SM Energy Co (SM) 2014 Q2 法說會逐字稿

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

(Operator Instructions)

As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, David Copeland, Executive Vice President and General Counsel.

Sir, you may begin.

Thank you, Sam.

Good morning to all of you joining us by phone and online for SM Energy Company's second 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 the 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 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 factors section of our form K 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.

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

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

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

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

I will now turn the call back over to Tony.

Thank you, David.

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

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

I will begin on slide 3 and share a few key messages.

First, I'd like to highlight that we had another very strong quarter.

We reported record quarterly production of 147,000 BOE per day, led by our Eagle Ford assets which had significant growth in the quarter.

Along with record production for the quarter, we also reported record quarterly adjusted EBIDAX in the second quarter of $423 million.

Second, we recently signed an agreement to acquire a significant block of a acreage in Divide and Williams Counties, adjacent to our Gooseneck acreage where we have been operating a very successful Three Forks program.

This pending acquisition is the largest in Company's history on a dollar basis and is expected to add a significant amount of oily inventory to our Williston Basin program, adding 61,000 net acres to our existing position.

So we're very excited about that.

Third, in the last quarterly call we indicated that we were working on testing various completion designs and longer laterals in our development programs.

We have been rigorously testing these completion designs to optimize our development programs in the Eagle Ford and the Balkan Three Forks.

During the second quarter, we started to receive a sufficient amount of data from these alternative completion tests to make some initial conclusions on the improved frack designs.

We can now comfortably say that we are seeing improved results that are significantly increasing the value of these core development programs.

Jay will provide more details on these improvements in his operational review.

Moving to slide 4, I will walk through some key financial and performance metrics for the second quarter.

As I stated in a previous slide, in the second quarter we reported record quarterly production and adjusted EBIDAX.

From a performance standpoint, we were above the high end of our production guidance range and within or below the range for all of our guided cost metrics.

As you can see, execution on our 2014 business plan has gone extremely well and positions us for continued success in the second half of the year.

With that, I will turn the call over to Jay for his operational review.

Thank you, Tony.

Good morning everyone.

As Tony indicated, operationally we had a great quarter, meeting or beating all of our guidance numbers.

But we're really very pleased with the progress we've also made in improving and expanding our drilling inventory.

I will start on slide 6 where I will discuss our operated Eagle Ford program.

We made 23 completions during the quarter, and production increased 9% to an average of 83,000 BOEs per day.

We currently have five rigs running in this program.

As many of you know, we've been moving to longer lateral drilling in testing the use of more sand in our Eagle Ford completions.

Our average well drilled in 2014 will be about 30% longer than in 2013.

With respect to using more sand, we now have some high competence results which demonstrate compelling economic value for this particular change in our completion program.

One of the first places we tried the increased sand technique was in what we call Area 2 of our operated acreage essentially right in the middle of our position.

Slide 7 shows the location of Area 2 and summarizes what we tested.

We had 26 older wells in the immediate area with an average lateral length of approximately 5000 feet.

And we drilled seven new wells late last year with the same lateral length and completed them with almost twice as much sand per lateral foot from around 1100 pounds per lateral foot a to little more than 2000 pounds per lateral foot.

Again, the lateral links for both the older and newer wells are essentially the same.

We generally restrict chokes on our new completions in the operated area for some period of time, in order to minimize any potential damage to the completion during early flow back.

So the best way to see differences in well productivity on choked wells, is to look at the flowing pressure upstream of the choke after equal amounts of production have been produced.

On slide 8, you can see the dramatic increase in flowing pressure upstream of the choke in the newer Area 2 wells at various cumulative volumes produced versus the older wells.

Slide 9 shows that the improved productivity of the wells is resulting in higher sustained production rates over time.

On slide 10, you can see that the early time condensate yield on these newer wells also was improved meaningfully which is another indicator of an improved completion.

On slide 11, we summarize the economic impact of increased sand loadings at the actual cost we experienced for the wells.

Although it does cost us some incremental money to pump more sand, we have largely offset those costs through our improved efficiency in drilling and completions operations over the last several years.

The combination of higher sand loadings, and our success in cost control, means that our newer wells in Area 2 are generating 40 percentage point higher returns, and our MPVs have been improved by approximately $2 million per well.

Obviously this is great news for Area 2, which is about a 22,000 acre block, but we expect to see this type of improvement in other key areas of the operated acreage as well.

We also expect good results from our change to longer lateral drilling, and will have results on some longer lateral high sand loading wells for you later this year, some of which will be in oilier areas of the field.

I think your take away from all this should be that our Eagle Ford drilling inventory is becoming a lot more valuable.

