SM Energy Co (SM) 2012 Q2 法說會逐字稿

Good morning.

My name is Keena.

I will be your conference operator today.

At this time I would like welcome everyone to the SM Energy second quarter 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, you may begin your conference.

Thank you, Keena.

Good morning to all of you joining us by phone and online for SM Energy Company's second quarter 2012 earnings conference call and operations update.

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

These statements involve risks and 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 10-K filed earlier this year and our Form 10-Q that we will be filing later today.

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

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

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

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

Company officials on the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Executive Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, the Company's Senior Vice President and General Counsel.

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

Good morning.

Thank you for joining us this morning for our second quarter 2012 earnings call.

I'll make a few introductory remarks and then Wade and Jay will provide their respective financial and operational reviews.

We'll be referring to slides this morning from the presentation that was posted on our website last evening.

My comments will begin with slide 3.

The second quarter of 2012 continued on pace with our business plans for the year.

Although we saw adverse financial impacts from lower natural gas pricing and production curtailments in our operated Eagle Fore Shale program due to equipment delays in our third party gathering system build out.

As a result of this constraint, we will defer several Eagle Ford well completions into 2013 and redirect the associated capital into oil focused projects in the Permian.

Jay will talk more about our Permian progress in a few minutes, but as a preface, let me say that I am very pleased with our progress in our Mississippi and limestone play, as well as our acreage build in this oily province.

In regard to our balance sheet, it was also an important quarter for SM with the redemption of our convertible bonds and the issuance of $400 million in new high yield bonds at an attractive 6.5% coupon.

I'll now turn the second quarter update over to Wade.

Thank you, Tony.

Good morning.

I'll begin with a brief recap of how the Company performed compared to our guidance for the quarter starting on slide 5. Production came in at 50.6 bcf equivalent, or 556 million per day, which was toward the low end of the range that we provided for the quarter.

Jay will discuss production in more detail in his review.

Cost for the quarter were generally in line or better than what we had guided for the quarter.

Transportation came in meaningfully below our guidance.

This is primarily a function of lower than expected Eagle Ford volumes in the quarter.

Production taxes also came in below our guidance as a result of tax incentives that we recognized in the quarter related to drilling in the state of Oklahoma.

On LOE, absolute dollars came in essentially in line with what we expected for the quarter, however, lower than anticipated production volumes pushed LOE per Mcfe slightly above our guidance range.

All the other costs that we guide on came in within, actually at the low end of our guidance ranges.

We had a couple of unusual items this quarter.

First, we reported $38 million of impairment on proved properties related to our Haynesville shale assets.

This impairment was triggered by weak natural gas prices.

We also recorded a loss on divestiture activity of $24 million in the second quarter.

During the quarter we ended the marketing process for a package of DJ Basin assets and we didn't receive offers in what we thought was sufficient value for the assets.

When these properties were reclassified from assets held for sale to held and used, we were required to recognize a non-cash write-down of about $28 million, to state the assets at market value for accounting purposes.

Lastly, we had a roughly $11 million charge in the abandonment and impairment of unproved properties line.

This charge related to the abandonment of acreage associated with one of the Company's exploration programs in the Rocky Mountain region.

The net result is GAAP net income for the quarter came in at $24.9 million, or $0.37 per diluted share.

Our non-GAAP adjusted net income for the quarter was $5.9 million, or $0.09 per diluted share.

EBITAX for the quarter was $214 million.

Moving to slide 6, I'll quickly discuss our financial position.

In the second quarter, all of our outstanding 3.5% convertible notes were redeemed or converted.

We subsequently issued $400 million of 6.5% senior notes due January 2023.

So our debt to book cap at the end of the quarter was 43% and our debt to trailing 12 month EBITAX stands at 1.2 times, which is well within our comfort range.

So our total long term debt at the end of the quarter stood just short of $1.2 billion, and as you can see, from the chart on the right, we're in great shape from a maturity standpoint.

I'll now turn to slide 7 and discuss our credit facility briefly.

The borrowing base currently stands at $1.4 billion.

As a result of $400 million high yield offering in the second quarter, our borrowing base was automatically reduced by $0.25 for every $1 in senior debt issued.

We have left our commitment amount at $1 billion, as we believe that amount is sufficient for our current needs.

Finally, a summary of our current hedge position is included in the appendix to the slide deck and detailed hedging information is included in our Form 10-Q, which will be filed later today.

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

Thank you, Wade.

Good morning, everybody.

I'll begin my remarks on slide 9. Production for the second quarter came in at 50.6 Bcfe, which is essentially flat with the first quarter on a reported basis.

Production on retained properties did grow slightly sequentially.

Our liquids production percentage for the quarter was a little higher than in the first quarter, but still rounded to the same 44% liquid as we reported in first quarter.

In general, production in our dry gas producing areas is declining, and we were unable to grow our overall rate within the quarter due to the timing of well completions and infrastructure-related issues, which I will discuss.

I now am on slide 10.

Production in the operated Eagle Ford grew 16% from the first quarter to the second quarter, to a record quarterly average of 207 million cubic feet equivalent per day.

