SM Energy Co (SM) 2013 Q2 法說會逐字稿

Good morning my name is Melinda and I'll be your conference operator today.

At this time I would like to welcome everyone to the SM Energy second quarter 2013 earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers remarks there will be a question and answer session.

(Operator Instructions)

Thank you Mr. David Copeland, Executive Vice President and General Counsel you may begin your conference.

Thank you Melinda.

Good morning to all joining us by phone and online for SM Energy Company second quarter 2013 earnings 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 to our website for this call and the risk factors section in our form 10K that was filed on February 21, 2013.

We'll also discuss certain non GAAP financial measures that we believe are useful in evaluating our performance.

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

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

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 these non-proved reserve metrics.

Company officials on the coast morning are Tony Best; Chief Executive Officer, Jay Ottoson; President and Chief Operative Officer, Wade Pursell; Executive Vice President and Chief Financial Officer, Brent Collins; Senior Director of Planning and Investor Relations and I am the Company's Executive Vice President, General Counsel, and Corporate Secretary.

I will now turn the call over to Tony.

Good morning everyone and thank you for joining us for the second quarter 2013 SM Energy earnings call.

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

I will begin on slide 3. The Company had an excellent second quarter.

I know most of you have already reviewed our press release from yesterday, so I'm not going to go over that in detail.

However, we had a very strong quarter on the production front driven by our growth from all of our development programs led by our operated Eagle Ford.

In fact, we set a new quarterly production record for the Company in the second quarter.

Guided costs in aggregate came in at the lower end of guidance.

Adjusted net income was $51.8 million or $0.76 per diluted share and EDITDAX set a new quarterly record of $342.5 million.

I'm now on slide 4. As we press released yesterday, we are increasing our production forecast for 2013 by approximately 10% to a range of 47.3 to 48.6 million barrels of oil equivalent with only a corresponding 3% increase in development capital.

The operated Eagle Ford program is the largest driver of this increase in production.

In that program we are going to be able to drill, complete, and flow to production roughly 20 more wells at a total cost close to our original budget for the year.

We are benefiting from a number of efficiencies in both the operated and non-operated programs in Eagle Ford that Jay will talk about in a little bit in his review.

I will also point out that there is essentially no contribution assumed in our 2013 production guidance from our new play areas in East Texas and the Powder River Basin.

Yesterday we also reiterated our 15% per annum production growth targets for 2014 and 2015 on retained properties.

Given that we are increasing 2013 production by 10%, the production numbers in 2014 and 2015 are expected to be 10% higher as well.

These targets assume that we will close our previously announced planned divestiture of Anadarko basin assets on January 1, 2014 and that these assets will contribute approximately 3 million barrels of oil equivalent of production this year.

These growth targets assume modest success in our frontier program in the Powder River Basin and minimal success in East Texas.

While with success these growth targets could improve, perhaps significantly.

I am now on slide 5. With respect to our revised capital forecast, we are increasing our capital program for 2013 to approximately $1.65 billion which is a 10% increase over what we had originally budgeted.

As I mentioned earlier, our development capital increased slightly to $1.24 billion.

Our development program remains focused on the Eagle Ford and Bakken Three Forks with 75% of our development capital being allocated to just those two plays.

The biggest portion of the capital increase relates to our non-development capital that will provide inventory to drive our future growth.

The $65 million acquisition of Powder River Basin acreage that we previously announced wasn't budgeted so that is part of this increase.

Our revised capital guidance also includes an increase in non-development investment in our new ventures effort where we continue to test and delineate our emerging East Texas and Powder River Basin plays.

Moving to slide 6, I would now like to take a minute to talk about a key element of our business strategy.

Because we intend to be a long term business enterprise, we know that we need to replace inventory and you can do that in one of two ways.

You can grow organically with self development or you can buy it through acquisitions.

Our first preference is self development because it generally allows for higher returns and the downside risk is less impacting.

I know that when I talk with many of you in the investment community at the conferences or during one on ones, we talk about ideas and projects being worked in our new ventures program.

But today, I want to explain why we have such a program.

On the slide you can see the phases of our new venture process.

I'm not going to go through all the steps in detail but the general idea is that we distill a number of geologic concepts down to a couple of potentially impactful prospects that if successful will ultimately compete in our development portfolio going forward.

That is not to say we will never do acquisitions.

We think that acquisitions have a place in our business strategy particularly when we believe that we may know something differential about an asset.

We have and will continue to evaluate a broad range of acquisition opportunities.

Moving to slide 7. You can see how new ventures fits into our overall business strategy.

As a resource play company, you must restock your project inventory so you can continually hydrate your portfolio going forward.

Remember that the key plays growing our Company today, and I am speaking primarily the Eagle Ford in the Bakken Three Forks, were sourced as new venture efforts four or five years ago.

As you can see core development remain our primary focus as we work to concentrate our capital on our highest rate of return projects.

We intend to operate our projects so that we can control the pace of investment and the quality of development which allows us to improve our returns.

We focus on debt adjusted per-share metrics because we believe that is the right way to gauge our performance.

When it is clear that project or asset will no longer compete within our portfolio, we look to monetize it and redirect the proceeds to higher return projects or to enhance our balance sheet.

With that am going to turn the call over to Jay for his operational review.

Think you Tony and good morning everyone.