Moving to the non-operated Eagle Ford, you can see on slide 12 that the operator there made 95 flowing completions in the second quarter.

As we expected, the Mitsui carry was completed in the quarter.

APC has been optimizing frack designs as well, and we are seeing encouraging results from their activity.

On slide 13 you can see that Bakken Three Forks production increased by 3% in the quarter and that we had 12 gross operating completions turn to sales in the quarter.

Moving to slide 14, last night we announced that we have entered into an agreement to acquire approximately 61,000 net acres in Divide and Williams County, North Dakota for $330 million.

The acreage is directly adjacent to our highly economic Gooseneck project area and brings our total position in the area to about 97,000 net acres.

We acquired interest in 126 drilling spacing units, 81 of which will be operated by us.

Speaking of our operations in the Gooseneck area, let me update you on how that program has been going recently.

Our historical activity in Gooseneck has been focused on the Three Forks interval.

And I know that a number of you have noted that we are the leading operator in terms of well performance in that area and that our wells are very economic.

I am pleased to tell you that they are getting even better.

On slide 16, you can see how we have improved our drilling operations in the Gooseneck area since 2012.

All our wells in this area average right around 10,000 feet in lateral length, and we are now drilling wells in 30% less time than we were in 2012.

On slide 17, you can see the impact on early time production rates we have been able to demonstrate in a recent multiwell test of optimized completions.

These tests included increasing the sand loading by approximately 40%.

On slide 18 then, you can see the impact to the economics of this program with rates of return improving an incremental 25 percentage points and net present values improving by an incremental $2 million per well.

We don't think we've reached the limit on our optimizations here yet, and expect to continue to improve our wells, as we have in all of our Bakken Three Forks play areas over time.

Given these results, it's easy to understand why we are excited about the acquisition we're making.

In addition to the Three Forks interval, we also think there is significant opportunity in the Bakken in this area which we're just starting to drill.

In summary, we've acquired a big chunk of acreage that directly offsets an asset were we have been performing extremely well.

We expect will be able to add a lot of low-cost, oily drilling inventory over time, and that proximity and size of the deal offers us material opportunities for economies of scale in our overall Bakken Three Forks program.

Moving to slide 19, I will briefly talk about the Powder River Basin.

As you know we've been actively growing our position in the Powder River Basin this year.

Currently we have 166,000 net acres leased or under contract which represents an increase of 33,000 net acres since year-end 2013.

At this point we would say that about 127,000 acres of that total position is perspective for the frontier, which is our primary focus interval, although we will be testing over intervals including the Shannon as well.

Last night in our press release, we disclosed the results of our Rush Frontier well which was intentionally drilled as only a 3800 foot lateral well in order to hold a particularly oddly configured lease.

It had an average 30 day peak production rate of 737 barrels of oil equivalent per day which on a per lateral foot basis is one of the best wells we've drilled to date in the powder.

With this well and the previously released results in our Loco well, we believe that we proved up about 20,000 to 25,000 acres on the north side of our position to add to the 20,000 to 25,000 acres we feel we proved up on the south end with our Dandy and Blackjack wells.

We are currently flowing back our Dynamite well which is located right in the middle of our acreage block, and should have results to share with you in the third quarter.

We added a third rig to the program in the second quarter and have contracted a fourth rate for delivery in the third quarter.

We're encouraged by our results to date and have a lot of positive momentum in this very oily program, and we're going to keep pushing it.

I don't have a slide for you on the Permian today, but if you read our press release you know that we reported another couple of very good wells in our Sweetie Peck Wolfcamp B program.

We're planning a lower Spraberry shale test at Sweetie Peck later this year, and we're currently in the lateral drilling at Wolfcamp D test on our large Buffalo expiration position on the north side of the Midland Basin.

We also did not include a slide on our East Texas expiration program because there really is no new news there.

We continue to be encouraged by the productivity of the wells we drilled, in our [Deep] Pines West Prospect area and are currently building infrastructure in order to get longer-term production test there which we expect to complete later this year.

As you saw from our press release last night, we have decided to defer on midyear CapEx in production guidance update for a few more weeks to give us time to incorporate the impact of this large acquisition we just signed yesterday morning.

As a preview, let me just say that we are optimistic that our 2015 and subsequent years growth rate will be favorably impacted by the acquisitions and improvements to inventory we're making this year.

With that, I will turn the call over to Wade.

Thank you, Jay.

I will start on slide 20.

So at the end of the second quarter, we had about $164 million of cash on the balance sheet, and our debt to trailing EBIDAX was 1 times.

That amount of debt equates to 48% of our total book capitalization.

So total amount of long-term debt remains unchanged from the prior period, at $1.6 billion.

We have no maturities on that debt within the next five years.