We had actually expected to grow more in the operated Eagle Ford, but our production for the quarter was impacted in April by the downstream pipeline curtailments that we mentioned at our last call.

And further impacted by midstream facility issues during the quarter.

As others have disclosed recently, equipment shortages and fabrication delays are a real problem in south Texas right now.

In our particular case, we have seen several months of slip in schedules for delivery of tanks and vessels required for assembly of new tank batteries and other required facilities.

Limited midstream capacity is creating high back pressures, and reducing rates on our existing wells.

And sharply limits the amount of actual incremental field production we can generate from new completions.

We're working hard with our midstream provider to resolve these issues and we are making good progress.

However, in the meantime, we have delayed some completions until we can realize more economic benefit from completion spending.

In the first half of 2012, we completed 26 wells in our operated program.

Our current estimate is that we will compete a total of 67 wells in 2012.

As we've said before, we plan on dropping one rig in the second half of the year and ending 2012 with five operated drilling rigs.

Our current completion schedule would leave us with about 28 wells drilled, but not completed at year end.

This revised estimate results in lower forecast production volumes out of operated Eagle Ford program for the year, and that impact is incorporated into our new production guidance figures.

I am now on slide 11.

In the non-operated Eagle Ford, we reported production of 9,500 barrels of oil equivalent per day of production in the second quarter.

This reported number is lower than the first quarter number on a sequential basis due to revisions on estimates of prior period production, which occurred in both the first and second quarter.

While these estimate revisions are not material to our or overall production numbers, we recognize that the relative impact of the much smaller quarterly non-op production levels in this one area can be pretty confusing.

From an operational point of view, the operator has continued to run at a consistent level of activity and is growing production.

We're carried on substantially all the drilling and completion activity because of our transaction with Mitsui.

However, Anadarko has been spending considerably more money than we budgeted on the build-out of the midstream assets in which we are not carried.

This additional investment will generate benefits for us in the future.

But for right now, this increased facility CapEx is one of the key reasons for our capital forecast moving to the high end of our original guidance range.

Moving on to slide 12, we operated three drilling rigs throughout the quarter in our Bakken Three Forks program.

Production was essentially flat with the first quarter due to a shift toward pad drilling impacting the timing of well completions, and lower working interest in a number of our completed wells relative to prior quarters.

We're very pleased with the results we're seeing up in the Williston and added a fourth rig right at the second quarter.

Our non-operated spending in the Williston has also been higher than we expected so far this year, as we continue to participate with a number of quality operators and their activities.

Moving to slide 13, we added approximately 28,000 net acres in our Permian region in the first half, increasing our total acreage there to about 115,500 net acres.

During the quarter, we operated three drilling rigs in three different areas of the Permian.

The first area, which we have mentioned in quarters past, is our acreage in Lynn, Borden and Garza counties, where we are developing a Mississippian limestone play.

The second rig was in south east New Mexico drilling in the Bone Spring.

The third rig we operated during the second quarter was drilling our first Leonard Shale well, which is currently flowing back after completion.

Slide 14 provides some additional information on our Treadway prospect, which is the acreage position where we are targeting the Mississippian limestone.

As you can see in the table at the bottom of the slide, our last couple of wells have had average 30-day initial production rates of 540 barrels of oil equivalent per day, of which about 85% is oil.

Our AFD cost for a no science well in this play is approximately $6.5 million.

We have brought a second rig into the play and continue to work on reducing our costs and improving the performance of new wells in the program.

Our total acreage position in this play area is approximately 68,000 net acres.

On slide 15, I would like to briefly go over our remaining development drilling activities for the quarter.

We ran three rigs in our Granite Wash play during the quarter and completed five wells, mostly in the Marmaton interval.

Our current plan is to run three rigs through September, and then drop back to a two-rig program for the remainder of 2012.

Lastly, our south Rocky's team continues to operate a rig in the Powder River Basin in Wyoming, where we're currently drilling a long lateral frontier well.

On slide 16, we have updated our capital guidance in 2012.

In my discussion, I have covered all the significant issues that are impacting our capital forecast, other than to note that our exploration spend is up somewhat from our original plan due to the acreage purchases we made in the Permian and other prospect areas that we have not discussed today.

During the first half of the year, we have sold or entered into pending divestiture transactions covering approximately $50 million of non-strategic, mostly non-operated properties.

While the midpoint of our capital guidance range has increased by approximately $50 million, it's important to note that this increase is essentially funded by our divestiture activities.

Moving to slide 17, we have updated our production guidance for the year.

We lowered our guidance to a range of 210 billion to 217 billion cubic feet equivalent, which is a result of the operated Eagle Ford infrastructure delays and completion deferrals I discussed earlier.

Now I'll turn the call back to Tony for his closing remarks.

Thanks, Jay.

Our Company continues to deliver strong performance in 2012, in the midst of a very volatile market and challenging construction issues in the country's most active basins.

We remain focused on the successful execution of our significant resource play projects and pursuit of our key business objectives for 2012.

Although we have had surface constraints in the operated Eagle Ford program, we are still expecting corporate production growth to be approximately 25% for the year.

In our Permian Basin region, we are pleased with the recent successes that have lead the Company to accelerate activity in the region.

