SM Energy Co (SM) 2015 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the SM Energy first quarter 2015 earnings conference call.

(Operator Instructions)

As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Executive Vice President and General Counsel, Mr. David Copeland.

Sir, you may begin.

Thank you, Damian.

Good morning to all joining us by phone and online for SM Energy's first-quarter 2015 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 divestitures 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 the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted on our website for this call and the risk factor section of our Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning.

We will 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.

Company officials on the call this morning are: Jay Ottoson, President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning, Investor Relations, and myself.

I'll now turn the call over to Jay.

Thanks, David.

Thanks to everybody for joining us on our first quarter call.

We did announce our -- or preannounce our record production volumes for the quarter.

And I'm sure everybody noticed in our press release that we basically beat expectations on all our cost numbers as well.

So clearly we performed very well operationally during the quarter.

The most important thing we want you to hear today is that our first-quarter accomplishments, including the signing of agreements to sell our Mid-Continent assets, position us to deliver on our 2015 plan and emerge from the year with a stronger balance sheet and more liquidity than we had originally forecast.

During this year, we'll continue to focus all our efforts on generating differential value for investors.

If you'll turn to slide 3, we measure our performance internally based on debt-adjusted per share cash growth metrics.

Just debt adjusted per share metrics.

If you look at these slides, what you'll see is that we've been in the top quartile of our peer group over the last three years on growing production, reserves and cash flow.

And that's our goal is to consistently be in the top quartile of our peer group on those important metrics and we have been consistently over the last few years.

Of course we know those measurements are made looking in the rear-view mirror.

Slide 4 talks about our forward-looking view.

As you would expect for a Company focused on a debt-adjusted per share growth in the current environment, we've been taking actions to reduce our rate of capital investment, pruning our portfolio and avoiding issuing stock.

Our capital investments are flowing to core areas where we have opportunities to add meaningfully to our existing billion barrels of inventory that is economic at current pricing and expected costs.

This morning, we're going to briefly make three points.

Wade is going to take you through the quarter, and then he'll touch on how 2015 is shaping up for us.

Then I'm going to mention an opportunity we have coming up for you to learn more about our Eagle Ford program.

With that, I'll turn it over to Wade.

Thank you, Jay, and good morning.

I'll start on slide 5. As Jay said, we had a really strong quarter.

Production was higher than we had expected led by our Eagle Ford program.

We posted record quarterly production for all products and saw equivalent average daily production increase 6%.

In addition, costs came in better than we -- than what we put out for annual guidance.

This outperformance on cost was somewhat offset by weaker commodity price realizations that plagued the industry this quarter.

Regarding our 2015 plan from an activity and capital standpoint, we are essentially right where we thought we would be at this point in the year.

On slide 6, is a summary of our drilling activity and our waiting on completion inventory that we provided with our budget.

At this point, we're only drilling in the Eagle Ford and the Rockies and we are more or less in line with where we expected to be on completions and uncompleted inventory build.

Flipping to slide 7, we've seen service costs come down in a manner consistent with what we anticipated in our budget.

So with our activity on pace with expectations and with service costs reacting the way we anticipated, we are leaving our capital budget for the year unchanged at about $1.2 billion.

However, I will say that recent data is showing costs heading even lower, so we could potentially under spend this amount.

Let's now move to slide 8. During April, we entered into agreements to sell our Mid-Continent properties for about $324 million.

We expect those transactions to close during the second quarter.

So due mainly to the better than expected results we are experiencing in the Eagle Ford, even after removing projected volumes resulting from this sale, we are maintaining our production guidance for the year.

And again, that's with no additional CapEx assumed.

For those of you focused on quarterly production, we're experiencing quite a bit of planned downtime in the operated Eagle Ford in the second quarter.

So I would expect overall production to decline in the second quarter and be rather flattish the remainder of the year.

Quick update on the balance sheet on slide 9. Bottom line, it continues to get stronger.

We had our borrowing base maintained at $2.4 billion in April.

Looking across the sector, I think it speaks pretty loudly to the quality of our reserve base that we didn't see a reduction given the current commodity price environment.

With the proceeds of our planned divestitures in the Mid-Continent, our 2015 capital program is now fully funded at current strip prices.