We have an undrawn revolving credit facility with $1.3 billion in lender commitments, with a borrowing base securing it amounting to $2.2 billion.

We intend to fund the acquisition in the Rockies that Jay talked about earlier with cash on hand and some borrowing on the revolver.

Moving to the next slide, slide 21, we show our debt to trailing 12-month EBIDAX against a group of peer companies that we track internally.

As you can see from the slide, this leverage metric was also unchanged compared to last quarter.

It also shows that we are well below our peer group median average of 2.2 times, and I might add that even on a pro forma basis after the Gooseneck acquisition, the ratio would be 1.1 times.

One final comment for me, we added some oil hedges during the quarter, and with the additional oil coming from the Gooseneck acquisition we've been adding more during July.

The details can be found in the appendix of the slide deck or in the 10-Q which was filed this morning.

With that, I will turn the call back to Tony for his closing remarks could

Thank you, Wade.

Before handing the call over for your questions, I will highlight what we think are the key takeaways from this call on slide 23.

First we had another really strong second quarter.

We came in above our production guidance and performed well against all of our guided cost measures.

We also set new quarterly production and adjusted EBIDAX records in the quarter.

Next I'm very excited about the pending acquisition that we announced last night, which is a fantastic fit with our existing Gooseneck acreage.

We have the potential to add a significant amount of really valuable oily inventory in a core area of the company.

These new assets are a great addition to the SM portfolio.

Lastly, we provided some data today on enhancements that we've been making in our Eagle Ford and Three Forks programs.

That are resulting in significant improvement to the economics of those programs and will add more updates on our well optimization as the data comes in during the upcoming quarters.

I now like to open up the call for your questions.

(Operator Instructions)

Mike Kelly, Global Hunter Securities.

Hi guys, good morning.

Good morning.

A couple questions for me.

One I just wanted to clarify with the improvements you're seeing in the Eagle Ford here, and the 40% improvement.

Is that 40 percentage points, if I look back at the Q4 presentation from the $90 oil and Area 2, you're about a 30% rate of return.

We're not talking about potential 70% higher here on the basis?

I just want some clarity on that, thanks.

Mike, it's Javan.

It's 40 percentage points in crease.

Okay, outstanding.

And then over the Bakken.

Looks like the acreage there is a little bit north of your position, is a direct offset, but is there you anything from a geological standpoint of -- is there any differences there I guess from a geological standpoint?

Because it does look like from the rates we pulled, you guys had about 40% higher initial IP rates.

And do you expect to see a little bit of less productive wells as you move further north?

Thanks.

Mike this is Javan again.

We have two areas in Gooseneck, the North Gooseneck area South.

A lot of this acreage lays right in between it and a little bit to the East.

So we would say the acreage is right in between us, we know is going to perform very similarly to our acreage position.

The acreage to the east obviously is a little farther away.

We did risk the acreage little bit when we bought it.

One thing I think we should say, and I'm glad you bought up Gooseneck, we hear this all the time.

If you go back and look at just general industry data in that particular Divide County over a long period of time, there are a number of wells there that weren't great.

A lot of shorter lateral wells drilled earlier on, a number of other operators have drilled wells that frankly we would not be proud of.

If you look at our results in Gooseneck, I think we stick out as an outstanding operator in that area.

And there's a number of good reasons for that, including the way we complete the wells in the way we operate them.

Were very front of operation staff there.

We fully believe that we can develop a lot of this acreage to the standards that we've been demonstrating on our other acreage.

Okay.

Great and maybe if I could sneak one more quick one in here.

You hinted at the end of your prepared remarks that the subsequent update we're going to get with the CapEx should be positive and bode well for production growth rates going forward.

And I figured you guys a 15% grower going into 2015.

Is it now with some bolt-on acreage here and the different positions, higher rate of returns in the Eagle Ford, is it a meaningful impact of 15% growth rate?

Should we start thinking about upward of 20%?

How should we think about that?

While this is Javan again.

Again we need to sit down with our board and get our capital program completely worked through, but I think it's safe to say that our growth rate in 2015 is going to be up certainly between 15% and 20%.

We will see where it ends up.

Great, thanks a lot guys.

Great quarter.

Matt Portillo, TPH.

Good morning, guys.

Morning, Matt.

Just a few quick questions for me in regards to the Bakken.

I guess just a quick follow-up on the acquisition acreage.

I was curious if you would comment maybe on the difference in the completion techniques or some of the opportunities you see to enhance maybe the EURs.

I think Baytex previously had a 390 EUR published here, and I think you guys analysis we've done would suggest that your Three Forks wells have materially outperformed that on your acreage.

