SM Energy Co (SM) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the SM Energy third-quarter 2014 earnings conference call.

(Operator Instructions)

Please note this conference is being recorded.

I would like to hand the conference over to Brent Collins, Senior Director of Planning and Investor Relations.

Please go ahead.

Thank you, Karen.

Good morning to all joining us by phone and online for SM Energy Company's third-quarter 2014 earnings conference call and operations update.

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

These statements involve risks that 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 our cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call and the risk factors section of our form 10-K, filed earlier this year, and our form 10-Q, filed earlier this morning.

We'll also discuss certain non-GAAP financial measures that 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 terms probable, possible and [3-P] reserves and estimated ultimate recovery, or EUR, on this call.

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

The Company officials on the call this morning are Tony Best, Chief Executive Officer; Jay Ottoson, President and Chief Operating Officer; and Wade Pursell, Executive Vice President and Chief Financial Officer.

I'll now turn the call over to Tony.

Thank you, Brent.

Good morning, everyone, and thank you for joining us for the third quarter 2014 SM Energy earnings call.

We will be referencing slides this morning that we posted on our website yesterday.

I'll begin my remarks on slide 3 and share a few key messages for today's call.

Let me begin by saying that SM Energy is very well-positioned for the period of uncertainty we find ourselves in with respect to oil prices for two primary reasons.

First, we have a portfolio of assets that generate strong returns and can continue to generate competitive returns even in a lower commodity price environment.

A lot of companies claim to make great returns, but we actually deliver them as I'll show you in a minute.

Second, we have a very strong balance sheet that we can use to be opportunistic or to weather out a prolonged price downturn if that should come to pass.

Wade will discuss our balance sheet in more detail in a few minutes.

Next, we continue to see positive results from our enhanced completion program and our operated Eagle Ford assets.

This will not only increase the economics of our existing inventory, but it will likely increase the total amount of inventory in this very leveraging asset.

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

Third, we have added significant acreage in our Bakken/Three Forks and Powder River basin programs.

The area that we are adding to in the Bakken/Three Forks is in an area that is some of the best returns in the Company.

In the Powder River basin, we continue to bolt onto our core acreage position and we continue to delineate our sizable footprint in this basin.

Moving to slide 4, we are showing our cash returns on average capital employed for the last six months.

Earlier this year we showed this graph of the last three years and we were not just top quartile of our peer group, we were at the top of our peer group.

That strong performance has continued the last six months and we think this is an important metric to track in the current environment.

This graph shows two key things.

First, on a relative basis, it shows that we generate strong corporate returns.

And we obviously couldn't do that if we also didn't have strong returns at the asset level.

Second, it shows that we effectively allocate capital and manage our portfolio to maintain the strength of our balance sheet.

In the current market we think those two characteristics should be even more important to investors.

And SM Energy is a name that we believe investors should want to own going forward.

With that, I'll turn the call over to Wade for his financial review.

Thank you, Tony.

I'll start on slide 5.

We thought it would be timely to remind everyone about the strength of our balance sheet.

At the end of the third quarter our debt-to-trailing 12 months EBITDAX was 1.2 times.

Our covenant on our credit facility is 4 times.

So we're clearly in solid shape there.

Our bank group just increase our borrowing base to $2.4 billion from $2.2 billion, which demonstrates the success we're having in adding proved reserves.

Also the nearest bond maturity we have is in 2019.

So bottom line, the balance sheet's in great shape.

I will would also note that we compare quite favorably to our peer group, as you can see on slide 6. Also supporting our balance sheet is the healthy hedge book, a significant portion, actually over 90% through the middle of 2016 of our PDP oil production, is hedged with swaps in the low 90s and collars with $85 floors.

Our hedging program provides us the visibility to our cash flow and preserves our ability to adapt in a turbulent rocket.

Our updated hedge positions can be found in the appendix of this presentation.

I'll now recap, real quick, our quarterly results on slide 7. As we pre-released a few weeks ago, production for the quarter came in at 142.5 thousand barrels of oil equivalent per day.

While overall production was at the lower end of our guidance, oil production in the third quarter hit a new quarterly record for the Company, a demonstration of our product mix shifting toward oil.

With the exception of LOE, costs came in close to our guided ranges.

On that metric, higher than expected work-over expense, combined with lower production volumes, drove results above our guidance.

Adjusted EBITDAX was $406.2 million for the quarter.

And GAAP net income came in at $208.9 million, or $3.05 per diluted share.

Adjusted net income was $1.44 per diluted share.

You can see a lot more detail in our form 10-Q, which was filed earlier this morning if you would like.

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

Good morning, everyone.

While we know that the biggest concern in the investment community right now is probably about the direction of oil prices; however, we really want to share a few important updates on our operations.

First I'd like to highlight the consistent improvements we're seeing in Eagle Ford well results.

Slide 10 in the presentation is a map showing four areas in which we have sufficient data at this point to make comparisons between our old and new completion designs in the Eagle Ford.