We expect to exit 2015 in a stronger financial position with debt to trailing EBITDAX projected to be around 2.3 times at year end.

And as we stated previously, we believe based on current pricing and projected cost reductions, we should exit 2016 in a similar area.

So in closing for me, we're very excited about the better than expected results in the first quarter and the potential outcome of the Mid-Con divestiture efforts.

Net results as our retained assets are generating more production in cash flow than anticipated and the balance sheet is even stronger than initially forecasted.

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

Thanks, Wade.

On May 14 at 8:00 in the morning Mountain Time, I'll be hosting a call which will feature our Chief Reservoir Engineer, Garth Stotts, discussing the technical aspects of the work we're doing in the Eagle Ford to prove up additional inventory.

There will be a press release in the next few days with the call-in details for you on that.

To be clear, this is a teach-in opportunity for those of you who are interested in the technical side of our business, and we don't anticipate announcing a bunch of new well results or conclusions about our program on that call.

I do think though that many of you will find it interesting and certainly hope you'll join us.

Before I open the call for questions, let me sum up.

Due to the strong performance of our core assets, our production outlook for 2015 is unchanged even though we now are selling -- or assuming the sale of some non core assets.

The non core assets we're selling are essentially all gas which means our production mix is moving to more liquids which will improve our realizations per barrel.

We're selling the assets for a multiple of cash flow well above our debt to cash flow so our balance sheet will be getting stronger and our liquidity improving.

We beat on operating costs and capital costs are moving lower than we assumed in our biggest area of spend.

During the last few months, we've repeatedly showed well results in our core areas that indicate improved performance and increasing confidence about economic inventory additions.

These results all bode well for the trajectory of our cash flows for the remainder of this year and 2016, for our NAV and for continuing outperformance against our peers and debt adjusted share growth going forward.

With that, we'll be happy to take your questions.

(Operator Instructions)

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

Not to front run the call, but can you give us any color on what you're seeing in Eagle Ford, just high level as far as -- I know you guys have been doing all kinds of things out there, but can you give us more detail on that?

Yes, we didn't show a bunch of additional well results because we've been at so many conferences in the last month and showed well data we just decided it was kind of repetitive.

But in general, as you look at building inventory in the Eagle Ford, you need to prove up two things.

First of all, you need to prove that we can land in other intervals within the Eagle Ford other than our traditional landing zone in the lower and make good wells.

And I think we've shown throughout the quarter and really since late last year that we can do that.

We made a number of wells in other landing zones that are meeting or beating, frankly, our lower Eagle Ford type curves.

So that's step one, and we still have more to show on that.

About 50% of the wells we're drilling this year are going to be landed in zones other than our traditional upper middle lower Eagle Ford landing zones.

So a lot of opportunity there, and we'll show more data as we go forward through the year on that.

The second thing you really got to prove is that because of that that you can push your spacing from one well to the next a lot closer together.

There's a lot of information coming out, not only from others in the industry and I think you're going to see more from us later this year showing that we can reduce our spacing by drilling wells in a stacked and staggered pattern.

We're currently in the middle of drilling a very large pilot, 12-well pilot on the northern area of our acreage for that.

We have several other pilots in progress.

Pilot data will be a little later in this year to really talk more about spacing.

So we're making progress.

I think we're starting to show a lot of data that indicates we can clearly make wells in other landing zones.

What we lack right now is really some tests -- bounded tests that show the reduced spacing and not a lot of impact between wells on that.

As I said, there's other people out there who have some pilots that are indicating that, but we have thicker pay, I think we have probably more opportunity than others.

The call coming up is really going to be about the tools we're using, the predictive tools we're using, the methods we're using, how we're looking at the Eagle Ford differently now than we used to look at it.

I think it's a very interesting technical discussion.

As I said there's not going to be a lot of new well data or no revelations about our value I think in that.

But I do think it will help people understand the basis for our confidence in what we're talking about.

And that is why we're doing the call.

Okay, that's helpful.

And then just digging a little more, upper Eagle Ford, I know you put out some slides I think most recently and IPAA talking about upper verses lower.

Sure.

Does that get what your point we're just talking about as far as where you landed.