As indicated on slide 9 we grew our corporate production volumes by 15% quarter-over-quarter and we're up 42% from a year ago.

All of our development areas had nice production gains for the quarter led by our operated Eagle Ford asset.

Moving to slide 10 I will discuss the operated Eagle Ford.

Obviously we had a really strong quarter.

We grew 28% on a sequential basis and 92% year-over-year.

We benefited in the quarter from a large number of new wells being connected to sales and added capacity in our gathering system.

Our swath drilling program resulted in nearly all the wells brought on in the first half of 2013 being in lower condensate yield Galvan and Apache Ranch areas of the field.

We also had a number of oilier producing wells shut in due to simultaneous operations associated with completing new wells.

As a result the production mix is gassier both for the Eagle Ford program and the Company in total for the quarter.

As we move into the third quarter, our oil rate will pick up as most of our new wells being currently brought on production are in higher yield areas on the north side of the field.

In fact I can say, that our oil volumes are already up strongly in July.

On the infrastructure front, our gathering infrastructure will be significantly expanded in the second half with the addition of eight new field gathering centers to our existing 10.

Our guidance assumes that tie in of these new facilities may curve our production growth for periods of time later this year, but these new facilities will allow us to continue to increase rate and reduce field separator pressures in 2014.

I should note that we used interruptible downstream wet gas transportation on a daily basis all quarter in addition to our contracted firm transportation.

Our firm gross wet gas transportation level rose again in July by 80 million standard cubic feet a day to 380 million standard cubic feet per day.

However, we do anticipate utilizing interruptible transportation again by year end and in the first half of next year and don't foresee any problems with space being available.

The biggest story in our Eagle Ford program, however, is really in our increasing development efficiency.

Our last 15 wells in the Briscoe area averaged $5.4 million per well, a 13% decrease in the cost per foot of well over the last year.

Because of these cost savings, we expect to now be able to bring on 95 wells in 2013, a 20 will increase over our original plan, while spending little more than our original budget.

In summary at this point in the year our operated Eagle Ford production is ahead of where we expected to be and our improved capital efficiency in the play is the major reason we can increase our corporate production guidance with a very little additional spending on rate generating projects.

In a non-operated Eagle Ford I am now on slide 11, production was up 9% quarter-over-quarter and is up 83% since last year at this time.

Anadarko accomplished a lot of facility tie in and new plant start up work during the quarter so was a very busy time for them.

We are encouraged by the decreases we are seeing in Anadarko's well costs and some of the experimentation they are doing to further reduce costs and do longer lateral's and revised frack designs.

We learn a great deal from our partnership with APC, which is an additional benefit to us beyond the opportunity to participate in a very economic development.

We believe the operator will be running at least nine rigs for the remainder of this year.

As you know we are being carried by Mitsui on essentially all our share of drilling and completion costs into 2014.

Moving to slide 12, during the quarter in our Bakken Three Forks development area we swapped out two older rigs for a more efficient pad drilling rig and we are now operating three rigs in the program which we plan to do for the remainder of this year.

During the quarter were brought on 12 new operated wells and saw sequential daily production growth of 12%.

In our current primary drilling areas Raven and Gooseneck we have seen operational efficiencies from the implementation of pad drilling.

Our Gooseneck well costs are down about 8% percent from the numbers we quoted at year-end 2012 to about $6.5 million.

We are participating with others in Bakken down spacing tests in the Raven area and in lower bench tests in the Three Forks.

There have also been some interesting industry results recently in the Bakken interval near our Gooseneck acreage where we've been drilling only Three Forks wells previously.

So we believe there are continued opportunities for adding economic resource in our Bakken Three Forks play area.

I am now on slide 13.

In the Permian Basin we grew production 25% on a sequential basis to 6,600 BOE's per day.

This is largely being driven by increased contribution from our Mississippi and line play as we completed several more wells there in the quarter.

We also drilled a Wolfcamp shale well in the southern Midland Basin that is currently flowing back after completion.

We hold about 20,000 net acres in the southern basin of which about two thirds is operated.

Of the three rig program we plan to run in the Permian in the second half we now intend to maintain a single rig program focused on shale wells.

We'll also be participating in wells on our non-operated acreage targeting shales.

On slide 14, we've included a synopsis of new ventures activity for the quarter.

During the quarter we closed on our previously announced acquisition of approximately 40,000 net acres in the Powder River Basin.

Our objectives in the stacked pay Basin are the Frontier, the Shannon, and the Sussex.

We have a total of 110,000 net acres in the Powder River basin.

We will be picking up a rig to start our development there during the second half of the year.

In East Texas we continue to build our acreage position.

During the quarter, we added another 45,000 net acres to our position bringing our total committed acreage to 195,000 net acres.

We just started up a rig there and are planning to add a second rig later this quarter.

We hope to have some additional well test to share with you by late this year or early 2014.

We will be testing in both the Eagle Ford and the Woodbine and there are some other intervals of interest as well.

In other business as Tony mentioned we have already announced that we are moving forward to sell our assets in the Anadarko basin including our position in the granite wash.

We expect the data room for that package to be open in September.

We also have several smaller largely non-op packages that are being marketed right now.

We hope to have all these deals closed before year-end.

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

Thank you Jay.

Good morning.

I'm on slide 16.

During the second quarter we issued $500 million of high yield notes with a 5% coupon rate in a 10.5 year maturity.

