million cubic feet equivalent per day, which was at the upper end of our guidance range at 277 to 299.

As Tony mentioned, we've seen strong performance this year from our Eagle Ford shale program, with each consecutive month seeing increased production in both our operated and non-operated programs.

Jay has some detailed slides later that emphasize this point.

Turning to the cost side, we came in at or under guidance for all of the components that we provide guidance on.

On LOE, our cost per Mcfe was $1.06, which was below our guidance range of $1.20 to $1.25.

Rocky Mountain Region saw a decline in workover activity this quarter, which was a result of the divestiture of non-core assets earlier this year.

Production taxes were lower than expected as a result of our receiving the benefit of some severance tax holidays in certain jurisdictions.

Turning to G&A, total G&A came in at $0.96 per Mcfe.

We had guided to $1.04 to $1.10, so we were under the guidance.

We came in below guidance on cash G&A, which was $0.61 per Mcfe, versus the guidance of $0.65 to $0.67.

Lower compensation-related items were the primary driver here.

On G&A cash NPP it was $0.14 per Mcfe, well under our guided range of $0.19 to $0.21.

Lower commodity prices realized during the quarter resulted in lower net profits payments for this legacy program.

As far as other notable items for the quarter, we had a gain on divestiture activities of $4.2 million related primarily to a minor divestiture of gas properties in the Rockies.

So, bottom line, we reported net income for the quarter of $15.5 million or $0.24 per diluted share.

Adjusted net income for the quarter, which excludes items that are generally one-time or infrequent items, or items whose timing and or amount cannot be reasonably estimated was $20 million, or $0.31 per diluted share, which is higher than consensus.

We provide an adjusted net income number because we believe it is the most directly comparable to the estimates that financial analysts calculate and publish.

Turning to cash flow, cash flow from operating activities was $148.2 million for the quarter.

Operating cash flow for the quarter was $130.1 million or $2.01 per diluted share, and this also beat Wall Street consensus numbers.

Moving on to slide seven, you'll see the balance sheet is in solid shape at the end of the quarter.

Our debt-to-book cap is 19% at the end of the quarter, and our total debt to trailing 12-month EBITDA is around 0.6 times.

So turning to slide eight, after the regular scheduled redetermination in September, our borrowing base was increased to $1.1 billion, up from the previous amount of $900 million.

We think the increase is a positive comment on our growing reserve base, despite the fall in commodity prices.

We had $2 million drawn under this facility as of the end of the quarter.

Finally, 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 this afternoon or tomorrow.

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

Thank you, Wade.

Good morning, everyone.

As Tony and Wade have indicated, we grew production strongly from the second to third quarter, and we've revised our production guidance upward again for the year.

Most of this growth is occurring as a result of investments we're making in our Eagle Ford shale and Bakken/Three Forks programs, so this is where I will focus most of my remarks.

Slide 10 shows the growth in our operated Eagle Ford production over the last few quarters.

As we have indicated previously, our rates have been constrained by downstream pipeline limitations, and individual wells have been constrained by a lack of infield piping infrastructure.

We have been working hard with our downstream partners to increase uptake capacity, and our latest weekly average gross gas rate out of the area is roughly 65 million standard cubic feet a day, of which 58.5 million standard cubic feet a day was from the Eagle Ford.

At our roughly 75% net take on the Eagle Ford gas, that translates to about 43 million standard cubic feet a day of net gas compared to our third quarter average of 30.6.

So as you can see, even without the additional takeaway capacity we have coming, we should see substantial growth again in our net volumes in the fourth quarter.

You can also see that the BTU content of the gas we are producing is over 12.50 for our operated results to date, so we get a nice revenue bump from NGL's in our operated program in addition to the significant amounts of oil we are producing.

Slide 11 gives some operational highlights for the third quarter.

We were running two rigs continuously during the quarter and expect to do so for the remainder of the year.

We turned nine wells to sales during the quarter.

Six wells were brought on at constrained rates due to infrastructure limits.

We were able to test three wells in the Galvan area at unrestricted rates.

The Galvan 16H, located in the northeast portion of our Galvan block, tested at an average 7.8 million standard cubic feet a day and a 55 barrel per million condensate yield for a 30-day test period.

The other two wells were in our first simul-frac pilot in the play.

As indicated on slide 12, we simul-fracked two horizontal wells in the Galvan area that were drilled on a 120-acre spacing.

Both wells were roughly 5600 foot laterals and were completed with 17-stage frac jobs.

We were encouraged by the production results and the microseismic data we collected, and we will be running several additional pilots in the next year to experiment with tighter spacing and alternative simul-frac methods.

I'm now on slide 13.

In preparation for next year, we've extended our existing Eagle Ford rig contracts and have committed to two new-build rigs, which should be available to us in the second half of next year.

We've not completed our budget for 2011 yet, but I think that you can assume that we are moving on a trajectory towards a six drilling rig count in early 2012.

Subsequent to quarter end, we entered into an agreement which secures a portion of the completion services needed to support our program, and we're continuing negotiations with other providers at this time to secure additional completion services.

On the takeaway capacity issue, we should have another $10 million a day of gas takeaway capacity available to us in the fourth quarter, and we're in advanced negotiations with downstream providers, which will allow us to continue to ramp production up to and through the arrival of the Eagle Ford Gathering LLC, the Kinder Morgan/Copano pipeline, which should be available to us after mid-year next year.

I'm now on slides 14 and 15.

Our non-op position in the Eagle Ford is being pursued aggressively by Anadarko, as indicated by our rapidly growing net production stream.

Anadarko had six rigs running on our joint acreage during the quarter.

The partnership completed a takeaway capacity arrangement with Enterprise and is moving forward in the construction of midstream facilities.

APC has announced that it is pursuing some form of additional JV arrangement on its share of the acreage, which we would expect would result in further acceleration of the development.

We're closely considering our own options for maximizing the value of our Eagle Ford position for our shareholders.