We've updated the data for recent production and are happy to report that we're seeing sustained higher production volumes in every area.

This will translate to higher recovery levels and better economics as our higher sand volume frac jobs are now being completed at essentially the same cost per lateral foot as our previous jobs due to continuing improvements in pumping efficiency.

These improvements mean that our Eagle Ford program can continue to generate economic returns and growth with even lower commodity prices.

Moving to slide 12, in October we were able to bolt on an additional 12,500 net acres to our recently expanded acreage position in Divide County, North Dakota, in the Bakken/Three Forks play.

We've been encouraged by some solid results we've seen from several recent Three Forks wells completed by the previous operator of our newly acquired acreage and we're moving in now to complete additional wells and also flowing back some recent Bakken completions in the area.

Our well costs continue to be in the $6 million range in that area and well economics are some of the very best in our portfolio.

In the Powder River basin we added an additional 5,000 acres through several smaller transactions during the quarter.

Our dynamite well, which is a test of the very deepest portion of our acreage position, had an encouraging initial test rate of 890 barrels of oil equivalent per day during the quarter.

Another important data point in the PRB is that we drilled our last long frontier well -- last long lateral frontier well -- in 40 days, which is a record for us and faster by about a third than our first few wells.

We're well on the way to capturing the kind of cost reductions we've forecasted for the play while we continue to work on delineating the acreage and on optimizing our completions.

We don't have any slides specific to our Permian or East Texas area operations here today to keep things brief, but let me just talk about them for just a second.

Our Sweetie Peck Wolfcamp shale development continues to be a great program with excellent well results.

We completed four wells on our acreage during the quarter.

I will note that we've moved to gas lift as our initial method for artificial lift at Sweetie Peck due to continuing issues with run times on the electric submersible pumps we've been using.

And that change will impact our reported initial rates on newer wells.

However, our newer wells are performing as well or better than our older wells over time.

In our East Texas prospect we're construction our gathering system now and expect it to be completed by year-end.

We don't have any exploration test results in either area to report this quarter.

With respect to production, our third quarter was an unusually difficult quarter to forecast and we were a little too optimistic with our guidance.

Our production, while still recovering as we entered the fourth quarter, has been up nicely in October and we expect to grow production 9% quarter-over-quarter.

As we look ahead to 2015, it's important to note that our internal assumption for some time has been that oil prices will cycle around an $85 WTI price.

This assumption has driven the choices we have made about our portfolio and our approach to hedging and managing the balance sheet.

Our major developments plays generate good returns at oil prices below our mid-cycle call at current costs.

And in a prolonged lower oil price environment, we're likely to see service costs move lower as well.

We're still guiding 20% production growth in 2015, which will be disproportionately oily.

We're in the middle of our budget process as we speak and we'll announce our budget in mid-December.

We do have a lot of flexibility to alter our plans if market conditions deteriorate substantially at any point.

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

Thank you, Jay.

Before handing the call over for your questions, I'll highlight what we think are the key take-aways from this call.

First, SM Energy is well-positioned for the current environment.

We have a portfolio that continues to generate strong returns and that is supported by a strong balance sheet.

Next, we are continuing to see strong performance from our enhanced completion program in the operated Eagle Ford, as Jay just discussed, which we expect will lead to improved returns and expand our inventory.

Finally, we've added additional inventory in the Bakken/Three Forks and Powder River Basin programs, which provides incremental oily inventory for SM for years to come.

On a personal note, today is my last earnings call with the Company.

SM Energy has been dramatically transformed since I joined in 2006.

I believe the Company is incredibly well-positioned for the future with its high-quality asset base and talented and dedicated employees and management.

Leading a public Company and working regularly with investment professionals like all of you has been of a tremendous privilege.

It has been the highlight of my 35 years in an industry that I love and am proud of as we continue to provide critical energy to this country.

I want to thank those of you in the investment community for your support over the years and wish you all the best of luck in your future endeavors.

Now let's open the call for your questions.

Thank you.

(Operator Instructions)

Pearce Hammond, the Simmons Company.

Tony, congratulations and best of luck and a wonderful retirement.

Thanks a lot.

My first question is about oil production.

I know you don't guide specifically to that for Q4, but I was wondering if you could provide some color because there's several things going on.

Obviously you put in the release, a nice uptick in your Eagle Ford oil production and some of those shut-in wells have come back.

But you've also got the Bakken transactions, the timing of those and the production that that adds.

So how should we think about oil production for Q4?

Pearce, this is Jay.

In generally, we're going to be seeing disproportionate oil growth over time so the 9% quarter-over-quarter numbers should be disproportionately oily.

I will say, and I think you can tell this from looking at our Eagle Ford production numbers, we had a lot big gas wells in the Eagle Ford shut in during the third quarter.

So those will be coming back on.

It's not as easy as just -- okay, we know oil's going up.

I can't tell you the exact percentage.