Lastly, we have maintained the strength of our balance sheet and have ample liquidity to fund our ongoing program.

I would now like to turn the call over for your questions.

(Operator Instructions)

Brian Lively, Tudor, Pickering, Holt.

Jay, on the non-op Eagle Ford volumes, do you have a sense of what -- or best estimate of what the second-quarter volumes actually were as opposed to the adjusted volumes for the prior quarters?

I can tell you what the adjustment was.

The true up to the first quarter, Brian, was about 1.4000 BOE.

So you can -- that should directionally be able to help you.

As Jay said, that number is at 1.5% of our total production, but it does make the chart look a little confusing.

If you add the 1.4 back and take it out of the first quarter, you get a smoother line.

That is what I was looking for.

And more bigger picture on the operated side.

I am just trying to get a sense of when you think you'll have most of these surface issues behind you, and specifically, what are you forecasting as you get into later this year and into 2013?

Should we expect to see a big uplift as you will be able to start bringing on these pads that you have completed, but unable to maximize at this point?

We haven't guided '13 yet, partly because we want to understand how all this is going to ripple into '13.

In general, I think it is probably accurate to say we're just a couple of months behind where we expected to be in terms of our ramp.

'13 gets a little complicated because as you may remember, we were expecting to run into our firm pipeline capacity in the first half there.

We have a flat spot in our pipeline off take capacity in the first half of '13, so it's a question of when we hit that in the early part of '13.

We need to do some more work on our forecasting as we see some of these facilities showing up to see when we think that will be before we will have a really good sense of '13.

I think it's fair to say we are about two months behind where we expected to be in our ramp.

What that does is it pushes that rate we had expected to add.

As we move forward, the fourth quarter was going to be a very big quarter, so you basically shift that out a couple of months and that is where the impact in production comes from.

We made good progress in the last month.

We have a number of facilities that are going to be installed in August and we have a number that are coming right at the beginning of the fourth quarter and we really need to see how that goes.

So far, most of the facilities have been delayed by a month or two versus what we expected.

So we try to build a forecast here that we think we can make based on assuming some delays.

And that is how we laid out the schedule.

I know it's early on 2013, so I'm not going to push on that.

Can you give a sense of if things play out as you see them now, where do you think your exit rate would be for the Eagle Ford for 2012?

We typically -- we haven't guided that number, and I would rather not give it because, again, it's a moving number.

It depends on our facilities in the fourth quarter.

If you look at our firm capacity, we were originally thinking we would be there up against it in the fourth quarter.

I think now that's going to happen sometime probably in the first.

If you look to that firm capacity number on our pipeline numbers, that is probably not far from where we will be.

Maybe a quarter later than we thought.

That is helpful.

On the Permian, it seems like the Mississippian results are a bright spot here, especially considering where you think the costs are going, and my question is just given all the Eagle Ford surface issues that you are facing.

It sounds like this asset is going to start ramping up faster in terms of being the next big area that you allocate capital.

Is that a fair statement?

And what should we expect to see as we go into late 2012, 2013 in terms of adding rigs to this area?

We're excited about several different areas of the Permian.

And I mentioned the Leonard Shale earlier.

We have some activity there as well.

And I think there's some really exciting things coming forward for us in the Permian with the work we have done.

It has taken us quite some time to get to this point.

We are going to be accelerating.

We've added another rig here.

I think if our results continue to prove up, we could potentially add another rig in 2013.

Then we have other exploratory activities going on as well.

We have some exciting stuff coming down the road.

I am very proud of the guys in the Permian.

They have stuck to this limestone play for quite some time to try to understand it and figure it out, and our results are starting to really show and certainly we -- on a lot of this stuff in the Permian, you're into three-year term leases, and we are going to have to accelerate activity to hold all the acreage.

So I think you can expect that over the next year or so, as long as our results hold up, we'll be accelerating some of this activity, yes.

To follow up on that one.

You're looking at the rates on these wells, the higher oil cut in them and then the cost side, where do you think that -- or where do you expect the returns to stack up on both the Leonard and the lime relative to the average Eagle Ford at this point?

Average Eagle Ford is a tough number.

Obviously the dry gas portions of the Eagle Ford don't work right now and the economic line of the Eagle Ford has moved north.

Let me take -- divert for a second and say part of the reason the infrastructure issues are tough is because we are focusing our activity more and more to the north, which wasn't our original plan.

So some of our infrastructure issues are created by our own drilling schedule changes.

But these wells in the Permian meet our hurdles.

I think there's some opportunity to drill longer laterals.

There's still some significant frac benefits.

I think we can drive our costs here.

The early wells had a lot of science in them.

We're still learning a lot.

The first few wells we drilled in the Treadway prospect area probably had too small a rip on the well.

We now have a bigger rig in the play with a top drive on it so we can drive costs there.

Saving a lot of money on directional.

There's a lot of things we can do I think to improve these economics.

And they're -- they meet our hurdles and they are very competitive right now.

So we're excited about it.

I don't want to get too nuts.

We don't have that many wells drilled yet, but I think it's an exciting thing, and certainly we're getting to a material acreage position in these plays.

