SM Energy Co (SM) 2012 Q1 法說會逐字稿

Good morning.

My name is Terri, and I will be your conference operator.

At this time, I would like to welcome everyone to the SM Energy 1Q 2012 earnings 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).

I will now turn the call over to Mr.

David Copeland, Senior Vice President and General Counsel.

Sir, please go ahead.

Thank you, Terri.

Good morning to all of you joining us by phone and online for SM Energy Company's first 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 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 10-K filed earlier this year and the Form 10-Q that was filed earlier this morning.

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

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

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 important discussion of these terms and the special risks of 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 Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, David Copeland, the Company's Senior Vice President and General Counsel.

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

Good morning, everyone, and thank you for joining us today for our first quarter 2012 earnings call.

I will briefly cover a few highlights and then turn the call over to Wade and Jay for their respective financial and operational reviews.

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

And my comments will begin with slide three.

As I reflect on this quarter, the thing that comes to mind is competent growth.

We are hitting the mark with continued strong performance across the board in executing our 2012 business plan.

SM Energy had another strong quarter to start the year.

We came in within guidance on production and met or beat all of our cost guidance.

Our development programs remain focused on high return projects.

In fact, approximately 95% of our drilling and completion capital is dedicated to oily and NGL-rich projects , with the bulk of that being deployed in our Eagle Ford and Bakken/Three Forks program.

Our financial position remains strong and our liquidity position was recently enhanced with the increase in our borrowing base by our bank group, which Wade will talk about shortly.

This increase is being driven by the growth in our higher value oil and NGL assets.

Finally, we are on track to post significant production growth in 2012, which will exceed 30% year-over-year, again, driven by our high return liquid-rich projects.

With that, I will turn the call over to Wade for his

Thank you, Tony, and good morning, everyone.

I will be pretty brief this morning.

The first quarter was solid and, frankly, very clean.

I will begin with a brief recap of how we performed versus our guidance on slide five.

Production for the quarter came in at 50.7 Bcf equivalent or 8.4 million barrels of oil equivalent, which is right in the middle of our range that we provided for the quarter.

Jay is going to discuss production in more details during his operations review.

Costs for the quarter in essentially all areas were better than our guidance and there were no transactions or unusual items during the quarter.

GAAP net income came in at $26.3 million, or $0.39 per diluted share.

Adjusted net income for the quarter was $32.8 million, or $0.48 per share.

EBITDAX for the quarter was $259 million.

For those of you who follow us regularly, you will note that we changed from operating cash flow to EBITDAX this quarter.

We made this change because we use EBITDAX internally as a performance metric and it is more commonly used in the investment community.

Moving to slide six, I will discuss our financial position.

Our long-term debt at the end of the quarter stood at roughly $1 billion.

This translates to total debt to trailing 12 month EBITDAX at the end of the first quarter of essentially one turn, exactly 1.04 times.

Our debt to book cap at the end of the quarter was 40%.

We are in good shape with respect to debt maturities.

We did call for redemption on our convertible notes on April 2.

And for those holders who are converting, we intend to net share settle those notes.

The cash portion will be funded using our credit facility, with the balance being settled in equity.

We are still in the valuation window so we won't know the precise number of shares we will need to issue for a few more days.

As a reminder these shares have been included in diluted EPS for awhile now as the stock has traded above $54.42.

Now, on slide seven where I will discuss our credit facility.

Our bank group recently increased the borrowing base from $1.3 billion to $1.5 billion, and that was despite oil and gas prices.

As Tony alluded to, this reflects the growth of oil and NGL-rich properties in our asset base.

We have currently elected to leave our bank commitments at $1 billion.

At quarter end, we only had $24 million drawn on the credit facility, so we clearly have ample liquidity available to us to fund our capital program and corporate needs going forward.

A summary of our current hedge position is included in the appendix of the slide deck and detailed hedging information is included in our Form 10-Q, which was filed earlier this morning.

So with that, I will turn the call over to Jay.

Thank you, Wade.

I will begin my remarks starting on slide nine.

As Wade said, production for the quarter came in at 50.7 Bcfe.