It just depends on how fast things ramp back up.

Okay.

Perfect.

And then you mentioned in your prepared remarks, Jay, the flexibility to respond to lower prices.

Can you provide some color around some of that flexibility, either around rig contracts?

How much flexibility do you have as it relates to service commitments, acreage holding, things like that?

Well that's -- there's two different questions there.

One is how much flexibility we have with respect to acreage holding, and the other is with respect to rig contracts.

With respect to rig contracts, we could probably be at half our rig count by year-end based on the rig contracts we have.

So we can shut down pretty fast.

And that assumes that you're not willing to pay any fees or any stand-by fees.

So we can get our rig count down pretty quickly if we need to.

On the acreage holding side, it varies a lot by area.

We have some shipper pay comments in the Eagle Ford.

We have some acreage holding in the Powder.

But in general, most of our rigs are working on HBP to acreage.

Our Bakken stuff is almost all HBP.

Our Permian stuff is essentially all HBP.

So again, we could reduce our activity level substantially pretty fast if prices really go in the tank.

Great.

Thanks so much, Jay.

Pearce, I'd mention one other thing.

If you recall 2008, 2009, we had a plan to do exactly that and we went from something like 13 rigs down to 3, not knowing where the bottom of the recession was.

So I mean, we have experience working through a down market and certainly could apply that again if need be.

I'll tack on some more, Pearce.

Clearly, though, we're not in knee-jerk mode here.

We're going to have to be convinced that you're going to have to see low prices for quite some time before we start really jerking our program around.

Welles Fitzpatrick, Johnson Rice.

First off, congratulations, Tony.

It's been great interacting with you and, needless to say, congratulations on all the changes that have gone on in the Company during your tenure.

Thank you.

In Gooseneck, can you talk about what you guys are thinking on spacing?

If I remember correctly, there was some thought on lease-line drilling.

And also, do you see a shift in water cut as you move south on the newer acreage?

This is Jay.

In terms of spacing, we've been targeting about four Three Forks wells per spacing unit.

And we're thinking about something like three Bakken wells per spacing unit.

We still have to prove up the Bakken.

We don't really know what the water cut will do as we go south on the acreage yet.

Again, we haven't tested a lot of that southern acreage.

I don't expect it to be significantly different.

If you look at the G&G maps, it doesn't look that different as you go across the acreage.

Perfect.

And then just one more, if I could.

On the area one, obviously that update looks strong.

Are those on -- if I remember correctly -- broad pump versus gas lift have been somewhat of an issue.

Did you get electricity in there and are those on rod pump or gas lift?

Those wells are still flowing, actually.

The last I checked.

And we will need artificial lift eventually and we will be putting them on rod lift eventually.

Okay.

Great.

So electricity is no longer an issue in area one?

Well in that particular area we're going to run a local generator, as I understand it, to be able to do that.

In the long run, we're going to have to electrify must much of the western portion of area one.

Perfect.

Thanks so much.

David Tameron, Wells Fargo Securities.

Also, Tony, congrats and best of luck in your next adventure.

Thank you, David.

If I want to go back to the Eagle Ford, I'm just trying to figure out what this looks like going forward as far as -- I assume this issue or logistical issue of shutting in wells, offset wells, and bringing pads online -- I assume that's going to be an ongoing logistical -- out in the field.

So I'm just trying to figure do we -- should we expect to see more lumpiness in the production?

Should we expect that to smooth out in the fourth quarter?

I'm just trying to figure out what the impact was because you're growing about 5,000 barrels a quarter -- or you had been.

Maybe a little less than that on an operated basis.

But just trying to get a handle on that going forward.

Can you help me at all with that?

Sure, David.

This was an unusual quarter.

We actually had deferred some work out of the second quarter into the third and we had a very large number of infill, or close to wells, large wells in the Galvan area that we had to shut in during the quarter.

And a lot of logistics associated with that.

So it was a really difficult quarter to forecast.

And, frankly, the guys in the field had it right.

We were just a little too optimistic here at corporate on how fast we thought we could get the worked done.

They did a terrific job, no incidents, did it within budget, all the things that they said they would do.

I don't think this is -- you should think of this as something that you should, on an ongoing basis, discount our production for.

It was a very unusual quarter in terms of the number of large wells we had shut in.

We're also looking at ways in the field where we can hopscotch a little more and not have these big batches that we have to shut in.

So I don't think, again, I don't think you should essentially be risking our forward forecast based on this one quarter's performance.

Okay.

And any -- you said the production's back up.

Do you care to give us a range of where production is at the moment?

At one point in time, we had about 60 million a day of production shut-in plus all the oil and everything going with that.

And we've got almost all that back at this point.

Okay.

That's helpful.

And then going to the Powder, where -- what's the progress, and I know it's a one-offs well and you're going to start to get into more of a development drilling type, but what are current well costs out in the Powder?

Or how should we think about that?

We're still [AAPing] these wells and about $16 million because we're still playing around with our completions a lot.