We used the proceeds to pay off our revolver.

To be frank, the issuances was mostly opportunistic because the 5% long term unsecured coupon was too good to pass up.

As you can see from the left side of the slide our capital structure remains very straightforward.

With four pieces of senior debt and a revolver.

Debt to trailing 12 months EBITDAX actually fell slightly in the second quarter and our debt to book cap remained flat at 52% from the first quarter of 2013.

On the right side of the slide you will see that the earliest debt maturity is not until 2018.

With respect to liquidity our revolver, which was nearly undrawn at the end of the second quarter, has a total commitment amount of $1.3 billion and a total borrowing base of $1.8 billion so we have plenty of dry powder.

Moving to slide 17.

I would like to discuss how we look at leverage.

We believe the debt to trailing 12 month EBITDAX is an important metric and one we use to manage the balance sheet.

By the way it is the only financial covenant in our loan agreements other than to maintain positive working capital liquidity.

Our current debt to EBITDAX multiple is well below the peer average of 2.5 times.

In fact it decreased slightly in the second quarter to 1.3 times.

We now expect to be below the previously guided 1.6 times at year-end 2013 despite the increase in CapEx that Tony discussed.

We plan to manage our leverage to a point where we can invest in projects that provide superior returns and grow EBITDAX production and reserves on a debt adjusted per share basis.

Lastly, with respect to hedging, we did add some hedges in the second quarter.

We actually now have the highest percentage of PDP hedged that we've had in recent history.

As most of you know we sell most of our operated Eagle Ford condensate at prices linked to LLS prices.

So we added some basis swaps to help protect our Eagle Ford pricing.

We also layered in some more natural gas hedges when we saw prices up around $4.

Details of our hedging position can be found in the appendix to this presentation and in 10Q filed this morning.

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

Think you Wade.

Before we turn the call over for questions I wanted to touch on a few closing key messages.

First, we had a strong second quarter with reported production well above our guidance range.

We also performed well on our total cash cost coming in at the lower end of our guidance.

Second we have increased our full year production guidance by 10% with a range of 47.3% to 48.6% million barrels of oil equivalent and we are also increasing our production outlook for 2014 and 2015.

Our development programs as Jay mentioned are performing well and with success in our new ventures program there is upside potential to our production outlook.

These programs could fuel our growth for years to come.

Lastly, as Wade mentioned our balance sheet remains strong and we expect to end the year with debt to trailing EBITDAX below 1.6 times even with our capital guidance increase for 2013.

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

(Operator Instructions)

Nicholas Pope, Cowen and Company.

Just looking at the big bump you had to in the softer guidance for 2014 and 2015 production numbers.

I know you had spoken previously about trying to get CapEx and cash flows fairly close to one another within the next year.

I was wondering what the thought process is now, with that increased production profile, if that is going to change the viewpoint of CapEx spending over that same time frame?

Nick, this is Wade.

Obviously we will give much more specific guidance later this year, on next year.

I think the comment I would make is that we feel very confident in reaffirming that 15% growth even on the higher production number.

And I would say that from a standpoint of what's assumed in there, I think earlier we said it was based on our current programs.

I would say there is no East Texas assumed in that projection and we just make the PRB there's a modest contribution from PRB.

But I think that should help you in your thinking from a standpoint of what is included in the general assumptions in that growth.

I think the answer to are we going to exit the year with EBITDAX in excess of CapEx?

I think the answer, I would answer that as saying we could.

I would also tell you that if we don't, it will be due to good reasons like spending in East Texas, PRB, and maybe some success in Permian shales.

But again will give much more specific guidance in that later this year.

All right that's great.

A little housekeeping, on the drilling carry from Mitsui, do you know where we are -- where we stand right now?

How much is remaining and where with the increase paste, where that might switch back to everybody paying equal costs?

Our thinking now is sometime around the middle of 2014 probably late 2Q, early 3Q, obviously will be watching a closely in it will depend on the pace of capital from Anadarko.

Jeb Bachmann, Howard Weil.

Just had a few questions, I just want to dig a little deeper into the improving well costs and the operated Eagle Ford that you had.

And if we could get a little more detail as to where you saw those improvements, where they on completion design or efficient rigs if you could?

Thanks Jeb, for the question, I think it really is an important one and I would have to say we are seeing improvements in all areas.

A lot of it is days to depth, we are just drilling faster and I give the guys in our drilling department a lot of credit for that.

I think if you look at us from an industry standpoint I think we are one of the quickest drillers in the basin down there now.

And our completion efficiency is getting better, our pumps are ready when we need to pump, we are getting better every day at getting these wells completed.

I would say it is pretty much across the board there's obviously some benefit associated with our pad and swab drilling as well that is incorporated.

Jay you think the trajectory of that will continue to move down going forward?

How much additional improvements do you think you could realize?

Obviously that is a more difficult projection.

We have made so many strides it is hard to say, it's not going to continue forever, obviously.

I think there is some room to continue.

I think we're also going to be focusing on drilling some longer lateral wells and experimenting additionally with our completion.

So those things may work against cost reduction but may help us on the EUR front.

This is primarily in area one or is this also area two and three where you're seeing these improvements?

Well we've seen improvements in area -- in the Galvan area, area three before, we really haven't drilled much in area one since last year.