And then I guess a second quick follow-up question, just could you remind us where your rates of return are currently on the older completions in Divide and with the new completions you've seen so far where those could be headed to?

Hello, this is Javan again.

In terms of completion styles, we typically pump a sliding sleeve, say a 26 to 30 stage completion, the sand loading as we've indicated there again.

I think our well costs are typically lower than most of our competitors in the area.

We are very aggressive about artificial lift installations, we've run a lot of long-stroke units there which are performing very well for us.

In general, I think we have a very good uptime on our assets, we're very pleased in the particular area we're buying here that all their gas is essentially connected to pipeline.

So a lot of good, great opportunities here we think to make good wells.

Earlier this year, we disclosed our own Gooseneck numbers.

I think the number we disclosed was a little under 400,000 barrels of oil equivalent per day from an EUR standpoint.

We did risk that a little bit on this acreage because there is a little bit of unknown as you go south.

But in general, that's probably not a bad number.

We think there's significant opportunities here with increased sand loading and some additional things we can do you know that we haven't talked about yet, some interesting completion techniques we think we can use to improve on that.

In general, I think if you look back at that release that we sent out at the end of the fourth quarter, at about $90 oil we were showing about 45% or 44% returns per well in Gooseneck.

And again we think those numbers are getting better over time.

Great.

And in one quick follow-up.

I know that you guys had also mentioned I think previously you were starting to test upsized fracks in the Bearden and Raven area.

And I guess specifically to Bearden you moved I guess north of 4 million pounds on the wells.

I was curious given industry -- early industry success with some of the 9 to 10 million pound completions in the basin, if you guys may be looking to potentially upsize further given the quality of that asset base, but I just wanted maybe some context of how you're thinking about the completion changes in that area of your acreage.

Javan again.

I think no question we're looking at higher sand volumes across the acreage position.

Most of our testing would be in the Raven, say East -- middle to Eastern or Western McKenzie County.

We don't have a lot of immediate drilling inventory in the Bearden area.

We do have a few wells later this year.

We will surly be testing higher sand loadings in our state line area later this year as we move there.

So far we haven't seen a big break over.

As you continue to pump more sand, it appears wells get better.

Everybody's moving in that direction.

That's the direction we're moving as well.

Thank you very much.

Pearce Hammond, Simmons and Company.

Good morning guys.

Good morning Pearce.

I was just curious would you consider any divestitures to fund the Bakken acquisition as well as $100 million PRB bolt-on acquisition earlier this year?

Hey Pearce, it's Wade.

We always look at divestitures.

I would tell you that specifically looking for a divestiture to fund those acquisitions, that's clearly not necessarily with the balance sheet.

As I mentioned, going into the end of this quarter we still had cash on the balance sheet and were using that, and the draw on the revolver to fund the Baytex deal.

So no imminent desire to do the divestiture just for that purpose, but we always look.

Thank you, and then my follow-up would be do you plan to apply for a private letter ruling with the Commerce Department to export condensate and then currently how much of your condensate is stabilized?

Pearce, this is Javan.

Great question, thank you for asking it.

We sell all of our condensate to middlemen.

We don't export crude ourselves, we don't have any facilities to do that, don't own firm transportation to the coast.

So all almost all our crew that comes out of the Eagle Ford is stabilized, we run it through stabilizer that Plains operates.

So from that standpoint, we don't see material difference between the product we're selling and the product that some people who talked about this are selling.

At this point given our situation we're not applying for letter rulings, but it could very well be that our downstream purchasers will.

Thank you very much, Jay.

Mike Scialla, Stifel.

Good morning guys.

Hello Mike.

On your new completion technique, what you outlined in the presentation if I'm understanding it correctly is just the additional sand.

You really haven't given this anything yet on the longer lateral lengths, is that correct?

And then how applicable do you think the new technique is to those other areas?

You alluded to the oilier areas may take a combination of both those things.

Mike, great question.

First of all, let me reemphasize that the testing we just talked about was on wells with similar lateral lengths.

We drilled those wells late last year before we started lengthening laterals, so we had an opportunity to get a straight up test between higher sand loading and lower sand loadings.

And that's why we did that test and why we show the data the way we did.

We don't have that result yet on longer lateral wealth.

I will tell you that we fully expect longer lateral wells to outperform short lateral wells, I think it's a no-brainer to some extent.

We guided most of the work we did this year when we put on our results at the end of the year on longer lateral type completions.

I will emphasize that the guidance we provided at the end of the fourth quarter did not include increased sand volumes.

So we would expect to improve on that.

In terms of how it applies to other Eagle Ford areas, I think from a modeling standpoint, we think it's going to work in any area where you have sufficient Eagle Ford thickness.