Turning to our activities in the Bakken and Three Forks, slide 16 shows that we're getting on a growth ramp in this play as well.

We've been running two operated rigs in the play and participating in co-owner drilling.

Slide 17 discusses an interesting test we completed in early October, in which we fracked three long horizontal Bakken wells in one 1280-acre spacing unit, back-to-back, without flowing any of the wells back until all were completed.

We call this a retained energy frac, and it's a more practical method for achieving simul-frac-like results, giving limited frac spread availability.

The combined seven-day average rate for these wells was over 3,000 barrels a day, and the wells continue to produce at high-flowing pressures, as we don't attempt to maximize initial production rates.

We think the flowback results are encouraging, but, of course, it will be some time before we can draw definitive conclusions about the EUR's of these three wells at this spacing.

In general, our recent results in North Dakota have been exceeding our expectations, and we'll likely spend more there in 2011.

The Eagle Ford and Bakken programs make up the bulk of our capital activity, and we expect that to continue.

I'll briefly discuss other activity on slide 18.

In the Permian Basin, we're finishing up our 20-acre spacing pilot in the Wolfberry at the Sweetie Peck field.

We're going to go to one rig while we monitor the performance of the 20-acre spaced wells.

In the Woodford shale, we're finishing up the drilling of a four-well simul-frac group that we plan to complete in December.

In this play, we believe the simul-fracking on 80-acre spacing is the optimal way to develop the acreage.

Our 2010 activity has been focused on the richer gas area located in the central part of our acreage position.

After these wells are completed, we're going to be shutting down our Whitford program for a while, as essentially all our acreage is now held by production.

In the Hainesville shale, we recently completed two horizontal wells in the Shelby Trough acreage in east Texas.

Those wells came in around 10 to 12 million cubic feet equivalent a day at very high flowing pressures on restricted chokes, and we're very happy about what that says about the potential of our acreage.

I should note that the majority of our spend on operated Hainesville drilling is being paid for by our carry and earning agreement that we enter entered into earlier this year.

In the Granite Wash, we recently completed a second well in the Marmiton B, the Maguire 16H in western Oklahoma, which had a seven-day average production rate of 6.9 million cubic feet equivalent per day.

We're currently completing our first well in the Marmiton C in the Styles Ranch area on the Texas side of that play.

We'll have two rigs running in this high liquids play throughout the remainder of 2010 as we continue to test the potential of our acreage.

Lastly, in the Niobrara, we recently completed drilling in completing a second Niobrara well in southeast Wyoming but do not have production results there yet.

For those of you who are keeping score, our first well on this play, the Atlas 119H, was recently placed on pump and has cumulative production to date of about 65,000 barrels.

The last seven-day average production was right at 350 barrels per day.

As I indicated, our activity level in both of these plays, the Niobrara and the Granite Wash, will be dependent on results we achieve in our ongoing testing programs.

On to slide 19.

Our capital budget forecast for 2010 remains unchanged since our last update and stands at $871 million.

There is a good chance we could come in on the low side of this number, just due to tightness in the market for services, but it is accurate to say that there have been no major changes in our plans.

The marketing of our Marcellus position by BofA Merrill Lynch is moving forward, with a number of interested parties visiting the data room and our oil APDP package marketed by Albrecht is also attracting considerable interest.

We expect to have bids on these assets during the month of November.

The PDP asset sales should close by year-end, and the Marcellus package should close in early January.

With regard to our 2011 program, we expect our capital investment budget to be around $1 billion next year, and the majority of that will be invested in the Eagle Ford and Bakken/Three Forks.

We're holding our budget planning meeting this week and will have an update for you in December after our board approves our 2011 business plan.

With that, I'll turn it back over to Tony for his closing remarks.

Thanks, Jay.

With that, I'll move to slide 20, where I'd like to leave you with some key takeaways from our call today.

First, we're having a solid 2010 thus far, and we had an excellent third quarter.

We are executing well on our plan for this year, a large part of which was advancing the Eagle Ford program to development mode.

Second, the SM Energy growth story is real.

When you look at our performance, adjusted for divestitures, you see that the Company is on a solid growth trajectory.

Importantly, this is being driven by the liquids portion of our portfolio, namely, the Eagle Ford and the Bakken/Three Forks, as Jay just discussed.

Lastly, we are positioning ourselves for long-term performance.

The commitments to rigs and completion services that we announced last night, as well as our pending arrangements with additional completion and marketing partners, are firm evidence of our plan to grow the Eagle Ford over the next few years.

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

[Operator Instructions]

With that said, our first question comes from the line of Rhett Bruno from Bank of America.

Please proceed, sir.

Hey, guys, nice quarter.

Thank you.

First question -- in the Bakken, could you give us any color on sort of the legacy Bakken acreage, where that might be?

And if you don't have it in front of you, maybe you have some idea of how much of that is in Roosevelt county, or that area.

Rhett, there's about -- this is Jay Ottoson -- there's about 14,000 acres in Roosevelt County.

We call it the Baneville area, and we haven't been drilling there, but we've been very interested in some of the drilling that's going on.

We're participating in a co-owner well over there, but I think it is an interesting area.

We'll see.

Okay.

Any of the other areas in particular in Montana that you are looking at what is going on around you?

Well, I think there -- if you look at the old Richland County area, the Elm Coulee area, there's a lot of really -- I think good opportunities on the refrac side there and some redrill work.

It's all held, so we're not particularly being aggressive about it, and it's tough to get a frac spread to go in there to do that work, but I think that there's going to be a lot of opportunity in the Bakken in general in refracks as we get maybe some of the initial drilling activity, or we catch up with the frac spreads.

But there's -- I think refracking a lot of the wells that weren't fracked with these big -- the long, multi-stage fracs is going to be an opportunity for those of us who have legacy acreage.

Okay.

And then in the Haynesville, I think, moving in to next year -- if I remember correctly, it's the commitment, something like 15 wells per year.