On a sequential basis, this was a slight decrease from the record production we had in the fourth quarter of 2011.

However, as a reminder, we divested a portion of our non-operated Eagle Ford program in December 2011, which resulted in our working interest being reduced from approximately 27% to 14.5% in the joint venture.

Adjusted for divestitures, the Company grew production 4% sequentially.

Our production mix in the first quarter was 56% natural gas, 14% NGLs, and 30% oil, very consistent with our production mix in the fourth quarter.

We have received several inquiries regarding our production mix lately so I wanted to spend a couple of moments discussing that.

I'm currently on slide 10.

As Tony mentioned earlier, 95% of our drilling and completion capital for this year is focused on oil and NGL-rich programs.

We expect our production mix in 2012 to average about 55% natural gas and 45% liquids by volume.

By 2014, we project that mix, given our current slate of projects, will be about 50/50.

I should also note that most of our operated production in the Rocky Mountains, Mid-Continent, and Permian regions is still reported on a two-stream basis.

That is, oil and rich gas, which explains why our gas realizations continue to be somewhat higher than NYMEX.

Another general point I would like to make is that although our overall price realizations have fallen as a result of lower gas and NGL pricing, our percentage operating margin has stayed relatively flat due to our improving cost structure.

Part of this, of course, is spreading our costs over more volume as we have grown, but our continuing process of selling older high lift cost assets, our conversion to company operations versus contract on all of our significant assets, and our people's diligent effort in improving efficiency and costs are really paying dividends.

On slide 11, we show our expected rig count for the year, which is heavily weighted again towards liquids-rich projects.

As you can see, a significant portion of our operated rigs will be deployed in the Eagle Ford and Bakken/Three Forks programs, which I will now move on to discuss.

I'm now on slide 12.

In our operated Eagle Ford program, production for the quarter averaged 178.3 million cubic feet equivalent per day.

The first quarter of 2012 was really the first quarter where pad drilling had an impact on the timing of our well completions.

The way the schedule worked out, we completed zero wells in the month of February and two-thirds of the wells we completed for the quarter were actually completed in the month of March.

Our guidance anticipated these issues and volumes ended up right on our plan for the quarter.

On the cost front, based on our current contracts, we now believe our frac costs per stage in 2012 will average about 20% lower than we were running in the last half of 2011.

My expectation is that we will leverage those savings by increasing our frac density on our planned wells, which appears to us to have benefits from a per well production capacity and EUR standpoint.

I should note that we currently have three frac spreads working in the play versus two in the last half of 2011.

We currently have six operated rigs running in the play.

Our plan is to cut that number to five rigs later this year as the efficiencies we expect from pad drilling start to kick in.

On slide 13, we show an overview of our non-operated Eagle Ford program, which is performing very well.

Despite our sale of the 12.5% stake in this project to Mitsui in December, we saw production grow approximately 9% quarter-over-quarter and averaged 12.9 thousand barrels of oil equivalent per day net.

This production growth was generated by a large number of wells completed by the operator very late in 2011 and early in 2012.

We still believe that the operator will run around ten rigs in this program in 2012, and will be carried for essentially 100% of our drilling and completion activity in the non-op program for the next three to four years.

Moving to slide 14.

In the Bakken/Three Forks, production averaged 10.3 thousand barrels of oil equivalent per day net for the quarter.

We operated three rigs in the program during the first quarter and still plan to add a fourth rig here late in the second quarter.

We have also been participating in a number of non-operated wells.

As you can see from the plot, our program is producing a nice ramp in production rate.

We are also improving our drilling and completion efficiencies in the Williston.

Recently, we did a three well sequential frac in our Gooseneck development area, completing three wells with 60 frac stages in six days, including some slight delays for micro seismic.

I think that is just an indication of how much more efficient our work will become as we move into our in-fill program in all areas in the Williston over the next year.

On slide 15, we show our other development areas.

We are running three rigs in the Granite Wash, focusing on Marmaton and Missourian oily targets.

In the Permian Basin, we have a rig operating in our oily Mississippian lime play in Borden County, and finally in the Southern Rockies, we have a rig running focused on various other oily reservoir targets, including the Niobrara and Frontier.