Or can you talk about are you seeing better results?

I think you highlighted north and east, if I'm correct in the IPAA presentation, I'm trying to pull that up.

But is that where you're seeing better results from the upper Eagle Ford or is that the area you view as perspective there?

I think what we showed if you look at the IPAA presentation is that we're getting performance in the upper equivalent to our lower Eagle Ford type curves in both those areas.

Some of the wells look like they're outperforming.

Some are about the same.

And what that tells you is hey, you can make completions in this upper Eagle Ford lithology.

And what you're going to see in this upcoming call is how we look at the lithology of Eagle Ford and how that lithology gives us these opportunities to complete in other landing zones to make distinct wells that recover incremental reserves as opposed to our lower Eagle Ford landing zones.

And that's what we'll be talking about.

So we've shown some good results.

The real -- the proof of the pudding is now can we move toward putting these wells a lot closer together as a result, and that -- those results are going to come later this year.

Again, the purpose of this call is to give people some sense of okay what are the predictive tools we're using.

Why do we express as much confidence about this as we do?

Okay.

I think the call will be helpful.

I'll let somebody else jump on.

Thanks, I appreciate it.

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

I certainly hope I didn't miss it, but is it safe to assume that given the reiteration of guidance in that 11.1 MBOE per day dropping out in the second half because of the Mid-Con sale that the GOR would go down by what the rough equivalent of that 11.1 at a Company level GOR would be?

Well, I think it's safe to assume if you take our previous mix and you take out that was a package is 95% gas.

So you're going to get a higher liquids mix than we had which will as I mentioned in my closing there will increase our realizations per BOE.

Perfect.

And then up in the Bakken any update on those Bakken wells and Divide I think as of the last commentary they were in line to a little bit better than Three Forks?

That's still the result we're seeing.

And we showed an update on that at IPAA again.

Those wells continue to perform.

We haven't completed any more of them since that presentation, so we didn't have anything more to say about it.

Okay.

And is that part of the rational behind waiting a little bit later in the year to start working through the Bakken Three Forks backlog or are most of those backlog wells more down south?

Almost all the backlog wells we're building are in -- are going to be in the Bakken Three Forks.

And the reason we're back logging wells up there is simply to give costs time to adjust.

We're drilling there because we have contracts to drill, but we're going to stack the wells up for a while and wait for our [frac] costs to come down.

Okay, perfect.

Thanks, that's all I have.

Our next question comes from the line of Pearce Hammond of Simmons.

Jay, I'd love to know your thoughts on the biggest differences in your mind and SM's completion techniques today verses a year ago in the Bakken and the Eagle Ford, just from a high level.

What do you see is the biggest differences in your completion techniques?

Well let me start with the Eagle Ford.

In general, the biggest difference is sand loading.

And we've moved from 1,000 pound per foot type sand loading, maybe even a little lower than that in some places to a couple thousand pounds per foot.

In general, we're pumping those jobs at a much higher efficiency.

So our costs are way, way down even though our sand loadings are up.

And we're just seeing a lot better performance.

The good thing here is that industry in general is seeing this.

You can talk to almost anybody whose pumping higher sand loading jobs now and you're seeing improved performance.

We can talk theoretically about why we think that is.

Maybe we'll do that on the call coming up.

But clearly, I think we were creating more fracture than we were propping, and we're getting more complexity and more surface area in our fracs.

So that's working for us.

That's really the Eagle Ford's story.

In the Bakken we've moved, along with everybody else, we've moved toward -- moving more toward cemented plug-perf completions.

We are seeing improved performance on that.

They are a little more expensive than the sliding sleeve jobs we pumped before, so we were -- obviously we're a little reluctant to go there.

But in general, that's the direction we're going.

I think what we'll be showing you over time, and we have some really early data on a few wells that at this point, it's certainly going in this direction, but it probably is not as conclusive as I'd like to be yet.

But we'll be able to show you that those wells are outperforming our sliding sleeve wells.

And if you go up into Divide County now we're essentially cement plug-perf everything and that's the direction those wells are going.

Great.

And then the follow up, I know this isn't the primary area of focus for the Company this year.

But any updated thoughts, high level on the Powder River Basin or East Texas?