So the last 15 wells we drilled are largely area one wells so that is why you see the big decrease versus last year.

We have already seen these kinds of reductions in our drilling program in Galvan say the area three area earlier this year, so just a continuation of a trend.

Just a couple of quick ones.

One, when you mentioned the production mix should improve on the oil side going into 3Q, are we looking back towards 1Q levels or maybe even a little bit north of that?

I should say this is Jay and I forgot to mention this is me.

The numbers are strongly up, we fully anticipate getting to that 50% gas production split by year-end.

I don't know that I actually even know where we are relative to first quarter right now, but we are up strongly from second quarter.

On the asset sales, how much of that is going to eliminate the MPP's on your income statement?

I think is good to be similar around $9 million $10 million Jeb.

Okay so you will still have some left over even with those asset sales?

That is true.

I believe on the balance sheet that we just release it is around $70 million so yes, down to 60-ish.

Then just one quick one?

Jay you mentioned on the interruptible takeaway end of this year into next year do you have percentage of how much you're going to be shipping on interruptible takeaway?

The last time we looked at it the number was about 7% in total.

That depends very much on what our actual production -- how our actual production lays out, so that was on a guided basis.

All right, great appreciate the answers guys.

Subash Chandra, Jefferies.

On Briscoe, curious how you're looking at second half drilling as far as EUR expectations go to get closer to that 600,000 BOE type curve?

I think on the last call we spent some time on pretty valid reasons as to why you weren't quite seeing the numbers that you thought be refresh of those thoughts.

The impact of RCS have if you've tried it there and if you can try it there?

And that downtime that you refer to on oil, if there is a way to quantify that for the quarter then I have a follow-up.

I think I heard three different questions there and I will try to answer the first one first.

Briscoe, the new wells are just starting production so I don't really have any comments on EUR's relative to those.

We did talk about that at our last call.

In fact if you look at our type curves in area one, all our type curves are driven based on gas production in then we apply a yield.

If you look at the type curves that we put out for area one, the gas forecast that we put out lay right through the middle the historical data if you adjust for downtime.

Really the issue is yields and as mentioned on the call, last call, we are drilling in the higher yield areas of the field today and those are the wells that we will be bringing on.

What we will really be looking at over the next six months is how does that yield look versus our expectation.

You made a comment about some specific technology RCS and right at the moment that is escaping me as to what you mean by that.

I can maybe make transient analysis.

I'm sorry I meant what your spacing is -- your frack spacing is and if there is a way of trying to replicate some of the other parts of the Eagle Ford and other liquids rich plays to get denser frack spacing?

Definitely were looking at a number of different things and I will say APC is as well, longer lateral's, different frack spacing to try to improve our performance in the oilier areas.

The issue you have to deal with in a lot of our northern areas especially in the northwestern part of our acreage as you have a lot lower pressures as well.

I think we need to do more work there, we frankly, just have not drilled that many wells in that area of the field and we need to continue to experiment to try to drive improved performance.

And then I am forgetting the third part of your question if you could repeat that.

The Briscoe oil downtime?

I don't think I can actually quantify that for you but I can tell you that by looking at the warning reports that I see we've had a large percentage of oil shut in --a larger percentage of oil shut in during the second quarter.

The way our swath drilling program works is we actually drill and complete the wells all in one area and we have a lot of wells shut in before we bring them on.

If you look at this year's schedule we drilled and completed a lot of Galvan area wells way back in the first quarter and about them on in the second.

We've been drilling and completing in the Briscoe area basically in the second quarter and we will be bringing them on in the third.

Because our wells in the Briscoe area are higher yield typically those simultaneous operations and differentially impact oil production.

As I said earlier, we are seeing strongly higher oil rates already in July so we think that essentially we'll get back on what I suppose most people would have regarded as a normal trend for oil.

We anticipated our oil rates being down a little bit this quarter.

A final one for me.

How are you thinking about PRB repeatability versus say Eagle Ford?

I notice it's early but if you had any thoughts there?

Think your comment is, it's really early.

So far, so good.

Everything we drilled is confirming with our type curves to date.

We don't have any reason to doubt our type curve but it is very, very early.

As you think about, do see more of a distribution curve similar to conventional play?

Or do you think there is some type of shale repeatability here based on some of the subsurface work you might have done?

Well what we've seen so far is that we think that what we will call the P10, P90 range is really how you measure this on a UR is what we have seen so far is we think that range is not going to be super real, real wide.

It looks more like a shale play from that standpoint.

But again, it is very early.

Matt Portillo, Tudor Pickering Holt.

On the operated Eagle Ford, just had two quick questions for you.

Firstly, as we look at the completion count pretty similar to the first quarter, but obviously saw a pretty dramatic uptick on the wells kind of look like a 2 X productivity on the wells.

I was just curious if that was a function of, purely a function of where you were drilling those wells or if that was also a function of improving IPs and EURs in the play.

And then the second question I just wanted to ask if you could just give us a little bit more detail in terms of the spud to spud times for you guys and how that has changed over the last year or so?

And then ultimately where you think the technical limitations maybe on the drilling times?

I will comment first on why the production seems a lot higher in the second quarter.

A large part of it is really capacity availability in our gathering system.

We added compression during the quarter and did some additional facility work.

Had some excellent performance by our gathering system provider Regency, which allowed us to bring on a whole bunch of new wells at pretty high rates.