Moving to slide 16, we show a graph of our projected growth for 2012.

Using the mid point of our guidance, we project to grow production by approximately 32% in 2012.

Much of that growth, of course, will occur in the second half.

With that, I will turn the call back over to Tony on slide 17.

Thanks, Jay.

As you just heard, we're off to a great start to the year and we are executing with confidence on our 2012 business plan.

We are focused on oily and NGL-rich projects, which will continue to drive us towards higher liquids production going forward.

Our financial position and liquidity remains strong and we are poised to deliver another year of significant profitable growth to our shareholders.

With that, we will turn the call over for your questions.

(Operator Instructions).

Your first question comes from the line of Subash Chandra with Jefferies.

Hi, good morning.

First, commentary, if you could, on the trend in NGL prices here very recently, if you have any thoughts propane, ethane, etc.?

And then I had some asset specific questions, if I could.

Well, this is Jay.

Obviously, ethane/propane prices are down.

I think there is a lot of good writing out there on the reasons for that.

We have done our own work and I would say we think it is going to be weak for awhile.

We don't have as much exposure to the Conway Hub as a lot of other people do.

So typically, our liquids are all at Bellevue and we are trading versus Bellevue.

I've heard some commentary from some operators about how they think prices are going to improve over the next few months, particularly in Conway, and that probably won't be as big an impact on us.

In general, I think if you look at the strip for propane, it is really pretty strong, solid.

I mean it is lower than it was but it is not going down.

And over time, we think those product prices will improve, but certainly, there needs to be more demand.

As a reminder, also, Subash -- this is Tony.

We've said in the past based on evaluations that we've done that even if ethane prices continued to drop and went to rejection, we would still see only 4% or 5% of reduction in our rate of return on our project, so I mean even in kind of that worst case scenario, our project is still very resilient.

That's right.

You did say that.

I was curious where do you think the Bellevue ethane rejection occurs?

Is it -- what price does ethane need to be?

You know, Subash, I don't know that we can claim to be experts on that topic and I would probably refer you to a whole bunch of people who are writing on that that probably understand the market better than we do.

Okay.

We're just committed to the idea that we have run the low site cases, as Tony indicated, and we really think we can stand a pretty low price.

Trying to project exactly what that is going to be month-by-month or quarter-by-quarter is really not in our wheelhouse of expertise.

Good enough.

And then on to more asset specific questions.

How much production was, if you will, curtailed or offline because of completion activities operated at the Eagle Ford?

And could you address why transportation costs, how you got them lower on a per unit basis sequentially?

Well, as far as exact Volumes and what was off and not off, no, I don't have those numbers for you.

I think we indicated that the real difference between fourth quarter and first quarter was the result of lack of well completions in the first quarter.

I don't remember the second question again was?

Sorry, the reduction in transportation costs per unit, how that was achieved.

In a general sense, transportation costs follow our operated Eagle Ford production.

So the dip -- a little bit of dip in production has a big driver on the overall transportation costs numbers.

The numbers move around a little bit quarter to quarter, obviously, these are accrual type numbers and it depends on when we pay the bills and how they get accrued.

But in general, our transportation costs will move with operated Eagle Ford production.

Okay.

And one final one for me.

Do you have the production mix in operated Eagle Ford versus non-op Eagle Ford?

I think if you look at what we showed in the fourth quarter for operated Eagle Ford, we were right at 56% gas in the operated Eagle Ford, which is one of the reasons -- it is probably a little unusual to us that people keep talking about our gas percentage going up when our dominant production is 56% gas.

It is 56%, that's where our growth is.

So nominally, you can't really be producing more than 56% gas.

I'm not sure where some of these people come up with all this stuff about gas percentages going up.

I'm not one of those people.

I understand, but I'm saying that because we get this question all the time and I think we try to guide on this but people don't listen apparently.

I think it is pretty clear from the fourth quarter numbers and first quarter, in general, our operating is 56% gas and non-op is oilier.

And so as that production grows, the mix gets oilier.