There is in general sufficient Eagle Ford thickness on almost all of our acreage.

Certainly as you go north on our acreage into the oilier parts of our acreage position, our position actually thickens from Area 2.

So I think all the indications we have would be that it should be very successful on the thicker oilier parts of the reservoir.

I can tell you from looking at APC's results, that when they pump higher sand volumes on their wells, which are north of ours, they get better wells.

So there's no reason to believe that as we move north into the oilier portions of our acreage that this should not be effective.

And that -- so Area 2 we may get some news before the end of this year on the new techniques there?

Yes.

Think you will.

Okay great.

And then switching over to the powder, you're going into a fourth rig there a little earlier that you anticipated.

Is that any read through on the permitting process getting any better at their

We have more than sufficient permits to run a four rig program.

Okay.

And last one for me on the powder, what are you budgeting for a well cost for your Shannon wells?

I think the current is between $10 million and $11 million.

Mike if you don't mind, call Brent back and we will make sure you get a good number on that.

I'm sure Tony's right, I just want to make sure that we get it exactly right for you.

I will do that.

Thank you.

Subash Chandra, Jefferies.

Yes.

Good morning.

On the Baytex acquisition, how is the infrastructure there?

Is it in good shape, or do you think most of the dollars incrementally could be for drilling, or will there be some infrastructure work required?

And then also in the acreage, just a question on the limits of sand loading up here versus of course deeper parts of the basin.

I would imagine you're closer to a max here potentially.

And also I think you guys have in the past limited the amount of water you've experienced in these wells versus other operators, and if you could refresh me on your successes to date and how that might translate into the new acquisition, thanks.

Thank you Subash.

Okay, let me start infrastructure first.

Less talk about Baytex has done I think a terrific job on the gas side infrastructure.

90% of their operated wells right now are hooked up to gas sales, and the other 10% are coming.

So we have a great gas architecture in terms of not having to flare a bunch of gas as we get in here.

Very pleased with that.

The oil is generally being trucked at this point.

We think there's an opportunity there to hook up oil sales which we've done on most of our acreage.

We think there's a positive associated with that in terms of our economics which we currently have rolled into our acquisition economics.

The water side, and this gets back to completions, generally we have pumped larger jobs up here than most of our competitors over time.

We think there's a strong relationship to well performance and water volumes, up to a point, and as I said we typically pump 26 to now 30 stage jobs up here.

I don't necessarily see that we're up against a limit on sand loading.

Frankly we will be testing high higher sand loading on subsequent wells, probably almost twice the sand loading that we have here or significantly higher I should say.

Again thickness does have something to do with that, typically their intervals are a little thinner.

This is a long answer to a short question, but we used to be concerned that if you frac these wells too much that you would get into the Bakken which we thought might be wet.

The recent testing in the Bakken and log and core work would suggest that it's not going to produce high water cuts.

So in fact we may be able to be more aggressive with our frac designs.

Okay.

That's good to know.

As far as the water infrastructure up there, is that also being trucked, and any opportunities to address that?

Or is water up there not as much as maybe the other popular perception might be?

What we do pay for some water up there, and we do truck some.

We've also been able to use in many cases some surface waters.

If you've been in Divide County, it's kind of a pothole area.

There's number of natural surface waters there that we've been able to use.

So at this point, no big issue on water use.

Or water disposal?

We have our own water disposal system.

We will probably have to spend some money on water disposal on the Baytex side, but we rolled that into the acquisition economics.

Okay, so that's in there as well.

Okay, thank you.

Jeb Bachmann, Howard Weil.

Good morning guys.

Hello Jeb.

Just a couple quick questions on the graphs you guys provided for the Eagle Ford and the Bakken.

Was wondering how many wells were in that sample set?

Yes this is Javan.

As I mentioned in the script, there are 33 total wells in the Area 2 data set, seven of which were completed with high sand loadings.

In the Bakken data set, that again -- and I don't know -- seven is the perfect number I guess.

But there were about seven wells I believe in the higher sand loading test there as well.

And Jay in those tests, were some of those or all of those unrestricted chokes, or were you playing around with that early on in that process?

Typically, in the Eagle Ford we produce all these wells back on a restricted choke for some period of time just to protect the completion.

This just good practice.

In the Bakken, we do bring we flow the roles back, they get an artificial lift fairly early, so choke management's not as big of an issue there.

Okay.

I'm just try to get a sense with this program as it continues to move forward, should we see improvement in that?

I guess you talked about optimization, but should we see expect that to continue going forward here in the curves and what you're seeing on the flow backs?

So Jeb, let's make sure I'm talking about the right assay.

Are you talking about the Eagle Ford now or Gooseneck?

I'm talking about the Eagle Ford.