Is that an asset that's maybe increasingly attractive as a divestiture candidate, or is it just the wrong time to be selling?

I think we -- we look at all of the assets and try to understand when -- is there a time to exit, how do you look -- how do you look at that?

I think as part of our budget process we're examining what the value of retaining the option of the Haynesville is.

It's not just the Haynesville, there's the Bossier behind pipe, and in most of our acreages are very significant -- in the Shelby Trough there is a big Bossier section there that a lot of people are going to be exploiting, and there's all the uphaul potential that we hold as well.

So there is a lot of option value to holding Haynesville acreage in that particular area.

If you remember, we didn't pay much to get into this, $500 an acre kind of numbers, because we've had this acreage for a while.

So our cost embedded in these acreages is actually quite a bit smaller than a lot of other people's who are in the play, and we have to really think about how much value do you add if you HPP that acreage?

So, there's a number of factors that come into our consideration here about what we're going to do in the Haynesville.

You can -- there's a lot of different opportunities for monetizing part or all of the asset, and then you have to really think about is this really the best time to be selling a gassy asset like that?

So, I don't think we know the answer to that yet.

We're thinking about it really hard.

For the next little while here we're not spending our own money, and we're clearly proving up the resource potential of the acreage, which I think should add value, no matter which way we go.

Right.

So is the 15-well commitment, was I -- is that more or less right next year?

And that's your own money, correct?

I think the 15 has come down some, because, we did the deal al.

We did a carry and earning agreement already and we basically turned over some acres to EnCana, who took that deal, and so I think we're down to more like 10 on an ongoing basis for the next couple years.

Okay, great, thanks.

Our next question comes from the line of Derrick Whitfield with Canaccord Adams.

Please proceed.

Good morning, guys, and congrats on the quarter.

Thanks, Derrick.

In the Eagle Ford could you comment on your early read on the simul-frac pilot and specifically your thoughts on ultimate space and merits of the simul-frac made productivity versus cost basis?

Sure.

Well, we're big believers in simul-fracs, and I think the results that we've seen from the microseismic would tell you that we can push these wells a little closer together.

So, we'll be doing some pilots on reduce -- further spacing closer together.

Again, these were spaced at 120s, we'll probably go down to 80s at some point and look at what that looks like.

The two wells didn't -- you didn't see much overlap in the microseismic between the two wells, except in some areas, so I think there's some opportunity there.

And then I don't think when you look at microseismic, all of that, everything you are seeing there probably isn't propped either, so some of noise you are seeing is not an open fracture.

So, I think there's opportunity to move our spacing down, which obviously is a plus from a reserve standpoint long term.

We're big believers in the performance enhancement associated with simul-fracs.

If you look at our Woodford program, we've clearly seen that those interior wells -- while you are retaining pressure, you do get some enhanced fracturing in those areas.

You get more activity on the microseismic.

There's -- I think there's a lot of good -- I'm not sure I understand how microseismic indicates all of that stuff to be honest, but I think just from a layman's viewpoint, if you look at it, there's just more activity, and I think that's a good thing.

I think it indicates more complexity in the fracturing you are doing, which I think means you are breaking more rock, all of that stuff I think leads us to believe that you will end up with a better well at the end of the day.

So the other very positive thing, I think about simul-fracing is it can help you minimize your infrastructure spend, especially in an area where you are not in a position where you have to drill well every section.

We can go into an area and essentially develop the entire area at that spacing, and it minimizes our possibility of having to go lay lines all over the place.

You can focus in certain areas and get to your ultimate spacing.

So we want to know this stuff early, so that we can plan our development appropriately.

That's really helpful, Jay, and continuing to think about spacing, are there any subtle differences in geology between your Briscoe and Galvan areas that might suggest different spacing assumptions?

Yes, I don't think we know that yet.

We haven't done a simul-frac pilot up in the Briscoe area, and I think the data is really important to being able to determine that.

I will say, I think in general we've been surprised with the consistency of the Eagle Ford across our acreage, in terms of -- there's not a lot of remarkable lithology differences, obviously, some portion of it is shallower, some portion of it has a little different fluid contents, but the geology has not been that different.

So my expectation is that we are it's going to work about the same, but we'll see as we go forward.

And one quick question on 2011 -- do you guys still feel comfortable with the preliminary projections you outlined at EnerCom?

Well, I think we just said that we're going to -- we're still thinking about that billion dollar kind of number.

as part of our budget process we're looking at all of the plays, trying to understand where our commitments are and where we really want to spend the money, and I can assure you that our focus is on returns.

We're trying to figure out how to maximize the value to the shareholder for this enormous, really, inventory that we've built over the last couple, three years.

And it's a challenging process for us, to try to figure out how to get all of this stuff into the right-sized sack that we can fund and that makes sense to go forward with.

But it's a lot of fun as well.

I mean, I think we're in a good position.

Terrific, and just to quickly clarify, those projections you guys have put out there, those were net of divestitures, and could you comment on what the Eagle Ford JV rig count assumption was?

Yes, I think we assumed a fairly high rig count in the JV.

I think we were assuming about eight -- I think APC said yesterday they are going to go to nine in the first quarter.

it's not a huge material change.

I mean, we fully expect them to ramp up additionally.

If they get another partner, we think they will be at ten rigs next year.

And as I mentioned in my formal comments, I think we're looking hard at our Eagle Ford position and trying to understand how to maximize the value of that position to our shareholders.

There have obviously been a lot of deals done.

There is a lot of interest in the acreage.

We need to carefully consider, do we want to do this all ourselves, how do we want to approach this, what's the best way to fund it, and we have a number of different ways to do that, which I think are non-dilutive and very positive for shareholders.

Terrific.

Thanks for all of the color with that, Jay.

Yes, one comment -- divestitures are out of all of that '11 projection.

We took all that out when we made those forecasts.