And of course, all our other investments, essentially, are on the oil side at this point.

Is it safe to say that I can -- I think in Q4 for non-op, we were 46% oil, 29% gas.

Is that a good number to assume going forward?

I don't see why you would use a different number to be honest.

It's going to move around some depending on where the operator over there is completing wells, but generally, it is not going to change that much quarter to quarter.

Okay.

All right.

Good enough.

Thanks, guys.

Thanks.

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Thanks, good morning.

Good morning, Scott.

Can I have a follow-up question on the NGL pricing?

What percentage of your NGL basket is ethane?

It is about 48%.

Okay.

And then propane would be about what?

It's about a quarter, I believe is the number.

That is a ballpark number.

Right at a quarter.

Actually, NGL total ethane 46% -- no that is operated Eagle Ford total.

Let me give you the numbers for operated Eagle Ford, it's 46% ethane, 24.9% propane.

Okay.

Okay.

And that's -- we sell NGLs other places but not a lot of other places, so those are generally good numbers for the Company as a whole.

The number on ethane has come up some over time for us on the Eagle Ford and I personally attribute that to higher plant recoveries but that is where we are right now.

Okay.

It does seem a little higher than most but you think that was plant specific?

About 60% now of the non-methane molecules that we produce in our NGL stream, the non-methane molecules in the gas stream in the Eagle Ford are ethane.

And then the amount you actually produce in -- you actually sell is dependent on your recoveries.

So you can calculate that recovery, but that is going to be 75%, 80% recovery, which is up a little bit from where we were.

Okay.

Understood.

Looking at the Bakken, I had a question in terms of your activity.

Where is that fourth rig going to be targeted mostly?

Well, I don't know that we have said "Hey, it is going to this place." We're going to be spread around.

Most of the activity is going to be in Bear Den area up on the [Anakline].

I think generally we will get to the in-fill program, which is what we have been hoping to do.

We expect that rig now to be probably late June.

Okay.

And when I look at your acreage position, obviously, your focused acreage is call it a little less than half of your total acreage position.

Is most the rest of it HBP, I know elm Coulee would be, but is everything else HBP or do you need to put a rig to work out there to hold some of that?

It is almost all HBP.

Okay.

And in terms of the stuff up in the Gooseneck area, what do some of your results look like recently?

I have seen some improved industry results up there.

Have you kind of been seeing some similar things as well?

Well, you know, our results in Gooseneck, they continued to improve as we upped our frac volumes, but I think, in general, they are very, very economic wells.

You know, we don't really quote IPs the way other people do because we don't manage our way around IPs.

We are getting strong wells and, generally, they've been very good.

Most of the people I've talked to have looked at the public data are telling me they are surprised by how good the wells are.

We are not surprised by that.

But they are good strong wells.

And they're not -- and they are cheaper, $1.5 million to $2 million probably cheaper than drilling in the main part of the Bakken to the south.

Scott, the way we kind of think about that -- this is Tony -- if you take a look at returns on both projects, they are very comparable, which kind of supports what Jay just said.

You got good producing wells in the divide area and yet they are cheaper wells, so your returns are comparable to the Bakken.

We like both programs, they are going well.

Great.

And one last question just on terms.

You talked about pad drilling and the impact that had during the first quarter.

How should we think about that when we look at the rest of the year?

Is it going to be fairly lumpy and does that smooth out as we get into 2013 or is that just something we need to adjust for?

I think it does smooth out.

There's a little bit of -- as we started up our rigs when we brought our pad drilling rigs on in the third and fourth quarter last year, we really kind of warmed those rigs up on individual wells and then really right at the end of the fourth quarter, we really transitioned into pad drilling with all of them, essentially at the same -- with all our three pad driller moving rigs at the same time.

We are even pad drilling some with our other rigs.

So it is lumpy here at the front.

As the schedules start to -- as some things accelerate or slip and they start to get a little bit less in rhythm, it will still be lumpy but it won't be as lumpy.

I think the real impact as you move forward over the next couple of quarters, April, during the month of April, the industry down there had several significant pipeline interruptions.