We were drilling, frankly in the best area of the field in the first quarter brought on a lot of those wells in the second quarter.

Too early to say whether the URs are better but certainly a lot of really strong wells in the Galvan area which frankly, is what we anticipated and we were able to take advantage of that during the quarter.

As far as exact spud to spud numbers, frankly I do not have the data in front of me I do not want to misquote a number.

The numbers are down and they have been down all year and we have seen significant cost reductions.

As far as technical limits, we are very close at this point I would say when you start look at that perfect well process and how fast can you drill each section, we are pretty close to where we thought we could get.

That doesn't mean that we can't do better, I think we can do better over time, but certainly there are diminishing returns.

Once you are drilling these wells at 9 or 10 days it gets hard to get a lot faster and frankly another day doesn't save you that much money because you still have to complete the well.

I think a lot of what we need to focus on now is really, okay our (inaudible) machine is really running well, we really need to focus on how do we make better wells.

In particularly some of the oilier areas of the field that are lower pressures, were we actually have thicker reservoir, how to make better wells, sort of the question I talked about earlier.

We're going to put some significant effort into that, Anadarko is a good friend to us in this sense in that they are doing a lot of experimentation with that as well so we learn a lot from them.

That is really going to be the focus I think of our technology effort over the next year or two.

Great and then just one quick follow up, in terms of the Permian we've seen some interesting results for you guys in the mix and your drilling your first Upton well now, but I think offset industry data looks very encouraging.

Could you talk a little bit about the scalability of the asset, how material this could be for you over time and maybe a little bit about how you think about the long-term plans in the play if you kind of ultimately prove up the commerciality potential there?

Well we mentioned earlier that we have about 20,000 acres in the southern Midland basin.

There's multiple potential pay zones in Wolfcamp section for example on most of that acreage, and it is a really good area.

A lot of our acreage is not very far away from some of the bigger wells that have been announced in the southern basin.

We also have additional acreage in the northern Midland basin.

I think we still need to test that and there is some industry testing in the northern Midland basin that we are looking at.

It can add up to a lot of locations.

If it works, especially if you can pursue multiple benches it is a material addition to our resource.

And I really believe, I think the Wolfcamp shale if you look at all the shales that people chase in the Permian I really think the Wolfcamp is the place to be.

Both on the Midland Basin side and on the Delaware Basin side.

I think it is the shale I think that it has got the most.

We think it is material, were obviously attempting to build position where we can, it is expensive but we want to build more position there.

Scott Hanold, RBC.

Good quarter, I want to go through a couple of things, obviously you had a very strong production coming from the Eagle Ford.

The transportation cost in that region were quite a bit higher than I guess, I'd expected and is utilizing interruptible part of that dynamic or interruptible will inherently carry a higher transportation cost, is that a true statement or not?

Scott that actually is not true, but let me explain transportation cost for you, it is a really good question and needs to be answered.

It is not really the interruptible that is driving the higher cost.

There is several things.

First of all, the unbudgeted volumes that we produced are all being produced to our last pipe in our firm transportation pile of bricks that we built with firm transportation.

And we're also using that pipe for the interruptible, so it is going to the same place.

That last pipe has the highest per MCF transportation cost.

It also has the highest NGL recovery so the economics are very similar to the rest of our pipes.

But it has the highest incremental transportation cost, the stuff that actually shows up as transportation costs.

So as we increase volumes to that pipe our transportation costs go up disproportionately.

During the quarter we also started, during the first half we also started up additional compression in the field which we pay additional fees to our gatherer for that and we have to pay for the fuel for that.

I know does not seem like it, but gas prices were actually little bit higher in the second quarter so our fuel costs were up some.

Those are the major things that are driving, have been driving and are driving our transportation costs up.

The lion's share of our company transportation costs really relate to Eagle Ford wet gas transportation both operated and non-operated.

As of those volumes ago up the corporate numbers go up but the Eagle Ford operated numbers have been going up for the two reasons that I have given you.

Okay that's very good, that's very helpful.

The other thing is your goal to get 50/50 gas to liquids by year end, what assumptions are built into ethane rejection to that?

Is there any improvement on that by the end of the year?

Scott I think we've talked about this before.

There is about 2 to 3 DCF impact associated with the ethane rejection that is baked into our numbers so obviously if we weren't rejecting we'd get there quicker.

It is not a huge material impact we think we will get there anyway.

We are still rejecting ethane under contracts in the Eagle Ford where we can do that or where we have that election.

One other question, On the Eagle Ford well that you will be bringing online in the back half of the year, more oily than some of the average mix right now.

So if you look at your Eagle Ford operated it was roughly 63% gas in 2Q, can you talk about some of those new wells coming online, what percentage oil versus gas those are going to have?

Scott I don't have those numbers directly in front of me.

It is going to go very much in an oilier direction so that percentage is going to move.

What you are seeing -- what you are going to see is our gas rates aren't going to go up as much but we are going to become oilier over the next couple quarters.

In as far as Eagle Ford itself, what would you, 50/50 is a total company what could the Eagle Ford be around the end of year in terms of oil gas mix?

Scott I don't think we've ever guided that and I really don't know the exact number.

I know how it makes up in the total overall corporate number and obviously it drives a lot of our corporate performance so it's going to get oilier, but I don't have an exact number for you.