Very good.

Thanks, guys.

Thank you.

Our next question comes from the line of David Cameron with Wells Fargo.

Please proceed, sir.

Hi, good morning.

Nice quarter.

Thanks, Dave.

A couple of questions -- Jay, you may have mentioned this, but what are your current well costs running right now in the Eagle Ford?

Yes, they run between 5.5 and 6.5, depending on depth.

Okay.

Some of them, as you get out into La Salle, have been more than that, because right now we're hauling a bunch of water out there.

But once we get our water infrastructure in place, it won't be as high.

But yes, 6.5 probably in the south and 5.5 in the north is probably a reasonable estimate.

If you say they average 6, 6.2, you are probably right in the ballpark.

Okay.

So, and if I think about -- if you guys are going to have a four-rig program next year, that -- what's the well count?

I mean, is that 70 wells?

I mean, I'm just talking drilled, assuming -- not assuming you frac, not completion wells, but how many wells will you drill if you have four rigs running?

Well, I think if you assume 18 or 19 wells a rig, you can -- you get right there.

Okay.

And same math for Anadarko's acreage, correct?

Yes, in fact, they may be able to turn them out a little quicker.

They're a little shallower.

But again, you have to get them completed too, so that's --

Okay.

And then as I think about year-end and reserve bookings, how do you think that engineers -- or the reserve engineers -- are going to treat the Eagle Ford?

Well, there's a lot of factors that come into that, Dave.

And we're -- it's not going to be -- we're not going to be booking broad swaths of PUDs.

Some kind of reliable technology.

Just don't have enough wells to do that.

So we're going to be booking direct offsets, generally.

In some areas we won't be able to book as many as you might think because of lease lines, or other factors, or we already drilled the well next door, or whatever.

So it's just going to come down to counting well by well and getting with our reserve engineers and our outside engineers to look at it.

We've never really talked about a -- we don't have a target for what we're going to do.

And I don't think -- you should not expect us to come in and book some, really high number, you know five wells per well or something like that.

It is just probably not going to -- that is not going to happen given the density of drilling on our acreage.

Yes, all right.

And one more question.

And I think you just answered this.

But if I look at the Anadarko shop and the JV, or trying to get a JV, my understanding is you can opt in, you can opt out during negotiating, presumably without you at the table.

I mean, is that -- obviously, you are involved, but are you standalone in this transaction?

I would say that the best answer to that is yes.

We are not co-marketing with Anadarko.

Okay.

They made it clear they wanted to do that on their own.

Clearly, we can sell our acreage that we have earned in the agreement, and -- but I think right now we're trying to understand -- partially trying to understand what they are going to do and looking at our own funding issues and where we see this going and the performance of the wells and how this stuff all stacks up against other opportunities we have.

And we're going to decide, both on the operated and non-operated, where we're going to go into next year.

I mean, it's just a little too early for us to be able to say that.

All right.

And presumably, if you so desired, you could sell acreage -- you could sell that working interest, of course it would be non-op but if, that's -- is that correct?

Yes.

That's true.

And I would point out, Anadarko is going to be selling a non-op interest too.

And so people say, "Well, you are not going to get an operators premium." Well, there is no operators premium if you are not selling operatorship.

So, it's true that we're not the operator and can't make promises that Anadarko can make, and surely there will be some discount for that, probably, but I don't think people should assume that we're in a second place -- a way second place position in terms of our ability to monetize our acreage here.

Okay.

Thanks.

That's all I've got.

Appreciate it.

Thanks, Dave.

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

Please proceed, sir.

Good morning.

Good morning, Welles.

Can you guys talk a little bit about the timing of those two new-build rigs coming to the Eagle Ford?

I mean, it sounds like from your comments earlier about total well count, that's going to be a first quarter event, is that about right?

Actually, they are mid-year and third quarter on the new builds and so we're --

Okay.

We're looking at what our rig count will be in the second -- in the first half.

Right now we have two rigs committed for the year, and then we have those two new builds coming, so we're trying to look for some rigs that we wouldn't have to make such long-term commitments to, to be frank, so that we could have a little more flexibility.

But I think that you will probably see us pick up some additional rig count in the first half.

Okay.

So additional rigs in the first half to bridge to that third quarter addition or -- I'm sorry, is that incremental, or is that the new builds?

Well, we haven't decided yet, and you are catching us right in the middle of the budget cycle here.

So the minimum is what we committed to, and then where we go from there is kind of dependent on what else we have to do and how fast we think we have to go and of course what we see as far as our takeaway capacity at the end of next year.

So we're working all of those issues.

I would just say again, I think it's likely that we will pick up additional rig count in the first half.

And we may keep that rig count, as I said earlier, I think we're moving towards a six-rig count at some point into next year, early 2012.

Long term, we're probably going to have to get to higher rig counts than that.

So it's a build process for us, and we're taking it one step at a time and trying to make sure that every step we take is the right thing to do.

Great.

And in the Bakken, with those acreage additions, are you guys targeting a specific acreage add number, or is it more opportunistic, one-off type acquisitions?

Well, I would say they are opportunistic.

We are looking at areas where we think we know things, where we think we have a better understanding of the rock than other people.

Frankly, it's a very, very competitive market, and people are paying a lot of money for acreage in prime areas, and that's not really our game.

Our game is early entry, low cost.

And so it's got to be somewhat of a unique position for us to buy it in the Bakken right now, and we've got to believe we know something.

And that's really the limitation on our effort there.

Great.

Thanks so much.

That's all I've got.

Thanks, Welles.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Please proceed, sir.

Thanks, good morning.

Good morning, Scott.

So on the Eagle Ford, and I know that you guys are in the budget process, but one of the things I'm trying to get a handle on is what kind of services you all have available to you.

So do you have dedicated frac crews right now in the Eagle Ford and, if so, how many?

Well, we have one frac crew we're using all the time and another one that we're using on a spot basis.