Well, we're making some good wells in the Powder River Basin, they're just too expensive.

And we need to continue to work on our costs.

Our costs are down, but they're not down low enough to compete in our core development -- against core development wells in the Eagle Ford and the Bakken.

So essentially we're ramping our activity way, way down.

We're down to one rig now in the Powder.

It's just an acreage holding.

I'm really working on the cost side and understanding it.

There may be some hydrating we could do that would allow us to get our economics competitive in the other areas.

In East Texas we're flowing seven wells back right now.

On a long-term production test.

They're flowing back, fairly choked back rates.

We're looking to see what the yields on those look like.

Don't have a conclusion there yet, and really focusing on the core development assets for this year and probably next year as well.

Great and then just one final one quickly.

What are you seeing in the acquisition market as far as potential bolt-on opportunities for the Company or is it as others have said, the bid ask spreads fairly wide?

Well the bid ask spread is very wide.

And I will tell you there's a lot of optimism.

I talked to some folks yesterday who are still talking about going public later this year.

I mean, it's a very -- there's a lot of people who really think things are coming back faster than we might have expected.

So that drives that bid ask spread.

Acquisitions are tough for us in any event because anything we buy needs to be as good or better than what we already own.

We already have a huge inventory of opportunities and that inventory is getting bigger all the time.

So it's going do have to be super good looking stuff to us.

It'd have to be in a core area for us.

It's got to really fit our footprint.

There's got to be some reason that we can make more of it than somebody else.

The acquisition market and a bid market and that you can see this by the bids we just got and the assets we're selling.

This is a very competitive business out there.

There's a ton of money chasing deals and a lot of private money.

Enormous amount of private money who wants to be in our business right now.

So it's an acquisition for us, it's very selective and very tough to do.

Certainly, we look all the time because we want to add to our core assets.

Part of our strategy is to build scale in core assets.

But very selective and very tough to get done.

Thanks for the very helpful answers.

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

Mentioned the costs on your plug-and-perf and cemented liner in Divide County a little more expensive.

What are those costs now?

Is that -- I think you had quoted $4.5 million previously, is that what those wells are coming in at or were those the older design?

Yes, I think we quoted a $4.1 million number for next year based on the sliding sleeves.

And I would say that number with plug-and-perf is probably just a little bit higher than that, but the wells will outperform them.

But the $4.5 million number is probably a really good number for a plug-perf job at end of the year this year.

And I think that's pretty much where we're going to be.

So you're talking about a well that's roughly 400,000 BOEs for 4.5 million barrels --$4.5 million.

So these are pretty competitive wells.

Can you say at this point how the Baytex acreage compares to the legacy acreage that you had in Divide County?

Well obviously we haven't tested it all, the wells we drilled looked pretty good.

If you look at wells that we drilled recently and look at them on a distribution, the Baytex wells compare very well to what we had before.

And in terms of the Bakken you were asked about a little bit, but I'm wondering do you feel like that is going to be potentially as expensive as the Three Forks or is it more isolated on your acreage?

Well, I think we think there's just as much upside on the Bakken as there is on the Three Forks.

We have about 400 locations on the Three Forks, and those are risked as we look at our acreage.

We didn't -- we risked them differently across the acreage.

But I think there's as much Bakken potential there as there is Three Forks at this point.

There's no reason to believe there isn't at this point.

Obviously, we need to test that.

Yes, okay and then a couple high level questions, you mentioned you're really waiting for cost come in line with prices.

But before you start completing, prices are moving up now.

One, what is your outlook for oil prices for the remainder of this year and where would you consider it going back to completing some of that uncompleted inventory?

Well, Mike, the script looks good to me.

I don't know have any idea whether prices are going up or down or sideways.

We were assuming the strip is a reasonable representation of what's going to happen.

I think based on that strip, our plan still is what our plan was, and our plan is to get back to completing in the Bakken say almost third quarter.

I think we've said multiple times that if we see costs lower in the Bakken earlier we might pick up and do a little of that work earlier.

But so far, we're very focused on cash flow, net cash flow and keeping our CapEx down and doing what we said we were going to do.

And I think if we saw cash flows improving a little bit, we would tend to let that improve our leverage a little bit as opposed to spend it.