Eagle Ford.

Clearly we think we're going to do better over time.

We're continuing to test other techniques which we think have the opportunity to improve even on those results.

Okay great, thanks guys.

Welles Fitzpatrick, Johnson Rice.

Good morning.

Good morning Welles.

On these higher sand loadings in both areas, is it safe to assume that it does not affect your spacing assumptions in those two spots?

Great question.

I think given the outperformance of these wells, spacing is something we need to revisit.

We don't have an answer for you yet, but clearly when the wells are performing this much better, I think you have to go back and look at whether you can push them a little closer together.

Okay.

Perfect.

Just one last one.

The royalty rate on the new acreage, is that also around 20%?

Welles, I have to look.

It is, but I again -- would you call Brett back and get an exact number for that because we want to make sure we give you the correct number.

It's in the [82] rage I think, but I want to make sure I check.

Sorry to interrupt you, but going back to the question I was asked earlier, the current AFE dollar amount on the Shannon well we're currently drilling is $11.3 million, but I think over time our expectation is we can get those well costs down.

Okay, perfect.

And did you guys say the lateral length on the Dynamite well by any chance?

It's a long lateral well, about a 10,000 footer.

Okay, thanks very much, congrats guys.

David Tameron, Wells Fargo.

Good morning.

Congratulations on the momentum you're building in the two plays in the operational front.

I know Jay, you said you'd address CapEx in mid-August.

But is as we think about capital allocation, obviously Eagle Ford and Bakken I guess would be one and two.

How should we think about all the other new venture plays or East Texas Permian powder?

How would you rank those or how she would think about what stands the best chance of getting the most capital of those plays?

That's a great question and something we will be working very hard on as we go into the budget cycle this fall.

Really as you know, we rank things based on returns, and MPVs they generate.

And we will allocate capital the absolute best way we can based on the highest return wells.

I think the powder will get money, and certainly we're drilling some great wells in the Permian right now which will get in that queue as well.

But how that allocation actually works we just have to see after we look at our fall process.

David, this is Tony.

I think it's safe to say that obviously the lion's share of capital is certainly going to be focused on our key development areas in both Eagle Ford and the Bakken.

And we don't see that changing anytime soon but we have some work to do as we do our capital update.

Thanks Tony, that's right.

Okay.

And is one more question on that.

I know it sounds like I'm fishing for a number I know you won't give it to me, just directionally for 2015, you had I guess philosophically put out the framework around that before, as far as you know if you maintain a flat budget, you grow X.

I mean how should we think about -- I know the balance sheet's in good shape -- but how should we think about your desire to over spend, out spend, accelerate growth, et cetera.

Can you give us some framework around that?

Well David I will defer that question, but what I can say is that we're going to drill economic wells.

Okay.

We have never been afraid to outspend to drill highly economic opportunities, and we're not afraid to do it now.

That said, we're also going to prudent in the way we manage our balance sheet.

Okay.

I thought I'd give it a shot, but I understand you can't really talk about it yet.

So thanks for the color.

Thanks David.

Scott Hanold, RBC Capital Markets.

Thanks.

Good morning guys.

Good morning Scott.

I'm just wondering on the PRB, you certainly have shown a pretty good appetite to increase activity, and your results warrant that.

Permits sound like they're okay.

Remind me of the infrastructure situation out there.

Is that going to -- should we temper growth expectations out there until there's some key pieces get put in there?

Where we are with that.

This is Javan, Scott.

In general we're in good shape.

We've dedicated the northern area and the southern areas of our position to gas gathering, and we're actually connecting the wells before we complete them.

On the oil side, plenty of infrastructure.

There's a new rail facility going in that area.

Typically you are going to see Bakken like differentials on the oil.

So in general, if we don't believe infrastructure's a real issue, obviously the Powder River Basin is relatively new basin, and there's fewer competitors for some services.

We think that will improve over time as well.

Okay.

I appreciate that.

And then on this acquisition in the Williston Basin, I guess my question is, do you think there's more opportunity in this area?

Obviously it's been highlighted quite a bit that you all have had some pretty good performance.

Is that an advantage for you guys to go out there and be a little bit more inquisitive?

Well this is Javan again.

Yes.

Our intention is to build position in our core areas, and certainly something we're interested in doing.

Okay.

Fair enough thank you.

Thanks.

Joe Magner, Macquarie.

Thanks.

I guess following on the last question, the last year or two there's been a lot of focus on expanding some new resource opportunities organically with this bolt-on acquisition.

How should we think about allocation of capital going forward between those organic opportunities and more acquisitions.