Welles Fitzpatrick, Johnson Rice.

Looking at the public data doesn't seem like you guys have had any significant issues getting permits up in the PRB.

Is that an accurate statement?

This is Javan again.

We haven't had trouble getting permits for the activity we currently had planned.

I think what we've tried to do, we are going to pick up a rig in the second half.

We have a plan, our tentative plans for 2014 are to pick up additional rigs, we're certainly trying to stack up permits, enough permits to keep a multi rig program going for a number of years.

Typically, I think we've tried to guide people to a relatively modest rig count in the powder just because federal permitting is slow and arduous.

And we don't want to give people the impression that we're just going to run in there and throw a huge rig count at it.

So far and we have a good relationship with the BLM, we are working hard to make sure that when we submit permits that they are complete and accurate which is very important to them and to us.

And we haven't had trouble getting permits at this point.

If I remember correctly your next Frontier well was going to be a on sometime around mid- year, obviously you don't have the results for us today.

But is that far along enough to comment on the cost relative to the $14 million to $15 million for the first batch?

Our cost are still higher than the $14 million, $15 million ultimate cost that we think we will be at.

I think that we'll probably is going to run almost $16 million by the time we are said and done.

With a lot of science I mean --

That particular well didn't have a lot of science with it, but it is new and it is deep and we clearly it was a little more expensive than where we expect to be.

The $14 million, $15 million range assumes that we are going to optimize somewhat.

One last one, as far as the Eagle Ford and East Texas it seems like there are a couple of schools of thought.

Clayton Williams having success just below the chalk and Halcon finding success just above the Buddha.

Do you guys, is it just too early to say where you think you're going to be landing these within the Eagle Ford zone?

Yes, I think it is.

There is a lot to learn, is a very large acreage position we've only announced one well I think in the whole play so far.

There's a lot of things going on out there, a lot of people drilling and we are obviously going to learn as much as we can from other people.

Ryan Todd, Deutsche Bank.

A couple of questions, first of all I guess on the Permian Miss.

Last quarter you had released the results of your first longer lateral well there and I know you turned on some additional wells in the quarter.

Any additional thoughts on the longer lateral well program there and its potential?

How should we think about, we've heard quite a bit about the Permian Wolfcamp about.

What are your current thoughts on the Permian Miss and at what point do you think you might be willing to give it a thumbs-up or thumbs down going forward?

Well we completed a couple additional wells in the Miss during the quarter nothing really, not really any new news there.

I think in general we said at the last call that we think the central and northern areas probably look better to us and I think that is still true after the completions we made.

We've had some issues getting these wells lined out, so we didn't talk about rates this quarter.

I do think the longer lateral's help.

There is still a wider 1090 range on the MIss program then generally we are comfortable with to really put our foot on the gas.

So we have an argument going of whether we are still delineating or whether we are really developing at this point in I guess I would say we would probably lean a little bit toward still being a little bit in delineation mode.

As far as the Wolfcamp shale goes there are some great wells in the basin.

We are watching that with great interest and we're picking up a rig, so that tells you how we feel about it.

One final follow-up on the operated Eagle Ford, how should we think about I guess in plotting your numbers next year how should we think about the activity levels from a well count point of view?

Is this year as well count a decent way to think about it or should we see some upper pressure on that?

Your question was specific to the Eagle Ford is that right?

Yes.

I think it generally you should expect that our well counts will be similar.

We have got a lot to do, we have got a nice program going, we are drilling great parts of the field.

I think our rig count, our well count, completed well count will be very similar to this year's.

Mike Scialla a, Stifel Nicolas.

My question is for Wade, that other expense item this quarter of $35 million, can you say what was included in there?

I think you had the royalty adjustment of $10 million, but beyond that what else was in the $35 million number?

Wade do you know the detail of that?

I do, so that is gas marketing expense Mike so if you, up in other revenues and this is gas marketing so those net down to essentially zero, which they typically do every quarter.

Jay you mentioned in the Gooseneck area that there is some interesting developments going on in the Bakken.

I thought the water cut in that area was very high which had been preventing development of that in the past.

Can you talk about what has changed there?

There have been some completions on the eastern end of our acreage that are interesting and the logs look wet, and so it is a little surprising to us frankly that the wells are performing as well as they are.

It is still very early and it may turn out not to be great, but it is interesting it is definitely an upside to our acreage.

While were-- Mike I know are you are interested the powders as well I want to go back to the question that was asked early about well cost down there and just make it clear.

What we are drilling in the last well we drilled and I mentioned cost $16 million is in one of the very deepest parts of the Powder River basin and has a very long lateral on it.

It is going to be on the higher end of our cost range.

I do think we're going to get our well costs down there over time.

While you're talking about longer lateral's you alluded to that in the Briscoe area as well.

Can you talk about what length you're looking at, what have you seen Anadarko do in their area?

Well they're talking, and I can't tell you whether they've drilling yet, but they're talking about going out to 7000 feet or more and I think that is typically where we need to go.

We haven't drilled one at that length yet, frankly we have been waiting for some of our gathering facilities to be put in place there before we spend a lot more money in those areas in the more remote areas of Briscoe.

But, I think over time we need to test longer lateral's, tighter frack stage spacing, and potentially even with that maybe downspacing again.

There are some additional work to do, there's a lot of acreage out there and we have quite a bit of time.