We're actually increasing completion cost in some respects to try to make sure were doing the best thing.

We're going to be doing a sand job, as opposed to a high-strength prop in job here shortly, which, again, would be a much lower completion cost.

So we're still AAPing numbers in the $15 million, $16 million range.

The well -- when I look at this 20 day reduction at about a $50,000 wet spread rate, that's about a $1 million cost savings versus where we were.

And I would expect, all things being equal, that you would see our well costs in that $15 million range at this point, with all the completion factors equal.

The big opportunity, really, is to drive completion cost savings or completion cost improvement.

And that's really what we're focused on while we continue to make drilling improvements.

Okay.

Last question on that, the Dynamite well, did you -- you said it was 7,500 foot effective, was it a longer lateral and some of that just didn't get off?

It was it was a 9,500 foot lateral.

We got -- we couldn't get our pipe to bottom.

And we ended up not being able to effectively simulate the last 2,000 feet.

Okay.

So we were a little disappointed by that.

But in general, the process went really well.

We just couldn't get pipe to bottom at the end.

The interesting thing I think about Dynamite is it really does connect up the dots.

When we look now at this resource, it's really clear that we have proved up a very large oil and gas resource in that area.

We need to work hard here to make it economic across that whole acreage position but we really feel like we've proved up a lot of the area on the north.

Dynamite is our first data point, really, in the middle of this position and it is in the very deepest portion of the basin.

So again, we've proved up a very large resource and pretty encouraging early results.

And now we just need to work on it to make it more and more economic.

All right.

Sounds good.

I appreciate the color.

Thanks.

Michael Hall, Heikkinen Energy.

I'll echo the congrats of everyone else.

Best of luck, Tony.

I guess first I'll just -- back to the Eagle Ford quickly.

Can you review a bit more as to what all -- what variables have all been changed within the completion enhancements and how that might vary from area to area?

Any additional color there?

Well we've shown a lot of data on that in previous releases about a specific areas.

Area 2, we'll start with those.

Those are the ones we have the longest data on.

Those wells where essentially the same lateral length as the wells we've been drilling before but just higher sand loadings.

And you see that continue to sustain significantly better performance and Area 2. That's probably the longest data set we have.

The other -- Area 1, we mentioned on our last call, those are longer laterals as well.

So longer laterals and bigger sand fracs and those wells are continuing to look really good to us and really encouraged by the results.

Area 3-B and Area 4, those are more similar lateral lengths -- a little bit longer but not a lot and, again, higher sand loadings.

What's interesting, I think, and it's particularly in Area 3-B, this is an area where we typically choke manage these wells.

So we restrict rates initially.

So you were seeing higher flowing pressures very early on the newer wells but not higher rates.

But here as we go out in time now you're starting to see those wells outperform on a rate basis as well.

And that's just a function of the fact that these are much more conductive frac jobs that we pumped.

So actually I think that's maybe the most encouraging data in the whole data set.

It really tells you that this stuff is sustained, that you're really connected better -- to the reservoir in a better way.

So really encouraging.

So in the long run, all this is going to translate to higher EURs and better economics.

Great.

That color on 3-B answers another question I had.

So thanks for that.

And I guess as it relates to these changes, have you changed landing zone at all in any of these as well?

Or are you generally staying in the same zones here?

Just curious if --

That's a great question because it leads me to another point.

Most of these were landed essentially in the typical areas we've been landing in the lower Eagle Ford.

Now we are experimenting with other landing zones.

We haven't shown data on it yet because we don't have enough data to show.

But we are looking at higher landing zones and alternating landing zones in a couple different areas in the Eagle Ford to look for opportunity to squeeze wells closer together and to, frankly, just put more wells into the upper Eagle Ford.

And we should have more data on that coming up over the next few calls.

We do have a really thick section in the Eagle Ford, especially as you go north on our acreage.

Right.

Okay.

And then as it relates to the shut-ins -- if I think about it as cycling of wells on and off for offset completion activity, are you seeing -- are the wells coming back as you would expect?

Are you seeing any potential harm to the fraction networks as you look at the data?

Or is there any kind of coming on as you would expect?

Well fortunately most of these areas that we were doing this work were in the southern area where we have pretty high pressures.

These are still relatively new wells and pretty -- not a lot of liquids production.

So I haven't had any damage on this reported to me.

You're right, of course, that when you're fracking in between older wells that that's always a concern.

That's why we shut the wells in in a good area around there.

In a lot of cases, people actually load wells with fluid in order to prevent damage.

So far we haven't seen that here but it is a concern.

It's the reason we're cautious about how many wells we shut-ins.

And, frankly, as we go through that process, it creates uncertainty in risk associated with forecasting.

That's certainly something that we underestimated just a little bit here this last quarter.

Fair enough.

Okay.