And we are attempting to term up additional -- we have already termed up some additional equipment for year-end next year.

Actually, just did that deal this last week to bring in some equipment in the third and fourth quarter to support those two new build rigs we're bringing in.

And then we're also working on some agreements to term up with the frac spreads we have and we're looking at some additional suppliers as well.

So you are probably poking on the last real brick we have to put in place here to really feel comfortable with our build plan.

I think that the infrastructure is coming along.

Drilling side, I think we feel pretty comfortable.

Really, it's the fracs that we have to line up.

And as I said, we just executed an agreement which we feel good about which takes us in the third and fourth quarter next year on through 2012.

So we're working hard on it, and I think you will see probably some more announcements from us in the next few quarters.

Okay.

How many -- in the Eagle Ford, how many wells can a frac crew get done in a particular month?

Two rig -- with our two-rig program, a single frac spread can pretty much keep up with that.

Okay, okay, so a six-rig program, clearly you need two additional full frac crews.

Need three.

And we -- by the way, we just -- the deal we just did is for another two.

Okay, okay.

Yes, we're basically -- we're in good shape, assuming we can keep what we've got and get that termed up.

And I think that we're very hopeful of that and very confident we can get that done.

I think we're going to be in good shape.

But it is -- it is the one chink we're continuing to work on.

Okay.

How about the Bakken?

In the Bakken, we have a -- we've had a long-term arrangement up there with Sanjel, and they've done a terrific job for us.

They've pumped all our work.

Depending upon what we decide to do next year, right now we still -- we have two rigs running, we'll clearly have two running into next year, and they've covered all our work, and we anticipate them continuing to cover that.

If we pick up an additional rig, we'll have to look for some additional services.

We think we can get it.

One of the things that we do that we think service providers like is we pump sleeve jobs.

We get on and off these wells.

We get our wells drilled, and we're ready to frac when the day comes.

And we don't pump these extensively long jobs that delay people, so I think typically we have pretty good response from folks about wanting to work for us in the Williston.

So, we're confident that if we up our activity a little bit that we can support that.

Okay, got it.

And on the Niobrara, the well producing at 350 barrels per day, I mean, how does that kind of fit into what you expected on that?

It's been, what, about six months since it produced, so it seems like it's holding in there pretty good.

Is that a fair statement?

It's actually a much better well than we anticipated and much better than our type curve in the play.

In fact, if you look at that rate, it was a little over 350 barrels for the last seven days, and it has been over 400 several of those days, and you look at our typical Bakken type curves for some of our better Bakken acreage, this well is outperforming our better Bakken wells, our type curves.

So I think it's very -- it's very encouraging, but I will say it is very early, and this is one well, and, we need to complete a -- about a three- or four-well testing program here before we're going to be comfortable really putting our foot down on a development in the Niobrara.

I think there is a lot of really great news out there about the Niobrara from a number of different parties, but it's a huge play, and a lot of area gets covered, and we're just going to make sure our part is going to work.

We have some 3D coming that we're going to be looking at closely, we've got some additional wells we'll be drilling in 2011, and we'll want to look at all of that before we announce any kind of victory here in the Niobrara.

But this individual well is a really good well, no question about it.

Yes.

And I mean that second well that you drilled and that is currently completed, is there anything that you saw in drilling that looks similar or different to it?

I know there is a lot of variability in that play.

Is there any that you can kind of say in that second well that maybe --

Yes, it drilled and completed a lot differently.

We didn't see -- we didn't get a lot of flow during drilling, and it treated -- I'm not sure I would say it treated tight, but it clearly didn't treat like the first well.

I -- the best way to describe it is probably to say it did treat somewhat tight.

I don't think this well has near the natural fracturing in it that the last well had, or the open fractures anyway.

So we'll see.

I think it is a really good test, and we're going to drill a couple of wells around our acreage in different places and we'll be placing those based on the 3D we're collecting.

We're getting to be able to do that and really understand the productivity of the acreage.

Okay.

Did you say what your type curve that -- you say that the first one is performing above the type curve.

What was that, I mean, did you throw like a --

I don't think I've ever thrown out a number like that.

What do you use for Bakken, like 400,000?

Well, we have about three different type curves but, yes, 400 to 500, depending on where we are in the play.

But I can tell you, any type curve that we have in the Bakken, right now this well is better than that.

Okay.

But, it's still early, okay?

You don't know what it's going to be doing six months from now.

I appreciate that.

Thanks, guys.

Thanks, Scott.

Our next question comes from the line of Matt Portillo with Putter, Pickering, Holt.

Please proceed, sir.

Thanks.

Good morning.

Good morning, Matt.

Most of my questions have already been answered, but just wanted to do a Eagle Ford follow-up on the well costs and your JV acreage.

I know that -- I just wanted to kind of throw out a number of $5 million to $5.5 million, does that sound about right in terms of the well costs?

Yes, it does.

Okay.

And then are you seeing any cost savings on the simul-frac completions that you are running at this point, or is it mostly from improved recoveries that you are hoping for?

I would say generally no.

We're not seeing -- especially now, because we're running a bunch of science associated with these wells.

Could you see some in the future?

I think you could.

But again, I think it's mostly on the infrastructure side, associated with your ability to develop -- once you decide, okay, this is going to be 80 acres and we're going to be kind of a rolling, retained energy type of frac going here, you can kind of focus your infrastructure build so that you are not spending a lot of money you don't have to spend early on.

And I think that's probably the biggest cost savings associated with it, especially given the current frac environment.

It's tough to get -- frankly, it's very difficult to get two frac spreads on location to pump a simul-frac right now, so we're looking at alternatives.

But I do think that the big upside is downspace, more reserves.

You already paid for the acreage.

If you can downspace the wells, there is just a whole bunch of free reserves there, and I think that's where the upside is.

That's helpful.

And then just on the financial side, your run rate CapEx year-to-date has kind of implied that Q4 might be around $400 million.