But I think we need to test the longer lateral's and we will be doing that and Anadarko will be doing that so we will learn a lot from both sides.

One last one for me, on East Texas you alluded to some other intervals that look interesting.

I know you drilled a chalk well in the past which I think was pretty much dry gas.

Can you talk at all about what other intervals you might be contemplating there?

Well certainly the chalk and I didn't mention the chalk specifically and that was the one that was really at the top of my mind.

There are some great areas in the chalk as you go east there and we think we have some opportunities in that.

There are some other intervals as well, but I don't think we are ready to really discuss those yet.

I assume that were you're looking at the chalk it would not be a dry gas area?

That was our intent originally, yes.

Brian Velie, Capital One Southcoast.

Quick question on one of the slides in the new presentation I noticed there is a footnote about Anadarko Basin proceeds for guidance purposes being assumed to happen at the start of next year.

I wondered if those proceeds figure into the 15% to growth in 2014 and 2015 or if that would be additional powder that you could put toward faster growth?

Correct.

They do not factor into that growth estimate.

Along the same line for the debt to EBITDA multiples, the being inside of 1.6 times is that also not include any proceeds from those sales?

Correct.

Does not included.

For CapEx spending this year after the increase this quarter, it looked like about $1.25 million of the $1.65 million is going to be call it developmental in drilling.

Do you think that same ratio will hold and '14 or '15 or do you think you might pull back a bit on the new venture spending?

I think that is probably too soon to tell.

Clearly it depends on how much success we have and we hope to be successful.

I think that debt-to-EBITDAX metrics that you're talking that is the metric that really matters that we want to maintain at a good healthy balance sheet, but certainly if we have success, we have the capacity to develop our successes and selling some assets and trimming our portfolio certainly contributes to that.

Pearce Hammond, Simmon and Company.

Regarding your non operated Eagle Ford asset which has performed exceptionally well, would you consider divesting this asset to help fund the development of your high-impact emerging areas like East Texas, Powder River basin and Permian?

Pearce I would say, this is Tony, obviously we continue to look at our portfolio every year and certainly this year our focus has been on the Anadarko basin.

Plus don't forget we still have got our Mitsui carry taking us through mid-next year as a Wade talked about earlier.

So there is issues there that certainly we would have to address if we were to seriously consider a divestiture but right now I would say that program is working extremely well.

Jay talked about our ability to learn from the Anadarko operation as well as our own operated.

So I would say right now we like the positions we are in both the operated, non-operated.

But going forward we will continue to look at our portfolio and see if it ever make sense for us to consider that as a candidate.

I know you all did not guide the realizations but given the compression in the LLSWTI spread in the past month can you provide any broad guidelines on how to think about oil differentials for the second half of the year?

I think yes, Wade mentioned, our Eagle Ford production trades off LOS so you need to focus on the LOS number and we're going to trade relative to that number.

So as LOS moves up and down those differentials move up and down.

It is about half our crude production of rough numbers I believe forgive me if I'm a little off on that, but that really is what drives Eagle Ford nets.

We haven't really seen any real degradation and I will call the gap between LOS and our pricing but LOS does move around.

The last one for me, service cost in the Eagle Ford and the Bakken how do you see those for the remainder of this year?

And then as you start doing some planning for '14, do you think they've flattened out or maybe some potential further declines?

In general we are assuming flat and I think that is consistent with the kind of numbers that we are seeing.

Michael Hall, Heikkinen Energy.

It's Michael of Heikkinen Energy, thanks a lot it might have been touched on, I guess just wanted to circle back a little bit on the quarterly progression around oil growth.

Can you quantify by chance how much oil volumes roughly were shut-in, in the second quarter?

I can't give you an exact number because I haven't added it up.

I just notice as I look to the reports if you look back over the last couple of quarters we had a larger volume shut in, in the second quarter and that was one of the rationales for oil rate been down.

As I said our oil rates are up substantially already in July as we begin to bring these wells on and I think you will see a reversal in that trend.

Fair enough, in terms of the remaining wells to be completed throughout the course of the year, do you by chance have the splits on how many it will be in let's say area one, area three or area two?

Is a vast majority going to be in area one at this point?

Just trying to shape model --.

I think what you will see in the third quarter the majority of the wells coming on are going to be area one of wells.

There are going to be pretty oily.

The fourth quarter we are going to move back, we will be moving back into some of the leaner areas of the field.

So I think what you will see over time here is oil rates will come up nicely I think in the third quarter and then you'll get back to sort of a normal progression in the fourth.

Makes sense.

On the incremental 20 wells for $5 million, I'm trying to understand that a little better just in terms of how much of those incremental 20 wells were maybe already had some drilling costs associated with them?

Have been accounted for previously or are full V and Z costs associated with all 20 of those wells or is some of that pulling on out of backlog and so there's only a completion cost associated with it?

Then, of those 20 incremental wells, are those predominately in Briscoe or is that spread throughout area one and three?

Two questions I'm sorry.

Great questions, I'm not sure that have the level of detail to really answer it well for you.

The number we gave I think was $5.4 million I want to make sure that we are not talking about in the Briscoe area.

In general, when we are talking about our budget, we had carry ins and carry outs every year and I don't think there will be a substantially different level of carry in versus carry out in terms of money or wells.

Our well cost is not just down at Briscoe it is down across the board.