And hopping up to the Williston, as we think about 2015, you may have provided this commentary in the past but kind of remind me, if you would, how much of the activity, maybe just on a percentage basis, would you say would be Divide versus Mckenzie or Raven and Bear Den?

I think the easiest way to think about it is about 50/50.

It varies a little bit during the quarters depending on where our rigs are at.

And we've been running three rigs so it's hard to split a rig in half.

Right?

So there's two and then one.

I think as we go into next year, we're going to be at a five or six rig type count.

That's our current plan, anyway.

And that activity will be split pretty evenly between Divide and other areas.

Clearly we picked up a lot of acreage in Divide.

We're excited about getting an opportunity to drill more wells there.

That's helpful color.

Thanks.

Last one on my end, in the Williston do you potentially know how many -- roughly how many PDP locations per DSU you've drilled down in McKenzie at this point?

Well I don't know that number off the top of my head.

So I don't want to venture a number.

We're testing down to about four -- again, four Three Forks wells per spacing unit.

I don't know that we've got very many of those done.

Yes.

I figured.

A little down on the -- I'll just follow-up off-line.

Thanks, guys.

Appreciate it.

John Nelson, Citigroup.

Just thinking ahead to the year-end resource update that we'll get with next quarter, I'm just curious as you think about the Eagle Ford assumptions that will be given out.

Do you still plan to average that from all wells seen to date or is there any desire, given all the positive results you're seeing with upsized completions, to maybe breakout what could potentially be done if we just only drilled upsized completions going forward?

Thanks for asking that because it's a point I wanted to address if I had the opportunity.

What you're going to be seeing from us at the end of the fourth quarter -- the last couple years we've kind of given these inventory dumps where we just dump a bunch of average data.

I think, forward-looking, you won't see that from us, at least in that format.

And we need to really think through how we want to talk about inventory.

And so you're probably not going to see that in that same format this next year.

Certainly we're looking at our Eagle Ford results.

I think as you look at public data on our wells, and you look at our acreage count, people can do math.

We're going to assume people can do math.

(laughter)

So I'm not sure.

Sometimes we give information that isn't actually all that helpful for people and we're going to re-look at all of that.

Fair enough.

Any thoughts on how long of a production history you would want to see out of the Eagle Ford before making some changes in what you communicate?

Or general thoughts in that regard?

Well you need at least -- I think at least six months worth of data to really be able to get a decent EUR on these wells.

And so we'll need to see that.

We're going through our reserve process right now for our year-end process and we'll see how much data we have.

And we're certainly going to be willing to talk about our economics and how we see these wells.

I just think we are going to re-look at the way we've been disclosing some of this information.

Yes.

Fair enough.

And then I just wanted to circle back -- you mentioned in 2015 that growth would be disproportionately oily.

Just hoping maybe you could put some context around that even if it's a big ballpark.

If we're 20% total, are we talking 25%, 30% oil or just sort of any thoughts there?

Yes.

I think we've already publicly said we'd be somewhere between 30% and 40% oil growth.

15 over 14.

15 over 14.

Great.

That's all for me.

Thanks a lot and congrats, Tony, and best of luck on everything ahead.

Thank you, John.

Jeb Bachmann, Howard Weil.

Congrats, Tony, as well.

Thank you, Jeb.

Jay, just starting up in the PRB, just curious on the arrival of that fourth rig.

I think originally guys were talking end of the third quarter, now it looks like by year-end.

There's any -- if you have any commentary about that.

Well we had that fourth rig working on an expiration test and it was delayed a little bit.

So it is a little delayed coming back.

I will say that in terms of our rig counts in the Powder given that we are drilling these wells about a third faster than we expected, probably ought to focus more on completion numbers than on rig count.

I think we'll end up with the number of completions that we expected to have this year and next year, probably with a slightly lower rig count than we had originally anticipated.

Okay.

And then if you just remind us on the geology in PRB as you move from north to south and the productivity per lateral foot -- obviously looks better in the north versus south.

If you could just give some commentary on that.

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

We do know that the northern area looks good.

We don't have much data in the middle.

And then on the far south end we have some pretty good wells down there that we drilled by ourselves and with others.

So I don't know that we have enough data in the center portion of the section to really characterize that.

We see significant overpressure pretty much everywhere.

We see oil and gas everywhere, gas to a varying extent.

Most of these wells have come on pretty oily and then the GORs will increase over time.

At least that's what happened in the vertical wells, so that's the way we forecast them.

Still a little early to characterize the overall geology of the play, I think.

Okay.

And then just switching over to the Permian, just wondering if you have any comments on the D and the thickness you saw there in that well as well as kind of lateral length and the [similar] amount of that lateral as we wait results on that well.

You're talking about the D well up at Buffalo?

The [UL] well --

Yes.

I'm sorry.

Up in --

The D is a little thicker up there than the B. I don't remember the exact thickness but it was a little thicker than the B section.

And it's a little more mature as well.

And it's a -- I believe it's a 7,500 foot lateral.