That's it for me.

Thanks for the comments.

Subash Chandra, Jefferies.

Good morning.

A couple of ratio questions here.

What do you think about the gas ratio through year-end?

And if you can put your 2013 hat on, and again without being specific -- I apologize for asking 2013 questions -- but do you think you can make a meaningful change to the oil ratio next year?

We guided throughout '14 already on what we thought our oil rig mix would be.

We did that in the last call.

I don't think that we would say anything as material changed.

I think by the end of this year we'll be at something like 55%.

What we said I think we were going to be at 55% gas by year-end.

And I think in '14, we said we would be roughly 52%.

And I don't think we know anything right now that would cause us to change that guidance.

Clearly, we're going to be getting oilier.

It's just -- that is the pace we think we're on based on our long-range plan.

Honestly, if oil prices stay where they are and gas prices stay where they are, we may get there a little quicker.

I think it would tend to drive your economics that way.

But that is currently our plan.

Okay.

Could you remind me again the firm capacity number by year-end and the status of that firm capacity?

If it is on schedule of not?

We are going to pull a number to make sure we get it right.

The firm capacity is going to be there.

It is already, essentially, there for us.

If you look at year-end/first quarter '13, we should have firm capacity line right at 300 million cubic feet a day of gross take away capacity.

299 is my number here.

In mid to '13, it pops up to 382 for a gross take away.

This is gross operated gas now.

And if you remember, to get to a number from that, you multiply that by 10% or so.

If we were producing 300 million a day of gross wet production, we would be producing about 330 million cubic feet a day net out of the Eagle Ford.

I would say we thought we were going to hit that number right at the end of this year.

We may be a quarter late.

That's a big number.

It is a big, big number.

And I think that is part of the issue as you -- there is a significant production ramp built in here.

So when you delay it a month or two, it results in -- when you look within the calendar year of 2012, it has a significant impact.

Overall, it doesn't really impact the value of the asset.

The wells are fine.

It's a temporary infrastructure issue and it will push it out a little bit.

So, let's say Q1 everything works out and you can get to that 330.

I assume that it means that you would complete your backlog as well.

We would, and catching up the backlog will take some time.

That's why when I say it will be a quarter out, I think we're probably talking -- that's part of the issue is we'll have to get back and complete the backlog of wells, get caught back up and so that is why I would say if you push our entire calendar out a quarter, that is probably not an unreasonable way to look at things.

Okay.

And one final one for me.

What is the rig count required for Permian lease retention at this point, and are you there?

That is a really good question.

And I am going to defer the question maybe for a quarter until I can get in and really dig around on that.

Right now, we're fine.

The question is over the next two years what do we have to get to and I don't know that number well enough yet to be able to give it to you.

It's going to be up a little bit, but it will depend on some negotiations we have going on about how we can pull up some of these leases.

I think for right now, we're fine.

But I do think we're -- given good results, we will try to accelerate the program somewhat.

Okay, thank you.

William Fitzpatrick, Austin REIT.

On the 48,000 or roughly 48,000 acres in the Permian that is not in the northern Midland, can you give us a rough break-out of where that land is in the other two areas?

We did that on purpose so we wouldn't have to do that.

Fair enough.

We can move on to firm transport then.

Do you think with three rigs going to five there are going to be any issues in the Permian with firm transport?

Are you guys looking to lock up any midstream there?

That's another great question.

It's a problem we haven't had to deal with much because our volumes haven't been growing that much, but it is something to think about.

In general, I think basis differentials have come in a little bit in the Permian recently.

What we have seen in terms of the northern areas that we're working, there is some gas pipeline infrastructure that we need to work through.

We think we can do that at the pace we're working.

Oil is essentially getting trucked.

We haven't seen any big issues with that yet.

I don't foresee this growing so fast that we create our own problem.

And in general, most of the stuff I have seen would say that Permian differentials are forecast to stay fairly tight.

At this point, we don't see a problem with it, but we probably need to do some more work on it.

Okay.

You have talked about completion cost coming in around 20% in the Eagle Ford.

Can we get an update on costs there?

I understand that might be getting offset by some more expensive fracs, but if you have an update, I would appreciate it.

I think on a stage count basis, we're probably down between 20% and 25% now on a per stage number.

We are being pretty -- part of the reason you see that lower CapEx number in the Eagle Ford is cost savings.

It's not all deferring completions.

There are cost savings built into that.

And we are being pretty cautious about -- we're not just going out and adding a whole bunch of stages to wells yet.

We're not at a point yet where we can talk about how much stage count impacts rate and reserves.

It's probably another six months or so before we'll be able to talk about that much.

I think there are some logical places where adding stage count helps, should make sense.

At this point, we are seeing about a 20% to 25% stage count reduction.

We are spending a little money on stage count, but not a ton.

So we have seen some cost reduction.

On the drilling side, drilling costs in the Eagle Ford and firm, but we are saving some money on the completions.

Okay, and just one last one.

Any ethane -- or how much, if any, ethane were you guys rejecting in south Texas in the second quarter?

We didn't reject any ethane in south Texas to my knowledge in the second quarter and it's not really -- right now it's not really close to that decision.