Is that right, and then secondly, what's leading to the big increases?

There's some infrastructure in there that you're building out for Q4, or how should we think about that?

Well, we do have some one-time expenses that are going to bump that up some.

I mentioned in the call we are -- we are clearly -- we look at it the same way that you do, and we're looking at the forecasts we're getting from the guys in the field, and they are still forecasting a number that -- it's a little below our budget, but if you look at the run rate, we're not getting there.

And I think that our feeling is that we're going to come in under by a little.

But, it really depends a lot on what we can get done in December.

We have a lot of frac work piled up at the back end of the year.

And depending on whether we pull that work off or not, could have a big impact on the capital swing.

So I know it looks like a really big number per month, and it is, and I think it's leading me to believe that we're probably going to underrun it a little bit.

But, I think that the great thing -- our growth rate is high, even though that number isn't that high.

So it -- it looks good.

Right.

Okay.

The other issue there, of course, is that APC has been ramping.

And so, we've been anticipating additional rig count there, and we expect that to happen.

They've also picked up some additional frac spreads here to finish up some wells that they had drilled but not completed, which will add quite a bit of CapEx in the fourth quarter.

Great.

And then just the last question, I don't know if you've guided on this yet or not, but the tax impact or implications on your asset sales, how should we think about that, just given your entry costs into the Marcellus and also on your PDP reserves?

Good question.

I would say right now we are assuming that it will be minimal cash taxes from those divestitures.

And a lot of that is due to the significant drilling program that we have right now, and that assumes the IDC's -- the IDC deductions next year.

But we will do some like kind exchanges like we typically do to defer some of the taxes, but that combined with primarily the IDC's and the deductibility of our capital program next year means that it won't be a significant number, as far as cash taxes on those divestitures.

Thanks, guys.

Thank you.

Our next question comes from the line of Jack Aydin with KeyBanc.

Please proceed, sir.

Hey, guys.

Good morning, Jack.

Tony, looking at the Permian Basin, Wolfberry play, your Sweetie Peck, a lot of interest in those plays.

We hear a lot.

My question is this -- is your acreage lower quality or, in a sense you need to do something else in that area to get better results in the -- from the Wolfberry?

Jack, I would say we've been very pleased with our Wolfberry position.

As you well know, for the last four years it has provided an excellent base of production and cash flow for us and in fact is still the highest cash flow generator of any of our assets.

So, we're very pleased with our position in the play.

I think the key for us going forward is going to be to continue to look at the results of our 20-acre downspacing program, to see where that might carry us.

And actually could provide for additional opportunities in that play.

But it's still early.

And we've drilled our first batch of 20-acre wells.

So what we're doing right now is the technical work and trying to understand the productivity of those completions.

I apologize if you -- well, how many -- well, how much acreage do you have in that play, and how many location you might have in the play?

Well, Jack, the -- Sweetie Peck alone is about 13,500 acres.

Yes.

Until we get the 20s drilled out on that, we probably have a couple hundred 20-acre locations, don't know that they all will.

We also have a non-op property called Halff East, which I think is about 6,500 acres, if I remember right.

It is 20,000 in total for both, so 6,500 would be right, net, and that's operated by Concho.

They are also doing a couple of 20-acre pilots which I think are very interesting, and we just recently shot some 3D there and tested some other zones, actually, as well.

So, I think there is still substantial upside in these assets.

We want to understand them.

I think -- a lot of people ask us, "Well, would you sell these assets?" and I think the answer to that right now is we would really like to understand the value of the 20s.

Selling it now without understanding that, people don't give you credit for that.

I think we'd like to understand the value of the 20s clearly before we make a decision on either of these assets, but we're very proud of our activity there, of our operations there.

We think it is a -- we run a -- we really believe that we run the best operation down there, drilling and operations.

And, we've done -- I think we've done an exceptional job on it.

I know other people have different reserve numbers.

That is just the way that the game -- people use different type curves and different tail declines and they get different numbers, but the economics of the wells we've been drilling we think are competitive with what other people do.

Final question, how much does it cost you per well, and what kind of EUR you using per well in that area?

Recent well costs about $1.4 million, and I think right now we're using about a 105,000 or a 108,000 barrels a well.

Again, some pretty conservative numbers based on a 40-acre type number down there.

Okay, thank you very much.

When we do the 20s we discount that some, so until we see the 20s performing, we're discounting that 108,000 number a little bit.

And, Jack, you know our business model -- I mean, clearly we're focused on the Wolfberry, but we have a strong position in the Permian and we continue to look for new opportunities out there.

So we're staying up with a lot of the other competitors as far as new play entries and, some of the activity taking place in the Permian.

Thanks a lot.

Thanks, Jack.

Our next question comes from the line of Joseph Allman with JP Morgan.

Please proceed, sir.

Thank you.

Good morning, everybody.

Good morning, Joe.

I noticed in your press release and your presentation and your comments that you are focusing on the -- I guess the Bakken and the Eagle Ford and certainly understand the Eagle Ford's a huge play and that's a play to which you have the most leverage.

And -- but just thinking about -- it seems like you are deemphasizing the Granite Wash, or at least you are not emphasizing it.

I know you don't have as much acreage in the Granite Wash as you do in the Bakken, but it seems to me that the rates of return there potentially could be quite a bit better than the Bakken rates of return.

So could you just talk about that a little bit and why not emphasize the Granite Wash, and I understand the Wolfberry does have less scale, but could you talk about that as well?

Yes, first of all, I think it is a really fundamental issue for Granite Wash is all of that acreage is HBP.

And we have acreage explorations in these other plays and we have to drill them, and so a lot of our activity given the size of our portfolio right now and the things that we have to do, the things that are HBP'd admittedly don't get drilled as fast.

I think in the Granite Wash as well, we're still testing this.

We're not in -- right in the area that Newfield and Forrest and some other guys have drilled their [Marmiton C] wells.