We have talked about our Galvan and well costs coming down earlier.

So we are saving money on all our wells essentially and we're able to spend a by making a few, making -- drilling and then completing a few additional wells or 20 additional wells.

In general though I don't think I can give you specifics on exactly where every well is being drilled as I said.

As we go into third-quarter a lot the wells coming on are going to be in the oilier area one areas of the field.

And then as we go back into the fourth quarter we move a little bit more back into some of the lower yield areas.

Last one on my end is just around base PDP declines on your legacy assets let's say, or just the non-active assets outside of Eagle Ford, Bakken, and whatnot.

You have what the oil declines are looking like there and the gas declines in the PDP?

Well, I don't have a specific oil decline number.

I can tell you that our overall corporate decline if you stop drilling today and just look at 12 months is about 40%.

Mike Kelly, Global Hunter Securities.

A lot of the focus of this call has been on the allocation of capital wells being drilled in the Eagle Ford between area one which is more oily versus area two and three.

I was hoping you could refresh is on the difference of returns between the two areas as you see right now the current commodity environment?

Thank you for that question, it's a good one.

What you will see I believe, your wells in area one, in the area that we are drilling in area one in the higher yield areas have very similar returns to our best wells in the leaner portions of the area in the area three which is the Galvan area.

When you look at it from a return standpoint, it is really not much of a trade-off.

It is really just a function of how do the wells lay out in the schedule and how do we move forward.

But the returns are actually very similar in the higher yield areas of the north portion versus the lower yield areas that we have been drilling in the southern area which have higher URs and better returns.

You guys provided what I thought was some great color on the strategic rationale for having a focus new ventures program and wanted to ask you just a couple follow ups on that front.

The Woodbine and Powder River Basin are obviously the two concepts that are being tested this year and I really want to get a sense of how long or short of a leash you are willing to give both of those programs in terms of doing the science work and doing the testing?

And really what you want to see out of both of those plays in order for it to make the cut and move into the development mode to?

Thank you.

This is Tony, let me address that one.

With both plays, what we have endeavored to do and I think we are accomplishing is putting together a significant position such that if we have success with either or both of those plays they will be material and will certainly fuel our growth longer term.

If you look at the acreage numbers that we've provided at present time you will notice that in both cases, over 100,000 acres.

What would like to do is to go into early testing, have a position that we can leverage longer term.

And if we have success with either or both plays it really provides us with a lot of opportunity.

We have the potential to self develop, we could also take that with success we wanted to potentially bring in a JV partner just like we have done in the Eagle Ford.

So it gives us a lot of optionality if we continue to have success.

I would say right now you're right, we are in the very early stages in both plays.

We're certainly looking to complete some near-term testing as Jay talked about earlier in both that is why we're moving some rigs and adding some modest capital this year.

Then if we have continued success, we will move into more of a delineation phase and then we continue to like what we see, we can go to full development.

But I think the way to think about that is it is a gradual process, you don't immediately jump to full development and that allows us to obviously manage our capital program and maintain certainly strong balance sheet in the meantime.

Let me add one comment, I think Tony's comment about the distillation of ideas is really important.

By the time we get to the point where we are talking about these plays we've built the material position, we are at the point where we are fairly convinced that they are going.

And we are going to put substantial amounts of money on the table to test them.

We come from a conceptual level all the way down to the point where we drilled wells and are building position.

At this point, these are meaningful things, were going to spend real money and as Tony mentioned earlier in the talk, these are the things that are going to drive our growth a couple years out.

We need to a source these things because our capital program needs to grow over time and we need to find new things.

I thought his talk earlier was really good from that standpoint.

That is good color, let me ask one more on that front in terms of trying to get understanding a what you guys do have going on behind the scenes.

In terms of putting additional plays together and maybe just if you could give us a sense of when we could expect to hear about more concepts that you are bringing to the floor here.

Well we typically don't talk about them until we have built position.

I don't think I will comment on specifics of what we are going to say or when we are going to say it.

I think you will see new ideas moving forward.

We have a lot of money right now to spend on ideas that we have distilled, so we have got a lot on our plate.

There will be some things that will come forward over time.

Jeff Robertson, Barclays.

A follow-up on new ventures, can you talk Jay or Tony about how many wells you think you'll have in East Texas that will go into the planning process for the 2014 capital program?

I think it is a little early to say that.

I think -- going into the year we are going to be running two rigs I can say that.

I haven't got an exact well count and whether our rig count goes up at year or not is going to depend to some extent on how much success we have.

Just a follow up for Jay would you anticipate that the $170 million on new ventures then goes up by some amount in 2014?

Or is that for the pace you are on in those plays is that about the right spend level.

That is almost that question about our budgeting process.

In fact what will happen in East Texas as we move forward is more of that money is going to move into the development side.

We really reserve new venture spending for those truly new things where we have not drilled approved well yet.

So our East Texas stuff as we are successful will move actually into our development portion of our budget.

I don't see new ventures necessarily getting a larger, that line item getting larger.

What would happen is we would start carrying a development wedge, capital wedge for East Texas.

We have reached the allotted of time for questions.

I will now turn it back to Tony best, CEO.

Thank you all for joining us for the second quarter call.

We look forward to talking with you next quarter.

This does conclude today's SM energy second quarter 2013 earnings call.

You may now disconnect.