Got it.

Great, thanks.

Our next question comes from the line of Jeb Bachmann of Scotia/Howard Weil.

A couple quick ones to follow on that last one, Jay.

When you look at potentially down the road with costs coming in and maybe oil continuing to increase, are you guys looking at maybe putting activity or rigs back to work in the Permian at this point?

Jeb, it's always been our view that we would be picking up activity again in 2016.

And that's still our view, that's consistent with the plan we had.

To be clear, our Permian assets have very similar economics to our Bakken work.

The only reason we're not drilling -- we've been slowing down the Permian so much is because that acreage is all (inaudible).

And we had more flexible rig contracting to be able to deal that.

We certainly intend to get back to drilling in the Permian and I've always viewed that as a 2016, early 2016 event.

So that's how we're viewing it now.

If prices went way up in the second half, and now we're completely speculating here, but if prices go way up and cash flows improve, we could pick up earlier and go back to work.

But our current plan is really that we start picking up activity again at lower rig rates following 2015.

And a quick one on East Texas.

The seven wells that are flowing back, results on those.

Is that going to really determine your program or lack of program going forward on those assets?

Yes, that's exactly right.

We'll look at the results.

A lot of the input we need is what are the decline rates on the wells.

And once we get them on a long-term test then how do they respond to a long-term production test.

And we'll make our judgment based on that.

There is zero money left in our budget to spend on exploration essentially for the remainder of this year.

And so we intend to flow these wells for a good long time and see how they look.

I think both East Texas and the Powder, depending on where prices go and how things go and as we continue to build out this massive inventory we have in our core assets, these are potentially very good partnering opportunities for us that add value.

And that's how we look at it as a big option at this point.

This is going to be my last question is what's left to divest or maybe JV and anything outside of those two areas?

I think those are obvious candidates.

And we're making good wells, our costs are just too high.

And a lot of that we can do better just by repetition.

We need to show a potential JV partner that we can drill these wells for a reasonable amount of money.

And I think the resource is there.

There's an enormous amount of resource in the Powder.

We think there's a really good-looking resource in our East Texas asset.

It's really about costs.

And we need to work through that which means we'll have to spend a little at some point.

But we don't need to do it now.

This acreage is in good shape.

We can wait until prices improve a little bit, until we get a little more experience from a cost standpoint to make those judgments.

Right now the focus of the Company is on drilling our core assets, on building the inventory that we're increasing confidence and building more and more inventory in these core assets with very good economics.

So that's what we're focused on.

Great, thanks, Jay.

(Operator Instructions)

Our next question comes from the line of Paul Grigel of Macquarie.

A quick follow-up question on the Q2 comment on production coming down due to downtime.

Could you elaborate on what exactly is driving that and then what's built into guidance into the back half of the year as well in terms of the new guidance and how conservative it may be after a couple of strong quarters here?

Well this is Jay, I'll comment on what's coming up in the field, then Wade will comment on the guidance.

But in general, in the field we had some planned simultaneous operations related to downtime and well completions and we also have some facility tie-in work and maintenance work that needed to be done.

And most of that work is occurring in the second quarter.

So it's really a temporary -- it's not a value issue.

Make it clear, this is related to just getting our operations going.

It's a lumpy business when you start working with these big facilities and a lot of well completions.

And that's really what is driving the lower than trend, I guess, performance.

And this really relates to the operated Eagle Ford next year.

Wade, do you want to comment on guidance?

Yes, I said it would be down and then flattish for the rest of the year.

I guess if you're trying to plug something into your model to fit our annual guidance, something in the range of around 5% maybe in the second quarter.

And then flattish the rest of the year could mean down 1% or 2% per quarter as we're slowing down, as we had guided before.

So I think that would get you pretty close to the annual guidance.

Okay and is there any rebound into 3Q as the 2Q same op issues go away in 3Q or is that built into that flat to down 1% in 3Q?

And I think that's kind of built in.

Or slowing down.

We are slowing -- we've gone from 17 rigs to 9 in our total package right now.

By the end of May we'll be at 9. By the end of the year, we'll be at 7. So things have really slowed down.

No, that's helpful.