Our acreage is farther to the east.

We think it has great potential, but it needs to be tested, and every one of these Granite Wash intervals is a new ball game.

So it's not like you can just go start drilling wells all over in every one of these intervals and be assured of success or be assured of the kind of returns, reliable returns that we expect from a development program.

So as we go forward, we're going to be somewhat tentative, I think, in the way you would look at it about this until we have a pretty good understanding of what is driving productivity of these wells and how that all works out.

With that said, we would love to spend more money in the Granite Wash.

We're trying to figure out ways to do that.

I think we will continue our program there.

It is though, HBP'd, and we have a little more time on it, and we're not quite to that point yet where we can put our foot down and say, "Okay, let's get a bunch of rigs out here and start drilling it."

I think we feel like we are at that position at the Bakken.

We feel that we are at the position in the Eagle Ford, and it's really time to start accelerating that to the benefit of our shareholders.

When we get to that point in the Granite Wash, we'll do it.

But we are not quite there yet.

Joe, what I really -- this is Tony.

What I really like about the Granite Wash is, it gives us a lot of flexibility in terms of managing our capital program, because it is HBP, and then while from an aerial extent it may not look as large as some other positions, what I like it about is you have these stacked washes and a lot of opportunity.

I think that the way to think about this is more in a 3D cube kind of model.

Each of these washes can be very productive in its own right.

And we just simply have to, focus on the testing to determine the ultimate productivity of the play.

But we really like the position we're in there.

We think we're right in the heart of the fairway.

Okay.

So it sounds like -- if I hear you correctly, so it is a combination of -- even though the rates of return may be as good as in some of your other plays, it is just -- it is early days, you are HBP'd and so there is no urgency to drill it, whereas in these other -- Eagle Ford and Bakken -- you have got some acreage holding limitations.

But there's also -- I guess it is scalability and repeatability of these -- the Eagle Ford and the Bakken that really make you pursue those plays.

Sure.

I think people mischaracterize the Granite Wash as a resource play.

It is a resource play, but as Tony said, it is in a number of different intervals.

So it is not one big monolithic thing that you can go out and just start drilling wells everywhere and expecting them all to work.

I think for a Company like ourselves, we are going to do the technical work it takes to make sure that we're drilling a repeatably high-performance well before we start spending a lot of money.

That is just the discipline.

Okay.

Very helpful.

Thank you.

You bet, thanks.

Our next question comes from the line of Nicholas Pope with Dahlman Rose.

Please proceed, sir.

Good morning, guys.

Good morning, Nick.

Hey, I was hoping you could go through a little bit -- just a lot of discussion about the Anadarko joint area and what CapEx requirements are going to be.

I guess, could you go into a little bit of, I guess, what kind of options you have as Anadarko looks to ramp up activity in terms of being able to go nonconsent on wells and back end interest and everything.

What kind of flexibility do you have there in that joint interest area?

Well, essentially we own the acreage that we've earned, and those are now divided, I believe, into 15 different joint operating areas.

Each one of those joint operating areas has provisions associated with non-consenting wells and maintaining uniform interest and a number of typical JOA-type language.

So we can essentially deal with this as 15 separate little plays at this point in terms of how we deal with the issues you've mentioned.

The options here -- we can bring in a partner for ourselves.

We could sell it.

We could nonconsent wells that we don't like.

We have a number of different opportunities here to try to hybrid -- again, to increase returns, if we choose to do that.

We're not quite at the point yet where we've made a decision on how to do that.

It is a significant amount of capital, and it is non-op which, clearly, is not particularly consistent with our strategy of being largely operated.

But, it is really oily and some of the wells are really good.

So you -- I'll point you to Anadarko's transcript from yesterday.

I mean, they are really proud of this.

And there's certainly some areas that they should be.

And so we're considering our options.

We're looking at what they're doing.

We're very interested in their process and how that turns out and the kind of values that they get, or might get, and the kind of terms they get for that.

And clearly we're testing the market a little bit, talking to people, but we're not quite at the point yet to pull the trigger on what we're going to do.

But it is an issue for how we manage our capital next year.

It is not quite ripe yet, I guess that I would say, but it is getting close.

Okay.

That makes sense.

And I guess when you talk about the option of going nonconsent, is that something that you have a nonconsent you will back into your interest, or do you potentially lose acreage if you go nonconsent?

No, it depends on what kind of a well it is.

If it's an acreage earning well, you'll lose what acreage was being earned with that well.

If it's just a normal unit well, you lose your interest, you end up in, like, a nonconsent case in that particular well, and essentially you lose the value of the well.

But it is an option, certainly, if you have areas that you don't like or they are not performing or you are running short of CapEx and you need to high grade your program, you can certainly do that.

It's just in the areas where you are drilling earning wells, if you don't participate there, you may lose a larger portion of acreage.

So it's something that's got to be carefully managed, and it is certainly something that we're thinking hard about.

Recent JV's have been done in the area.

Wow, there are some really big numbers that people are paying to get into some of these, and I think you have to look at that real closely and decide, okay what are we going to do.

And so that is where we're at.

That is helpful I appreciate it.

And just kind of following on to that, going through the capacity, the infrastructure capacity that they had in the area, can you just go through those numbers again really quick?

I'm sorry, I think you went through them kind of fast earlier on the call, but in the Eagle Ford shale, what is your capacity --

Sure.

We've said a number of times on a number of calls that we felt we would be at 80 million a day capacity by the end of the year, and we still think that's about right.

And I mentioned some numbers specifically, I'll refer you to the transcript.

Where we're at, just in the last few weeks, we're making progress towards getting to that 80 million a day, and I think we'll have that much gas to produce by the time we have that capacity, which will just be in a few months here, or in a few weeks, actually.

As you go into next year, we're negotiating, and we're in advanced negotiations, I should say, with a party to allow us to produce more gas, so that we'll be able to continue to ramp our production up.