And again, we drilled that well jointly with two other parties so, and I won't name them I guess, but we end up spending about $3.5 million net on that test.

And so you're able to stimulate the entire 7,500 feet?

Yes.

We got our job away and we're flowing back.

Okay.

Last one for me.

I guess just looking at overall valuation, I know you guys get this question pretty often.

But any thoughts on ways to improve that, considering your execution has improved here recently?

Just wondering if there are assets that maybe looking to divest -- kind of core up in the Eagle Ford and the Bakken and the PRB?

I do think focus is a continued question that we get.

We don't spend that much money outside our core programs.

So it's a little -- I don't think this is really a question of concentrating our capital.

I do think that you will continue to see us focus the asset portfolio.

We do this every year.

We've sold $1.5 billion worth of assets over the last four or five years.

And that's certainly something we'll continue to do when we see opportunities to do it.

We are running a very focused capital program.

And our production is very focused as well.

But we're going to continue to focus the program.

We look at our valuation all the time.

We think it should be better, quite frankly.

We don't think -- I don't want to be defensive about this but I think people don't give us enough credit for the kind of high returns we make in our program.

That's what we talked about it so much today.

But I do think, over time, people will come to appreciate that.

And certainly we are going to work to continue to focus on high return, big inventory projects that we can get into at reasonable costs.

All right.

Great.

Thanks, Jay.

Matt Portillo, TPH.

Just a quick update.

I was wondering if you could talk about your upsized fracs that you've implemented in the Bakken and how those wells have been performing with the longer-term data that you've seen so far.

And then in regards to some of the bigger completions that you are looking at, where those sit in terms of providing incremental data on potentially doubling the profit volumes and some of the tests you were looking at on the state line?

Well I'll address that in three parts.

First of all I think we showed data a while back about some of our increased prop concentration jobs in Gooseneck and with good results.

And those wells continue to perform well.

Probably the latest thing we've really moved to in the Bakken is we have moved to plug perf essentially on almost all our completions.

We're still not cementing our liners in a lot of cases.

But are -- have moved to plug perf and more stage -- and a higher stage count on a lot of these wells.

We don't have a state line well flowing back yet so I can't really comment on results there.

But we are looking at higher prop concentrations.

Not to the extent we do them Eagle Ford but certainly relative to our other Bakken results.

And we're moving to alternative entry point methods in the Bakken.

Great.

And then just a quick follow-up.

In regards to the down-spacing comments you made earlier on the Eagle Ford, if we look at where your wells have averaged on the previous data you provided from an inventory perspective, you're probably 200 feet wider than probably your offset peers in the basin.

I was curious if you could provide any context around some of the down-spacing tests you're currently looking at and how tight those ultimately are from a spacing perspective across a couple of your different areas in the Eagle Ford.

Well first comment I'll make is we've seen some of our offset peers going the other direction recently where they've actually been widening out there spacing.

But in the gassier areas on the southern end of our position, we typically drill these well at 900 to 1,000 foot offset.

I don't think that's going to change.

Eagle Ford's not that thick down there.

We are varying landing zones to see what we can do their and that might allow us to push some of these wells closer together -- too early to say.

In the northern areas, originally we had talked about drilling these wells at 425 foot offsets.

The last couple wells we drilled were at 550 foot offsets.

Again, I think this is where we had the biggest potential to push those wells back closer together by varying landing zones and including some upper Eagle Ford wells in there.

So that one -- I think there is a significant amount of upside in that, we just haven't proven it yet.

We need to do that.

Perfect.

Thank you very much.

Mike Kelly, Global Hunter.

Tony, first off best of luck.

It was a pleasure covering you here over the last two years on the sell side.

It was even more of a pleasure being a shareholder when you turn this Company into really a leader on the resource development side of things here.

So best of luck and congrats.

Thanks so much, Mike.

First question is, Jay, I was hoping you could give us your thoughts on what gives you comfort and confidence to continue to add acreage in the Powder and ramp-up to four rigs, given the current oil price environment and the fact that well costs here are still relatively elevated -- starting at $15 million a pop?

Well great question.

I'm sorry to say great question all the time, but it is a really good one.

This is a long-term business.

And I know that oil prices are back where they were in 2012 now.

But Tony was saying he's been this business 35 years.

I've been there close to that.

We've seen these cycles before.

You've got to have a long-term perspective on this.

What we've found in the Powder is a very large oil and gas resource where we've been able to establish a very dominant position over a big area.

And that's not that common.

And so you've got to take a long-term perspective on this.

They're federal leases.

They have very good royalty provisions associated with them.

This is an area where if you do this right and really focus your efforts on reducing costs and getting efficient, we can make some high returns over a cycle.

Our view has always been that oil prices would vary around about an $85 midpoint.

So prices being $82 doesn't scare us.

We plan our business around these kinds of cycles and, frankly, around oil being about where it is right now.

So we think there's significant economic potential in the Powder.

We think we've captured a loss of it.