We do have the ability to reject if we want to on several of our contracts, but we haven't been doing it.

Thanks so much, guys.

Scott Hanold, RBC Capital Markets.

You are going to the Permian, it looks like you built a nice position up there in the northern Midland Basin.

Is there room to expand that further or is it pretty competitive or already locked down up there?

I think there is some potential in the play and I will say this just to try to scare people away from it.

It's not an easy play.

And there is some technology here that needs to be applied to really understand this reservoir and if you don't apply it correctly, you won't get very good results.

We think there is some potential running room.

Right now we've got a big chunk bit off and we're going to work on it for a while, but I think over time there may be some opportunity to run.

This is out of the really shaley -- the intervals where most people are chasing shale.

So it is a little less heated than some of the shale play areas.

I hope we can build some more position.

That is the easiest way to say it.

Okay.

And the way it sounds, you're not looking right now, but you could opportunistically.

Do you think this is a fairly expansive play or is it a little bit more regionally tight?

I don't know the word regionally tight.

It is a geologically constrained play.

In a sense.

And I don't want to get too much into the geology because I'd give a lot away here.

But it's not like playable over huge areas of the Permian Basin.

You need to be in a certain place to make it work and you need certain technologies, certain data to really be able to play it.

And we think we understand that.

And hopefully a lot of other people don't.

And I didn't say that we weren't looking for acreage yet, and I didn't say we were either.

Okay.

Understood.

And my next logical question.

I think I can guess a response is, what technically is more challenging or different about this reservoir?

No, I don't think I'll address that.

Okay.

Fair enough, thanks, guys.

Mike Scialla, Stifel Nicolaus.

My questions were on the same lines of Scott.

I'm probably going to get some limited answers here, but I'll try anyway.

The improvements you made on these more recent wells in the Permian, was that due to geology and location or was that more due to the way you drilled and completed the wells?

It's a combination of them.

I think we've disclosed in the past that we drilled some vertical wells in the play, and we had some early success in vertical wells here, and thought that was where we were going to go with it.

And then some subsequent vertical wells showed us we really need to drill these horizontally.

So we reworked our program, redid a lot of geologic interpretation and started drilling horizontal wells.

These wells we are showing here are results from our horizontal wells.

That is really what made the difference for us.

And there are a lot of science associated with the direction we're drilling those and how we're completing them, but I'm not going to get into that too much.

Is seismic one of those tools that is important to the future success of the play?

Now you're asking me questions that I won't answer.

Okay.

Maybe in terms of the 68,000 net acres that you mentioned.

Do you feel like that area has been de-risked or is that where you think this play might work?

I would say more of the latter.

It certainly hasn't all been de-risked.

I wouldn't want you to think it has been.

We have some good indications.

We have some technology we think can help us some.

It's still very early days.

It's still in what I would call a delineation stage development play.

You mentioned you are spending some dollars on acreage in some other -- it sounds like maybe unproven plays or are those exploratory type plays?

I would call them exploratory.

Can you give us any idea of how many acres you might have there?

I think we indicated how much we added in the first six months.

Outside of Permian or inside?

Sorry, outside the Permian.

No, we're not going to address how much acreage we've added outside of Permian.

Okay.

And then one last one for Wade, you mentioned you were in your comfort zone now in terms of debt to cap.

The budget has gone up a little bit from the beginning of the year and cash flow with the production being down is going to be a little less.

As you look out to year-end and into 2013, does it still look like you're going to be within that comfort range?

And if not, any thoughts on another non-core asset sales or anything like that to get you back in that range?

No, we still feel very comfortable with the balance sheet and where we're headed in the foreseeable future.

We'll use the revolver to fund the gap, the remainder of this year, just like we said we would, and lots of capacity there.

And looking ahead at 2013, still feel very comfortable working within the debt metrics that I have laid out in the past.

I think you said 1.5 times debt to EBITDA.

By your projections, you're going to be under that?

No, I think what we said in the past is we want to stay below 2 times, and we would go to 2.5 times for the right transaction or right opportunity.

But we're -- I think we're headed to -- my numbers show 1.5, 1.6 times by the end of this year, which is very comfortable.

Got it.

Thank you.

Nick Pope, Dahlman Rose.

I think on the last call you talked about some of the hiccups you had in March and April and the operated Eagle Ford, and looking at the number that you put you up in the second quarter, I was curious what the profile looked like over the quarter itself.

Because it seemed like April was a little slow.

I was wondering what June rates were, if you were able to give those numbers and maybe current rates for the operated Eagle Ford.

We typically don't give month-by-month numbers like that.

I will say April was low because of pipeline issues.

And then we ran smack into these other midstream issues that kept our rate -- we were up from April, but kept our rate pretty flat for the rest of the quarter.

We have made considerable progress already in July in resolving those and we're up quite a bit.

I don't think we'll give specific numbers.

And the reason for that is because on any given day, the numbers are up and down.

It's real hard.

I don't want to give a number and find out we had an interruption next week that takes us down 20 million a day.

We are making progress.

I think if you profiled all the second quarter, what you see is April was low and then we got up some and we were basically flat through June.