The Kinder Morgan/Copano pipe shows up, supposed to be in July next year, around mid-year, and we have some ability then to start shipping on that pipe.

So we're going to have an amount of capacity before that.

And then we'll have some obligations, actually, to Kinder Morgan.

So we're looking at that whole thing trying to understand, okay, what is the right build rate so that we keep the pipe full, don't pay any ship or pay obligations, meet all our commitments, meet our leasehold.

There's a number of different factors that go into this, but I think you can anticipate us having a pretty steady ramp of production.

This is going to be huge.

If you look at it a couple of years out, this going to be a very, very large portion of our production and probably be as big as the whole company is today in a few years and so --

Excellent.

But it is going to be a steady ramp to that point.

And did you all have any constraints during the quarter that limited production in the Eagle Ford or --

Yes, we did.

We were limited at various points during the quarter.

And to lower numbers and we just have kind of been overcoming those one at a time as we step our way up to this 80 a day, and then I think you will continue to see that step its way up over the next -- over the next year.

Excellent.

Thank you, guys, that's all I had.

Thanks, Nick.

Our next question comes from the line of Mike Scialla with Stifel Nicolaus.

Please proceed, sir.

Good morning, guys.

Good morning, Mike.

Nice quarter.

Thank you.

Jay, I've been pestering you for the last several quarters to try to pin you down unsuccessfully on an EUR for the Eagle Ford.

I guess given it is an area that you are ramping up and allocating the most capital, what all are you modeling in terms of well economics there in the gas condensate area?

Well, it is a good question.

We're in our reserves process right now, and we'll be booking year-end reserves here in just a few weeks.

I think we have commented publicly that we agree that Anadarko's comment that a 400,000 barrel well, what, that's about a 2.4 bcf well, I think those are very reasonable numbers in the northern portion of the play.

We have done some work recently in the more southern areas, say in the Galvan area, some [pecket trangent] work that would indicate to us that we're probably being too conservative on our reserves there.

And so I think you will see higher numbers than that in the Galvan area, and the Briscoe, I think that number I quoted earlier is probably a reasonable number.

So it varies, but clearly the southern areas, as you get closer to the reef, you get deeper, you get higher pressures, they have higher reserve numbers.

They also get dryer, so the economics don't necessarily work in your favor.

And they are a little bit more expensive.

So, I think there's -- in terms of your economic issues, all I can really say there is deeper, dryer stuff is more expensive, but it is bigger reserves.

The shallower, oily stuff is cheaper, but smaller reserves, and I think we'll probably -- I'll probably reserve all of the rest of the comments until after we get our reserve numbers in at the end of the year.

Thanks, that helps.

In terms of the Bakken, those two rigs -- one of those still running in Divide County or where are those rigs operating now?

And how do you feel about the Divide County acreage now?

Well, we're real pleased with it.

We just acquired some more acreage in that area, and I think we've been very pleased with the wells.

As we've said on previous calls, those wells are about $1 million cheaper than wells in the main portion of the Bakken/Three Forks play.

And although they don't have as big an IP's, they are holding in real well for us and we're performing above our type curve for the area, which was built based on taking 1.8 times a whole bunch of 640-acre wells that were drilled up there.

We're drilling longer laterals.

So we're pleased with it, and it is going well and, yes, I think we have -- I'm not sure we have a rig drilling up there right now --

Yes, we have one rig there and then one rig down in our Raven prospect.

Okay.

And then moving over to the Haynesville, you mentioned those two wells were restricted, and you talked about very high pressures.

Can you say what choke size or pour pressure you are seeing in those?

Well, they -- they've both come on and been producing for a significant period of time well above 8,000 pounds.

These are really good wells.

I mean, we've talked to people in the play.

People don't talk so much about the big IP's anymore, people -- almost everybody is restricting choke settings, and we've compared notes, and these wells are making between 10 million and 13 million a day, at 8,500 pounds, coming on 8,500, 8,600 pounds and hanging in there above 8,000 pounds for a long time.

These are good, good Haynesville wells.

Unrestricted choke.

Unrestricted chokes, say 18, 19, 2064s kind of chokes.

So we're very pleased with what we've seen.

We think it indicates that there is a significant resource potential there in our acreage.

Obviously, if we didn't have to, we probably would not be drilling these wells right now, but as I mentioned, we're not really paying for this.

There is no cost incurred for these two wells because we're being carried on both of them.

Can you say what the well costs were on those?

They were in excess of $10 million.

Okay.

I wanted to ask too on your -- you've obviously focused more on liquid-rich areas here, any plans to start breaking out the NGL's in your production stream now that you are hedging NGL's?

Or can you tell us what the NGL breakout was for the quarter?

Well, we're -- that's a good question.

We're certainly looking at that.

We account for it, frankly, the way we're supposed to right now given our contracts that we have.

So you see it in the price, as opposed to the production stream.

I would say that the third quarter from from an economic standpoint it was pretty close to 50/50 if you look at dry gas versus liquids, but I would ask you to stay tuned on that.

We're steadying that as we speak.

Let me ask one more along that same line.

In the Eagle Ford you talk about 12.50 BTU gas.

If you -- what does that equate to in terms of an NGL field if you have a cryogenic plant stripping those?

Well, I think that 12.50 is probably about a 5 gpm, 5 point something gpm yield, if I remember right.

A little lower -- maybe a little lower than that, maybe a little lower than that.

Those are ballpark numbers.

It's about 5 gpm.

Great, thanks.

Thanks.

Ladies and gentlemen, that concludes the Q and A portion of the call.

I would now like to turn the presentation back over to Mr.

Tony Best for closing remarks.

Thank you, Jeff, and thanks to everyone for your interest in SM Energy.

We'll talk to you again next quarter.

Thank you for tuning in this morning.

Ladies and gentlemen, that concludes today's conference.

Thank you for your participation.

You may now disconnect.

Have a wonderful day.