And then on your comment earlier and Mike's question on the Bakken costs and mention that you could accelerate sooner.

How close are you to that level?

Is it 5% to 10% away or is it still a sizable amount of reductions on the completion side that you would need to see to move those forward from 3Q or 4Q?

Honestly, I don't know that I know that number.

I know that the trajectory is still down and until we're comfortable that we've gotten to where we think we can get, we probably won't start back up.

Again, we're very focused on net cash.

We want to get our costs down, but we also want to stick to our capital budget.

And it's not just okay, we get to a number and flip the switch, it'll be a thoughtful process.

Okay and then one last one, can we get your latest thoughts on oil differentials both in the Williston Basin and then in South Texas and the Eagle Ford?

Well, the Eagle Ford, very clear, we trade $17 off LOS.

And so LOS, there were some days in the quarter when LOS had actually traded over Brent which was an exciting day for us.

But it didn't last very long.

But you can always use about $17 off LOS for us.

That's our two major contracts.

That's pretty much what they price at.

Obviously Permian differentials have improved due to the pipeline work.

I think the Bakken numbers are in that $10, $12 range.

I don't think they're going to change much.

Seem like a little better as this thing roles over.

But I don't see -- there may be slight improvements in differentials as you go through the year just due to the fact that volumes should roll over a little bit.

That's all I got, thanks for time.

Our next question comes from the line of Chris Stevens of KeyBanc.

Can you give us your latest thoughts on whether or not you would consider doing some from refracks, whether it's in the Eagle Ford or Bakken or anything like that?

Thanks for asking that because we actually have done one here recently.

Don't have results back yet.

We're participating in consortium to do some refrack work in the Eagle Ford and looking forward to sharing results with some other operators there.

I do think there's significant opportunity both in the Eagle Ford and the Bakken in refrack work.

And there's some -- the technology is certainly moving along.

And there's a large resource there that should be amenable to that I think in a lot of ways.

I think when people think about refracks on these big horizontal wells, they need to be thinking a little differently.

These are going to be pretty expensive jobs because they're large.

And there are a lot of diverter that needs to be pumped.

So it's not a little vertical well refrack that needs to be done, you have to have significant production response to make these pay.

But with that said, I think there is a lot of potential in wells that were under stimulated originally.

And potentially even as we go forward as you look at stress regimes within the rock after these wells have been completed a while, there may be some opportunity to change frac direction or add additional complexity.

Still on the very front end of this and certainly a big opportunity for those of us who own big positions and great assets.

I just can't emphasize enough how good assets get better over time.

A small amount of incremental recovery in the Eagle Ford is a really big number to a Company like us.

And so these are things that are certainly -- we're certainly going to be chasing.

Okay, so I guess costs could be somewhere around the typical costs of a completion out in the Eagle Ford or is it a little bit cheaper than that?

Well it might be a little cheaper.

You'll save some wire line work because you're not going to end up -- you probably won't run as many plugs and -- you won't be plug-perfing necessarily like you are now.

The chemical costs may be a little higher because you're going to have to pump quite a bit of diverter.

But typically we pump some diverter in a lot of stages anyway.

So I would probably say the cost is going to be if you're going to throw out a number, three quarters of the cost of a typical primary job.

That would be a reasonable place to start for an estimate I think.

Okay.

So then would you say that the EUR, incremental EUR, should be like a 50% uplift or something like that in order to generate a decent rate of return?

Well, we don't know that yet.

And that is the $95 question, right, is what will the uplift be and how sustained would it be?

I'm almost positive you'll get an initial production response, but will it hang around and have any real value in the long run?

So -- and there's a lot of questions about whether that's acceleration or incremental reserves.

There are a lot of things you have to be answered on the refrack side.

Again I think where you're looking at wells that were significantly under stimulated to begin with, I think you can be more confident of incremental reserves.

When you're starting to get into wells that were completed with a halfway decent frac to begin with, then it's a different kettle of fish entirely and really there's a lot of testing that needs to be done before anybody concludes that.

Right, okay.

And then out in the Eagle Ford, are you guys still testing anything else on your completion design?

Are you pushing the amount of sand that you're using, testing anything else with your stage spacing or cluster spacing out there?