And we're just going to keep grinding on it until we make these wells as economic as everything else in our portfolio.

Okay.

Great.

On the returns front, you guys highlighted multiple times in today's call you're very confident in what you're getting in the Eagle Ford and up in Divide County in the Bakken.

But maybe if you could really quantify that -- take it one step further.

I think you guys have what comes out to be about a 25% hurdle rate on your IRR's on the project level.

What's the oil price that is necessary to get those types of returns up in Divide, in the Bakken and then in the core part of the Eagle Ford where you're putting the capital to work?

I understand why you're asking that.

But we don't want to get into how low can you say you can go limbo contest with our peers because there just never seems to be a great correlation between the numbers we hear people quote and their actual corporate returns.

However, if you look at public data, on our actual returns, as we show on that slide in the deck -- I think it's slide 4 -- that date would indicate that our programs have been generating very high returns and that we're able to maintain, therefore, acceptable returns at prices significantly lower than most of our peers.

And our wells are getting better over time.

We've shown you that in repeated quarters over the last few quarters.

So we're not going to talk specifically about what returns we make at what oil prices and try to compete with people on, frankly, data we don't know how they are calculating those numbers.

But we can make good returns at prices lower than we're currently experiencing.

All right.

I think that's fair enough.

Well said.

Quick one from me just in east Texas.

After the gathering system is up and running there, what is the plan?

Well we're going to get some long-term tests on the wells we've already drilled and see what that initial decline rate looks like.

That's the one piece of data we really don't have.

We weren't able to test them for a long period of time because of [earning] restrictions.

So we'll get a bunch of those wells on task for a long period.

We're going to drill -- we have a plan to drill some turn-and-go type wells in there next year to see how low we can get the well costs.

So about midyear next year I think we should be at a decision point on whether we go -- how we go forward with the project.

Great.

Thank you.

Mike Scialla, Stifel.

Tony, congrats and best of luck from me as well.

Thank you, Mike.

Jay, I hope you don't take this as a limbo, how low can you go, but just trying to get a sense where you said $80 or $82 -- really doesn't change anything.

Just knowing that it takes usually some time, if prices were to go lower, for service costs to come down.

Say if oil were to go to like $75 or something in that range, would that cause you to change your plans for 2015 at all?

Mike, again, you look at our -- if you look at our balance sheet and you look at our programs, we're not going to over react to a short-term period of lower -- of $5 lower oil prices.

We have a very solid program and our execution is good.

We'll drive on.

Now, clearly if you see sustained lower prices, you'll also see lowering costs.

So we'll factor that in.

We'll be looking at a number of variables with respect to our balance sheet and our borrowing base and a whole bunch of other things before we make a decision on how we tweak that program.

At this point, we don't see any reason why we would deviate from the programs that we've already discussed.

Mike, this is Tony.

Let me add one comment.

I think folks focus on price -- commodity price.

But we also take into account duration.

And it really depends on both factors.

You don't adjust your entire drilling program, potentially drop rigs and really good crews that we've built up and added over the years, for just a blip in price.

So we really do look at duration as well.

And that's exactly what occurred in 2008 and 2009.

And we'll take the same approach this time.

If this is an extended downturn, we see that duration continue with low prices, then certainly we have the flexibility to adjust our program accordingly.

That's helpful.

Appreciate that.

Wanted to ask you on all the wells you've drilled at Sweetie Peck so far, have those all been in the same zone or have you tested more than one Wolfcamp zone there?

All the wells we drilled so far have been in the Wolfcamp B section.

We currently have a lower Spraberry well that's being fracked and going to be flowed back here shortly.

And we're excited about that.

The lower Spraberry down there is a nice thick section.

It looks good on logs.

That lower Spraberry, was that in Buffalo or was that in Sweetie Peck area?

No.

That's in Sweetie Peck.

We may very well drill a lower Spraberry well at Buffalo later on as well.

But this well is a Sweetie Peck well.

Got it.

Okay.

And then the assets you just picked up from Magnum Hunter in Divide, were there some new properties there or was that just increasing your interest in wells that you already own?

Essentially all of it was increasing interest in the acquisition we've made previously from Baytex.

They were a partner there in that acreage.

Got you.

Okay.

And have you tested the Bakken there yet or have those all still been Three Forks wells?

We're flowing back some Bakken wells ourselves right now.

And there have been some previous tests, not on the -- I don't think there's been any on the Baytex acreage but a little bit north of that.

So we're flowing back a few wells right now, should have results by, I would think, by next quarter.

Great.

That's all I had.

Thanks.

Joe Allman, JPMorgan.

Congratulations, Tony.

Best wishes.

Thank you, Joe.

On the completion design changes, Jay, in your second quarter conference call you indicated that in Eagle Ford Area 2 you were seeing a 4,000 basis point improvement in rates of return and in the Bakken at 2,500 basis point improvement in rates of return.

And then in Eagle Ford Area 1 you added the longer laterals.