Kinder Morgan was down for several weeks due to a fire in one of their gas plants and that will impact a number of people, not just us.

Regency had a fire in a dehydration unit that had them down for essentially the entire month of April.

So April is going to be kind of a tough month from a production standpoint.

So, unfortunately, we brought on a bunch of wells right at the end of March or in March and then had a bunch of production downtime in April, and that's why our production guidance for the second quarter, the low end of that is a little lower than some people might be expecting.

I think we can recover from that during the quarter and that is why we guided where we guided.

We left our guidance alone for the year because we really do believe we can make that up.

But I think you are going to see some industry-wide impact in the month of April due to some of these downtimes.

Now, as we go forward, again, I think the lumpiness will spread out and you will start to see less impact in a given month, for example, from that.

But it's always going to be a little lumpy and you always have to account for the fact that you will have some base downtime as a result of completing wells around these pad drilled wells.

And, of course, we are need to improve our efficiency in pad drilling.

Over time, we will get better, but the schedule -- it takes us a little longer now to get a complete pad completed than we hope it will over time.

I think it will improve.

I guess that is the long story.

That is good color, I appreciate it.

Thanks.

Sure.

Your next question comes from the line of Pearce Hammond with Simmons & Company.

Good morning.

Good morning, Pearce.

Very strong Bakken production growth quarter-to-quarter.

What accounted for that?

Was that just better weather?

Well, certainly, better weather has had a big impact on the industry as a whole up there over the last quarter.

Last year, we completed almost all of the wells we completed for the year in the second half, and part of that I think is slush production from that.

Part of it is just a good steady continuous program.

Had a number of really nice wells, as one of the earlier callers asked.

Gooseneck has continued to outperform our expectations, had several really nice completions there.

It is a great program for us and I think we are really running on all cylinders with the rigs we have there and we are looking forward to our next rig coming, as I mentioned, in late June.

And then can you provide some more color on the Permian and do you potentially have some prospectivity to the Cline?

Well, any more it seems like anybody who owns acreage in the Midland Basin has prospectivity in one shale or another.

So I would say the answer to that is that we have prospectivity in shale.

The Cline is a specific shale but there is a lot of other ones, too, and I guess other than that, I won't comment on anything related to exploration.

And then lastly, what is your -- what would you estimate your base decline is for the company?

Base production decline?

We did that number at the end of the year and the number is a little over 40%.

40%?

40%, for the first year annual number.

And that's a result of us -- it's come up over time as a result of us participating in a lot of these resource plays and selling a lot of our legacy low production rate or low decline production.

So we have a pretty steep initial decline this year.

Over time, as we build a bigger base under us of these assets that have lower declines, that will start to come back down, but right now, it is in that a little over 40%.

Great.

Thank you very much.

Pearce, this is Tony.

If you think back about when a lot of these plays got their start, it was all about the same time so certainly as these plays come on with high initial decline rates, that's what drives that early on.

Great.

Thank you very much.

Thanks.

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

In the Bakken, it sounds like there are no near-term plans to drill outside of the three main areas and combine that with kind of mid billings being a little bit of a hot spot on the lease sale on Tuesday, flirting with $5,000 an acre, would you guys ever look to sell the Bakken acreage outside of the 87,000?

Well, in fact, I think a lot of people know we have a non-op Bakken package that's being marketed right now by Bank of Montreal, and we would expect bids on that later on this summer.

So we are looking at our non-op position, specifically, as we do always, to try to have more control over our capital spending.

So we will be selling some acreage this year.

As far as selling HBP, operated HBP, we don't have any plans to do that.

No compelling reason to do it.

I understand that some of that might be worth some real money.

Right at the moment, we're focused on getting our existing acreage that needs to be HBP tied up.

Once we get that done, then we will look at broadening that program.

Okay.

And you guys have mentioned in the past that Briscoe might be able to go tighter than 625s.

Have you seen anything more on that than I suppose IPAA where you last updated and when do you think you all will know where you stand on that?

Well, we haven't released any results on it.

We don't have anything to talk about today.

I would expect that we will talk again about spacing probably at the end of the year.

Perfect.