Well, we've done some tighter cluster spacing.

Generally, we're moving.

We've done some smaller mesh sand tests.

Generally, we were using more [under] mesh than we used to.

That's as a general statement.

In terms of sand loading, we tested above a couple thousand pounds per foot.

Didn't see a lot of benefit associated with that.

I think that's probably about as high as we'll go there.

Okay and then out in the Permian, any results on any other zones you've tested out there?

I think we've discussed publicly we drilled a nice lower Spraberry well in our Sweetie Peck asset not long ago.

It was a good-looking well.

We felt really good about that.

We are drilling a middle Spraberry test, but we won't complete it here for a while.

We're actually shutting down our rig here at the end of the month in the Permian for a while.

So we have -- if you look at our asset which is 15,000 net acres or so there in the Midland Basin side.

Got a great looking Wolfcamp B, some of the very best Wolfcamp B wells drilled in the entire Midland basin on our acreage.

The lower Spraberry looks good.

So we've got two intervals there.

We have probably at least three other intervals we need to test, the middle Spraberry, the D, Wolfcamp D and the Wolfcamp A. We think there are hundreds of economic locations on that little spot of acreage, so it's a very valuable piece of acreage.

We're certainly going to get back to it.

It's this point, it's HP'd and we're minding our capital, we're minding the cash register here and so we're going to defer activity for some months.

Thanks.

Appreciate all the color.

Our final question comes from the line of Biju Perincheril of Susquehanna.

On your Eagle Ford program, Jay if you'd look at your stack (inaudible) program as you down space, what is your expectation as far as productivity?

Is this case where you're thinking locations will be going up and you're able to keep your EURs or production levels flat from what you're getting today?

Well, that's certainly our hope.

I think what we said is we think we can double.

It's not an unreasonable expectation based on our original spacing and the thickness of the reservoir that there's an opportunity here to more than -- to double or potentially even more than double in some areas our well count by reducing spacing and stacking and staggering these wells.

If you remember, we space most of our wells in the gassier areas of our acreage on about 900 feet.

And we spaced a lot of our oiler stuff at 550 feet.

And if you look around the universe or the operators out there, that's almost double what a lot of people are doing.

And so -- and that's in a single landing zone.

We have 300 feet of section on a lot of this acreage.

So we believe that we'll be able to land wells in other -- in the upper or even in the lower, lower and achieve higher density drilling.

And I don't -- because of the fact that we space conservatively to begin with, I don't think that's much of a stretch quite frankly.

So that's where we're going.

So far, the results we've seen would say that a lot of the upper tests we've done have as good as or better well performance than our lower Eagle Ford type crew.

Do they have to be as good?

Not necessarily to be economic, but we certainly would love that, and that's certainly our hope.

I think if you'll tune into our technical call here on the 14th, we're going to show you some really great tools we're using to be able to look at the lithology and the completions we're doing.

How we measure our performance.

How we look at the economics of that.

So I think you'll get more insight into how we view that on that day.

Again, not a lot of results necessarily, but a good sense of how we are driving the program.

Great, I'm looking forward to that.

And then on your NGL realizations, as I compare it to the (inaudible) blended price that our realizations have been coming down the last couple of quarters.

Is your blend changing or is there -- what is driving that and how should we think about it going forward?

Yes, I don't think our blend is changing.

I think we've had probably a higher NGL volumes percentage wise.

I know there's been some shifts on the Anadarko side with where they're recovering.

It maybe just the recoveries on the Anadarko liquids because of the [Persada] plant.

They're doing some rejection now as well which may be driving some of those differences.

We do make a lot of NGLs out of that Anadarko operated stuff.

Okay, all right.

Thanks.

As far as our operations, nothing's really changed.

This concludes today's question-and-answer session.

I would now like to turn the call back to President and COO, Mr. Jay Ottoson, for any further remarks.

Thanks so much again for your participation.

I really hope you'll join us in our teach-in on May 14.

I'm excited about it.

All us technical guys, we get off on these things so it's going to be a lot of fun and I hope you'll join us and ask a lot of hard questions.

All right, thanks a lot.

Bye, bye.

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

This concludes today's program.

You may all disconnect.

Everyone have a great day.