I appreciate that you're just interested in coring up some of your growth areas, but is there a bit more of a shift towards acquisitions, or is this just an opportunity to bolt on the core area and it's a not necessarily a one off, but not a specific change to your strategy going forward.

Yes Joe, this is Tony.

Good question.

I would say at this point we see our highest potential for growing inventory with our current core development areas, and I think as you can see from the results, that we've share this morning, and last night, we certainly believe that.

And we're seeing some great results in growing inventory from these core areas.

As Jay just mentioned, another key part of our growth strategy is to see where we can continue to add acreage in and around these core areas because if we have success there, then we hope to extend that into some additional new acreage.

Regarding new ventures, I think at this point we have a pretty compelling portfolio of opportunities.

So we will continue to look out there, but I think we've got a very compelling set of assets right now, and our focus is on continuing to exploit what we've captured already.

I think it is safe to say that in addition to true expiration and looking at new ventures, you are going to see more emphasis from us on key acquisitions like we've announced this morning.

Okay.

That's all I've got.

Thank you.

Thanks.

Before we take the next question, let me note that Baytex NRI in the 126 spacing units ranges between 81.6% and 82.1%.

Or right at 82%.

(Operator Instructions)

John Nelson, Citigroup

Good morning.

And congratulations on the quarter.

Thank you John.

Could you just remind me, is $100 million still the right way to think about the annual CapEx level to run a PRB rig?

I haven't looked at the numbers., That depends entirely on the working interest.

I think on a gross basis, $100 million is not far off for 100% working interest, but I have to look and see.

Our average working interest in these wells is in the 55% range.

Yea.

Fair enough.

And then just on the comment that you see permits that have sufficient to run a forward program, can you just talk to what a framework around that statement is?

Does that mean over the next 12 months you have sufficient visibility, or how you get to that statement?

While we've been adding rigs one at a time here as we build inventory and permits.

Currently has something like 36 permits approved, which is probably six rig years worth of activity or five rig years worth of activity.

We have a number of permits in the queue and a number more in preparation.

So I think in general we feel very comfortable that we have enough permits to stand up and run a consistent four rig program, and potentially more rigs into 2015 depending on how our capital situation looks.

That's really helpful thanks.

And then just last one for me.

In the Permian obviously industry activity has heated up, and relatively you guys have a smaller position.

Are you seeing any pressure in operating in the Permian?

This is Javan again.

In terms of pressure, I'm going to assume what you mean is cost pressure or ability to get things done.

Certainly.

Rig count in the Permian is very high.

Activity levels are very high and going higher.

There is some cost pressure, although not a lot, mean I probably call it a 5% annual cost increase rate at this point.

We share frac spread there with other parties.

We're able to get our fracs in when we need to.

Would love to get our activity level higher; with some success we might be able to do that and get our own frac spread which would be good.

It is a very busy area, it is a bubbly environment right now, and that happens in all these basins at some period of time.

We just have to get used to it.

John, I would point you to the latest Baron and Associates report.

They gave a basin by basin cost update.

And most of the basins are relatively flat, maybe a 1% or 2% expected for the year, but nothing dramatic.

And the one exception there is in the Permian, and that's probably more in the 3% to 5% range.

But today we haven't had the faculty acquiring the goods and services that we need to go ahead and execute on our program.

That's very helpful.

And then just last one for me.

Which would be expecting result wise in East Texas either in 3Q or 4Q?

Any updates for when we should expect to see those wells?

As I indicated earlier, we're currently installing infrastructure to be able to do long-term production tests on a number of our wells.

The key piece of data that we need is how do these wells decline over time.

We already know we have good pressures, they look very productive initially, and we think they're going to have acceptable liquid levels, liquid loading levels.

Really the big issue is what that decline rate look like.

We're working on the infrastructure now, we hope to have some results obviously takes time to get a long-term production test.

We hope to have results by year-end.

Okay.

That's all for me.

Congrats guys.

Thank you John.

Joe Allman, JPMorgan.

Thank you.

Morning everybody.

Good morning Joe.

So in the Eagle Ford in Area 2 with the new completion design, so how does that impact the EUR?

So what's the new EUR associated with those, that increase in rates of return and PV that you decided?

While Joe, we haven't estimated an EUR yet.

Clearly it's going to go up in proportion to the productivity of the well.

I haven't gotten a new EUR number for you, but it's clearly up.

Okay, got you.

And in terms of the size just changing the profit loading.

Do you expect to make some other changes going forward?

So for example are you going to try shorter frac stage lines in closer spacing and things like that?

This is Javan again.

We're testing all the things, we're also looking at using more hundred mesh in these jobs, which is both a cost savings and we think a potential for interesting improvement opportunity there.

Got you.