And that is when we really started to see -- we expected to grow in June and we really didn't and that was when some of the impact of the midstream infrastructure really came into play.

One point I should make, there are a lot of people out there that look at individual well data on the Texas Railroad Commission website, and we have gotten a lot of questions from people about why is this well falling off, et cetera.

And that really does -- these constraints really do ripple back to individual well rates.

We put on a new completion, and it literally knocked a lot of our other wells back.

So you can't see on that website what the well head pressures are that are causing these things.

But as the pressures go up, a lot of our older wells lose production.

So it makes it confusing.

If you are out there using state data trying to figure out what's going on, you really can't do it.

It's not amenable to that.

In general, I think the last couple of months of that quarter were pretty flat.

Okay.

That is helpful.

I was just hoping to -- sticking with the operated Eagle Ford, I was just hoping to get these numbers correct.

I think at year-end, in terms of the producing wells or completed wells, you're at 84 year-end.

And you've completed 26 wells in the first half of the well.

Is that right?

26 is right.

We need to check the 84 number.

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

I can follow up afterwards.

I think that's all I had.

Thank you.

David Tameron, Wells Fargo.

Just a few follow-ups.

I don't know if you said this and I missed it.

Can you talk about in the horizontal Permian, Mississippian lines, can you give us an oil cut, oil percentage on that well?

Yes, there's about 85% of oil and they make some NGLs too.

If you look at the total liquids, it's actually higher than 90%.

Second, Granite Wash, you talked about you are going to go down to two rigs once you are done HPPing.

Can you talk about the thought process there rather than -- maybe move those rigs to the Permian or you guys are going to Eagle Ford to Permian on some of those?

Can you talk about that though to keep drilling that Granite Wash acreage?

Let me correct one thing you said.

Our acreage in the Granite Wash is already HPP, so we are not -- that is done.

That has been that way.

Clearly, if you look at the Granite Wash recently the NGL prices up there are poor.

And what we have done is we have looked at it and said we need to continue to hydrate this program to make sure we're making the kind of returns that we want to make.

And the guys there in our Tulsa region said, if you let us cut a rig, we'll be better off.

We can manage through a better quality prospect.

So that is what we decided to do.

We're not laying down a rig early.

We're laying down a rig at the end of September, which that contract expires anyway.

I think it could very well be that after a couple of months we pick up another rig in the Permian and end up essentially moving from one place to another, but probably not within 2012.

I think if our Permian recount goes up, it will probably go up in '13 after we rework our capital program.

And we're committed to trying to get ourselves back closer to cash flow during '13.

Since you went there, can you give us any magnitude?

What does pretty close mean, plus or minus?

What we said is that we thought we would be back to cash flow by 2014.

So that assumes our capital is relatively flattish.

Other than that, it's just too early to say too much about '13.

I hear you.

Granite Wash, are you still drilling the same targets you were before?

I know it's Marmaton, Missouri and whatever name it happens to be at the moment.

Are you still chasing those same formations?

Yes, during the quarter -- I think so far this year we completed seven wells in the Granite Wash.

I believe five of those were Marmaton completions.

It was either five or four.

We did complete a couple, three Hogshooter wells and, frankly, they were disappointing.

And all these wells were in Oklahoma.

We don't own much acreage in panhandle of Texas.

We just haven't been successful in offsetting anybody's successes in Oklahoma in the Hogshooter and we focused most of our activity then in the Marmaton where we have been successful in a number of areas, particularly in the Mayfield area, which is in far western Oklahoma.

We have a good list of prospects.

At this point we're just going to hydrate that list and get ourselves into the best two-rig program we can.

Those wells look good to us.

They run strong economics.

We think, given that we are HPP, that is the right thing to do right now.

And last question, back to Eagle Ford.

The non-op -- some of those issues with the production estimates and deferrals and some of the accounting issues -- is there anything you can do on your end to address that or how do you manage -- you mentioned it's a relatively small portion.

But, as you know, the street likes to focus on the op versus non-op and it creates some confusion and volatility in the stock.

Can you talk about anything you can do to address that from your end?

We are trying, believe me, David.

We are trying really hard.

We get actuals on a three-month lag, so literally we are just seeing now data from April.

So we are seeing the beginning of a second quarter actuals now at the beginning of the third quarter.

Given the transactions that have occurred, the fact that there's a lot of wells in the non-op that get shut in for one reason or another during the quarter.

The fact that our interests are different in a lot of the different areas of the non-op.

It is actually very difficult.

And I know it seems like it ought to be easy and you just call up somebody and ask what their production is.

It doesn't work that way.

I think we are getting better.

Clearly, we understand what their underlying trend is, which looks like high single-digit growth to us quarter to quarter.

And that is going to help us as we go forward.

But, I am sorry.

In a sense that it is very frustrating for me as well.

I think we're doing the best we can.

We also have infrastructure issues as well.

There is a lot of complications.

And so I appreciate the frustration, and we certainly share it, and we're trying really hard to get better numbers.

I didn't assume you want -- you're not trying to get better numbers.

Just wanted to see where you are in the process and that explanation adds some color and is helpful.