What kind of improvement in rates of return are you seeing with that well?

We haven't calculated the number yet just because it's a little too early in terms of forecasting an EUR.

We've seen about 60% to 70% IP improvements in Area 1 so far.

You can see from the curbs there.

So we anticipate a significant improvement in returns.

We just haven't calculated an exact number yet.

Got you.

When you talk about 60% to 70%, are you talking about in that -- in the well with the longer lateral or --

There's three wells there in that -- in the [data set] Area 1. Part of the issue here is there's only three wells in the data set.

But in Area 1, the data we're showing there, there's 3 wells that were completed with longer laterals and upsized fracs -- about 2,000 pounds per foot -- versus about 20 wells in the red line, which were completed with shorter laterals and smaller fracs.

And what you see there over time is about a 60% to 70% -- maybe even a little more than that actually over time there improvement in early production rates.

And what we need to be able to do is get an [up data] there and a little bit of decline history so that we can forecast an EUR and get a forecast for at least the first two or three years production so that we can make an economic forecast.

The wells are a little more expensive because they're longer.

Again, as I mentioned in my text today, the cost per foot -- per lateral foot of the completions is about the same as it used to be because of increased efficiency.

But the longer lateral drilling does cost us a little bit of money.

So there is some -- we need to rerun those economics here as we have more data.

Thank you.

That's helpful.

And then are you leaning towards longer laterals throughout the program -- throughout your acreage in both the Eagle Ford and the Bakken where you can?

Well the Bakken we're drilling 10,000 foot laterals essentially everywhere.

We haven't tried to go beyond that yet.

That's something that we have to think a little bit about.

In the Eagle Ford we'll be up about 30% in lateral length this year versus 2013.

Our average lateral length in the Eagle Ford will be about 6,500 feet in 2014 versus 2013.

We are drilling wells longer than that in some areas where we can and with some success.

These Area 1 wells I just talked about averaged about 7,000 feet -- 7,200 feet.

So we'll push that where we can where lease boundaries allow.

But in general, about a 30% uptick in lateral length.

And that's 2014 versus 2013 on average you're saying?

That's right.

But you've only done it -- three wells I guess in the Eagle Ford.

So presumably in 2015 you would even go -- your average would be above that, assuming that this test works well?

Well, again, there are areas down in the southern areas of the field where we already have a pattern established where we're not going to be able to drill these 7,500 foot wells.

I think Area 1 where we don't have a lot of development already in place, we would -- yes, we would typically go to a longer -- probably the 7,500-type foot lateral lengths.

Okay.

That's helpful.

And then -- okay.

When you think about longer laterals, one thing -- I think some investors think one of the issues with SM is inventory.

And so, of course -- and it's better economics if you drill longer laterals but if your tests are successful -- but you also will lose well count.

And you may lose longevity of the drilling inventory.

So do you take that into consideration when you're planning how you're going to drill the wells?

Well we're going to drill the wells that make the best economic returns.

We're not going to worry about whether you we have 9 years or 10 years of inventory when it comes to that.

But we'll drill wells that make the highest returns and we'll find other sources of inventory.

I think what you've seen, and what we've said, about our Eagle Ford program this year is we originally had planned to drill about 100 wells -- drill and complete about 100 wells.

And now we think we'll drill and complete somewhere around 90.

We're going to end up, I think, with about the same reserve outcome and about -- and essentially the same rate outcome and about the same -- not that different cost -- a little bit lower cost, probably.

But we end up at the same point with fewer completions.

So there's a balance here.

But, again, we're going to drill what makes highest -- the most returns sense.

We're not so driven by well count inventory as we are by returns.

That's helpful.

Then last question, so beyond doubling the sand and drilling longer laterals, what other completion design changes are you testing that you'll be talking about over the coming months?

Well there's a lot of different ways to put more sand in wells.

Upping stage count is a way to do that.

We're looking at across our portfolio, not just in the Eagle Ford, but we're looking at a number of different refinements to completion techniques using coil tubing assisted techniques, for example.

Coil tubing shifted sleeves -- a number of different methods.

I think the biggest upside in the Eagle Ford, again, is the thickness of that section, the opportunity to place wells up and down, stagger wells, push spacing, generate value from the upper Eagle Ford section we haven't completed a lot.

We're also looking at 100 mesh sand versus 20/40 or 40/70 -- using more 100 mesh, which I think we are seeing some positive benefits there.

So we're doing a raft of tests across our entire portfolio to try to optimize our completions, just like everybody else in industry's doing.

Great.

Very helpful.

Thank you.

That concludes our question-and-answer session.

I would like to turn the conference back to Tony Best, CEO, for any closing comments.

Thank you, all, for joining us for the third quarter call.

Jay and the executive team will provide a fourth quarter update at our next call.

Thanks so much.

Thank you.

Ladies and gentlemen, thank you for your participation in today's conference.

This does conclude the program and you may now disconnect.

Everyone, have a good day.