And Jay, similar to the way you did this testing by basically changing one variable, do plan on changing one variable at a time just to see how each variable has an impact?

Certainly we try.

You want to move quickly as well, and you can't wait a year to test everything.

So there are cases where we will change more than one thing where we think we can sets out how those impact things, but generally yes you should try to change one variable at a time.

The whole theme here is that we're getting bigger stronger faster.

We had a great asset.

If you go back four or five years, this company didn't have these big chunky assets that you could really work on.

This is a huge opportunity for us to go in and just make this stuff better and more valuable.

I think we've accomplished that, as we talked this quarter I think you're seeing higher values, I think you will continue to see a more valuable development as we go forward.

Got you.

And in terms of the Bakken, you talked about using sliding sleeves.

So have you tried plug and perf, in the Bakken and if so how does that work?

We have just started doing some plug perf completions, and we don't have results on them yet.

We just started pumping some here in the last couple of quarters, and we're optimistic about it but I don't have results back yet.

Okay, and Eagle Ford, what completion design are you using there?

That's a cemented plug perf design.

Okay.

Just a couple quick ones.

Scott Hanold may have asked this one, but in the frontier -- or did I miss the answer if he did, the frontier play, what does the infrastructure look like?

And are you constrained in any way from ramping that up pretty quick if you wanted to?

Again the gas site infrastructure we're in good shape, we got dedicated areas to two different gas gatherers who are working well with us, and we're getting our wells hooked up before we complete them.

On the oil side, the oil generally there's new infrastructure out there, some rail facilities going in.

We trucked some of it today, I think there's opportunity over time to hook most of that up to pipe as well, so no real delays.

These are long cycle wells.

It takes from the time you drill a long lateral well, you get hooked up to get it completed, it probably takes 120 days from spud to production.

And that's another opportunity for us here is to try to squeeze that time down over time.

We certainly were able to do that in Eagle Ford over time, with think will be able to do it in a powder as well.

Got you.

And two real quick ones with the Baytex acquisition, how many drilling locations do you think you add with that acquisition?

Thanks for asking that.

I figured that would be a question today.

Let me put it this way.

My math would suggest that given the value of the PPV that we only need to do one good drill well for spacing unit to pay for this.

Now we're drilling our other Gooseneck acreage at four Three Forks wells for spacing unit, and we haven't even got to the Bakken yet.

So we're not going to put out a number today of how many wells we're going to drill, but I think you can assume that we think there's a ton of upside in this asset.

Okay, great.

In an earlier in the call, I think you talked about how much of your acreage in the frontier is -- how much of that acreage is perspective for the frontier, and the powder.

Did you say 127,000?

That's the number I gave yesterday.

Okay, very helpful, thank you.

Michael Hall, Heikkinen Energy Advisors.

Thanks.

Appreciate the time.

Many of mine have been answered, but I guess to some housekeeping on that Divide acreage block now.

What's the average working interest across the ownership after the deal?

It would be somewhere between 37.5% and 50% on a typical well drill.

It depends on whether it's in an existing spacing unit, or whether some people may have not consented or on the base acreage where we basically own 37.5% of an AMI.

Okay.

Thanks.

And then you alluded to --

Before we move on from that, let me just say I personally view that as an opportunity.

I think over time we will be able to pick up additional acreage of this.

Yes.

Point taken.

And then you've made some commentary around seeing some improved results or optimistic results from the Bakken and any additional elaboration of what you're seeing and its time frames on additional data?

We're running a number of different completion tests in the Bakken including the plug perf test I referred to.

We're running some higher sand loading test, and we're doing some down spacing work.

Most of our Bakken work will get -- is getting done now, and we probably won't have results till late this year.

We also have a state line test that we've mentioned earlier that we're doing.

And there is a hurdle in the Bakken water handling and dealing with water from the reservoir, or is there --?

Are you speaking specifically at Gooseneck now?

Up in Gooseneck.

We don't see that as particularly a hurdle.

These wells produce at higher water cuts than typical Bakken but not superhigh water cuts.

That was one of the concerns early on, but it has not proved to be the case.

Okay.

Helpful, thanks.

And then in the Eagle Ford, I believe you had some upper Eagle Ford tests in the hopper.

Any updated commentary around that or just a reminder on finding and when we might hear about it.

We do have some planned upper Eagle Ford tests.

Haven't released results on those yet, probably won't until sometime later this year.

All right.

Appreciate it, thanks for your color.

Thank you, and at this time I'd like to turn the call back to management for any closing comments.

This is Tony Best.

Thank you so much for joining us for the second quarter call.

We look forward to updating the SM story again next quarter.

Thank you for calling in.

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

this does conclude today's program.

You may all disconnect.

Everyone have a wonderful day.