I appreciate it.

It is frustrating.

We're frustrated too and we want to get the numbers right.

I shouldn't say right.

These are all estimates.

From a corporate perspective, they're not material.

We understand that people look at these numbers and focus on that.

It's another reason -- this is why we slowed this thing down.

You are not alone in it.

Other E&P companies had similar issues and same basin, different basin.

And just trying to figure out where the process is.

The color was helpful so I appreciate it.

I think that's all I got, thanks.

Pearce Hammond, Simmons.

I noticed that the NGL hedging realizations on the out year NGL hedges were around $27 a barrel, which seems a little bit low.

I was curious, are those ethane hedges?

Just trying to get a better sense on those prices.

The comments you made, because they're ethane, that is exactly correct.

Our out year hedges are almost all ethane.

We typically didn't hedge a lot of the heavier products out that far.

And that is why, when you look at those numbers, the numbers look low because they're mostly ethane or almost all ethane.

That's it.

Thank you.

And does your production mix, specifically NGLs and condensate, make you a bit more exposed to surface constraint issues in the operated Eagle Ford?

I think people may not fully understand the difference between running a gas condensate project and running something in the Bakken.

In the Bakken, we complete a well.

If we need to, we flare a little bit of gas.

We haul the oil away in a truck.

You can pretty much add well after well.

You just add up your wells.

Here, every well we put into this gas handling system creates back pressure on all the other wells.

All this stuff is tied together.

It is essentially a gas production field that makes a lot of liquids.

And frankly, handling a lot of liquids, up-tubing in these wells.

It makes it complicated.

So it's not as simple as you add a well and you add rate.

It's a fairly complicated multi-phase, hydraulic problem when you start to design these facilities and try to optimize them.

So, I do think that it's not necessarily the NGLs that create that issue.

It's more of the fact that this, for us, is a largely gas-driven production mechanism here.

And that creates all these issues associated with back pressure and facilities and need for -- we may need come compression as we move to the higher liquids end of this thing.

Compression can become more important.

We hadn't planned for that this early.

We may need to accelerate that.

It is a more complex problem.

And I think there's a lot of people out there who want to build a simple spreadsheet where you add well, after well, after well and sum up the answer.

It doesn't work that way.

Thank you for that color.

And then lastly for me, can you elaborate on the lower service costs you're experiencing in the Eagle Ford?

Most of the service cost reduction, we've said, is in the frac side and we negotiated about a 20% discount to our frac costs from last fourth quarter.

And then we have seen some additional benefits during the year.

Between 20% and 25% reduction in per stage frac costs.

Other costs down there are not going down much.

And you're still seeing most of the other components of LOE and CapEx are pretty firm.

And that is just -- we haven't seen a lot of that reduction yet there.

Thank you very much.

Michael Hall, Robert W. Baird.

In the operated Eagle Ford, any reason to think once you get some of these infrastructure enhancements delivered that some of -- and some of the line pressure issues resolved -- any reason to think that production would come back on?

Is it more just deferred as opposed to lost?

There's really no issues with the wells.

It's just a matter of -- right now, if you add a new completion, you really don't add as much incremental rate as you would think you would add.

So it's not really economic to add incremental wells when you can't add the incremental rate.

Now, again we made good progress in resolving that and our rates are up some.

And I think they're moving in the right direction.

There's no real issue with respect to reserves here long term.

There's no real issue with respect to the well performance.

It's just a matter of getting the facilities in place.

Getting our pressures down to where they need to be and being able to get back to normal well work.

Right now, we've been spending almost all our time trying to work the facilities piece.

And then as you commented, you're shifting some of the activity to more oily spots on a block.

Any emerging sweet spots or variance relative to what you laid out earlier?

I think the sweet spots are what we've said.

Typically it's the northern ports of Galvan and the eastern portion of the Briscoe acreage.

That area there is where we're going to focus most of our activity over the next couple of years.

It is important to note that our original development plan was more broad based.

And part of the reason that the infrastructure gets tougher is because you're moving into more confined areas to do this.

And that creates differences in the schedule versus where we were going to install things and when we're going to install them.

The higher liquid loading in our wells also creates -- most wells that have higher liquid loading are more sensitive to back pressures and that creates even a little compounding affect in that.

I think our people are actually doing a really good job of managing through this.

And, of course, schedule delays and the delivery of equipment have created an issue as well.

But we're responding to what is a fairly dynamic economic environment down there.

And we're going to get through this.

It's just going to be a little delayed.

And Michael, the changes that Jay talks about are all for the right reasons.

Obviously our economics are stronger in the liquid windows and that is why we are making those changes, but it does create challenges with the infrastructure.

It makes sense.

Appreciate the color And on the downstream component, any lingering issues there?

Anything else to say on that end or has that all been resolved at this point?

We really haven't had, in terms of downstream pipes, really haven't had much trouble since that April time period.

And that was two very distinct plant-related problems that got resolved by the end of April.

I want to embellish on what Tony said.

He's absolutely right.

The changes we're making, we're making because it's the economically right thing to do.

We are deferring completions because there's no value in making completions that you can't produce the gap -- the product.

As we move farther north into the oilier parts of the reservoir, what it means is you may defer some gas production, frankly, from the southern portion of the play, and push the economic -- the capital that we were going to spend on that to places like the Permian where our economics were strong for liquids.

Every decision we're making here is driven by value creation.

Obviously, we didn't wish for our equipment to be delayed, but we're dealing with that in the way that we think creates the most value for shareholders.

Certainly makes sense.

Any way to quantify it?

Is it meaningful enough to move away from the gassier component into the more liquids-rich, which I'm assuming is somewhat lower rate?

Any impact or any can way to quantify that impact on guidance or if any?

We have plenty of locations in the oilier portions of the reservoir.

And I think we'll still be able to get to essentially where we thought we would get to in terms of our firm capacity, just a little later than we expected.

The shift to oilier stuff in the Permian does impact rate some because that, frankly, we're getting a fairly late start in the year.

A lot of those wells won't come on until later in the year and into '13.

The benefit associated with that oilier -- shift into oilier happens later.

So that is part of the rate impact that we are looking at.

On the Permian, did you -- can you disclose what you paid for that 27,000 acres?

I don't think we will.

It's worth trying.

The last one for me.

Highlighted gas declines in the operations update section of the release.

Are those outpacing expectations to the downside?

What does that base decline rate look like?

Actually, I think our basic line rate has come back a little bit from where it was.

The areas where we're declining is largely the mid continent and it is the older -- the gas assets, the Haynesville in particular, where we didn't -- where we've stopped drilling.

Our Woodford assets, which we haven't drilled for a while.

Those assets are on decline.

They are going to be on decline.

Our expectation was that with Eagle Ford growth that we could more than offset that decline.

And when we ran into our infrastructure problems, we weren't able to do that.

Can you put a number on what the base decline is, let's say, on your P2P stream?

I think we said in our last call that our number is 40%.

It is still in that range.

It hasn't changed from last quarter to the next.

Thanks, appreciate it.

Joe Magner, Macquarie Capital.

I think you addressed it earlier in terms of considerations around infrastructure, midstream issues in the Permian.

But based on what you have learned with your Eagle Ford experience, what can we anticipate going forward in terms of hurdles or how might you look to be more proactive around some of those types of channels down the road?

It's a little bit early, but as you move and shift more capital into this new area, just trying to anticipate what kind of growing pains you might expect going forward?

I think I'll comment that the stuff we're working on in the Permian is very different than what we are doing in the Eagle Ford.

The infrastructure issues are significantly less complex.

Basically, we can truck the oil out of there and that's 90% of the value -- 90% of the production.

So really it's more of an issue of getting your -- just getting your gas op tank hooked up.

And in that area that area, that Lynn/Garza area, it's a little lean up there.

There are some -- there is some competition between providers that we will certainly be working on if we need to install some of our own equipment, we will.

At this point, we don't see that being the big issue.

We have been, I believe, very proactive in our Eagle Ford program.

I can't completely control what happens to tank delivery or vessel delivery in this environment that we are in.

And that is just something we estimated we would get it quicker than we would.

I don't think the Permian is the same kind of problem.

Overall, in the Permian in terms of differentials or basis differentials in the Permian, they have come back in some.

I do think with the amount of activity out there it is something we do need to keep an eye on.

But the wells have strong enough economics at this point we think we're okay.

Okay.

And not to try to pick on or get you to talk too much about 2013 plans, but it seems like activity levels generally are going up in all existing areas and new areas going forward.

How should we think about your capital spending plans and considerations around cash flow, balance sheet constraints, liquidity?

Not to get you to speak specifically about 2013, but it seems like that out spend will persist for the foreseeable future.

What we have said is basically by year-end 2013, we expect to be in a position where we'll be within cash flow.

And I think what that infers is basically a CapEx program that is relatively flat year to year.

And obviously we haven't guided yet on 2013, but we'll take a look at that, and obviously the opportunity slate can impact that going forward.

But, right now, that is the way we're thinking about next year is more of a flattish capital program.

Tony promised me that if I had good enough returns, he wouldn't make me shut things down.

A lot of that will certainly depend on our new ventures work, as well as some of the new areas that we are now talking about, Permian specific.

What areas might slow down if Permian is expanding and Eagle Ford is continuing and you've got some --

Jay talked about the fact that we're going to be laying a rig down later on this year in the Granite Wash.

And also that is already HPP.

We do have a lot of flexibility with that program.

We have been very deliberate with our approach in the Granite Wash and we like the position we are in.

But that is one where we've got a lot of flexibility.

So I like that.

If you are comparing year-over-year, we certainly won't be drilling Haynesville wells next year.

That's right.

And I think our infrastructure spend will be down some in non-op.

So there are some knobs to turn.

Part of the reason we haven't guided '13 is because this is one of those things we really have to scratch our head about and try to understand.

What are the best economics?

How do we want to do this?

But we are going to try to get that closer to our cash flow.

Okay.

We'll leave it there.

Thank you.

All right.

With that, thank you all for joining us this morning.

We'll talk to you again next quarter.

This concludes today's SM Energy second-quarter earnings conference call.

You may now disconnect your line.