And one last one if I could on the 2014 50/50 plan, how do you envision that oil/NGL split?

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

It's going to get oilier, I can say that because of basically Bakken, Permian, Granite Wash, but I don't know the exact number.

Perfect.

That's all I have.

Thanks so much.

Your next question comes from the line of Jeff Robertson with Barclays.

Jeff, are you there?

I think Jeff disconnected his line.

We will go to the next question, David Tameron from Wells Fargo.

Good morning, David.

Hi, good morning.

Nice quarter.

Thank you.

And just, Jay, just following up on the last question, that 50/50 split, is there -- can you give us any guidance as far as what percentage of Eagle Ford, what percentage would be Bakken, Granite Wash, I mean do you guys anticipate -- you're going to four rigs in the Bakken now, do you anticipate taking that higher in the next couple of years?

Can you give us any color around that?

That number is coming out of the long-range model, which assumes about a five rig Eagle Ford program and four rig Bakken program going forward.

Most of the growth beyond that is really in the real oily Granite Wash piece and then we have some Niobrara/Permian rig count growth involved in that based on what we are seeing right now.

So in general, it is pretty much a flat operated Eagle Ford program, and that is what is built into the model that we are using to do that.

Okay.

That's helpful.

And when I say it's flat, I don't mean flat rate, I mean flat rig count.

Yes, yes.

And when I think about the -- you are adding a rig now but then it sounds like you are going to exit at five rather than six.

Are you retiring a rig, is it just pad drilling, or can you talk about the reduction in rig count?

Really, the idea of going to five rigs is that we think with pad drilling that we can get to where we need to get to on a rate curve without having to run the sixth rig.

It is an efficiency issue.

It's not that we are trying to slow down.

We actually think with pad drilling that we can get to where were drilling.

Our original plan was six rigs with five, and that is just part of what we hope to gain from the efficiencies with pad drilling.

Okay.

And just to confirm, you did say that Bakken no-op, that is included in guidance, correct?

Can you repeat the question?

I'm sorry.

The Bakken non-op, is that in guidance or not in guidance, production from that?

It is.

There is a little rate in there that we would have to if we sell it would have to come out.

It is not a big number.

Okay.

And back to the Eagle Ford.

Along with some of the other over-reaction out there, I guess I would call it, on the gas side, there has been talk about decline rates in the Eagle Ford.

Have you seen any change in your Eagle Ford operated productions as far as decline rates?

I wouldn't say we've seen a change.

I mean, these wells do decline, obviously, and they have pretty healthy normal looking resource play decline rates.

But I haven't seen anything that would indicate they are going faster.

I would say if you look at some of the -- I've had people ask me about public data on some of the wells we completed in the fourth quarter.

When we did those down-spacing tests late last year, some of the wells did have higher declines than the base wells and I think some people picked up on some of that.

A lot of what we have seen, and you've got to be really careful with the Railroad Commission data because there is so many things going on internal to the field in terms of shut-ins, restricted rates for periods of time associated with hooking up facilities, we're swapping out compression.

We had these, just in this last month, these -- a lot of downtime associated with gas offtake infrastructure.

Those guys are still starting up their facilities, too.

I think people assume these gas pipelines come on and they are just there and it really doesn't work that way.

There is a lot of up and down and we are bringing on new wells all the time, and now we're bringing them on sometimes three wells at a time and we got to handle all that.

So there is a lot of up and down in the public data and it is difficult to explain month to month exactly well by well, rate by rate.

I'm not even capable of doing it, to be honest.

So I think it is a -- it is hard when you look at that data and say it looks like declines are up, it's a little hard to really tell that unless you know exactly what the choke setting was on the wells and what we were doing at the time.

But in a general sense, I don't see anything that looks like deterioration in well performance in the base wells we're drilling.

In fact, in general, I think our wells are getting better as we learn to frac them and as we move our frac spacing closer together.

So I don't see that.

All right.

Thanks.

And then one final one.

Nevada, you know, Noble's made noise about it.

Plains was making noise this morning.

You guys have, according to the K anyway, a couple hundred thousand acres out there.

Have you -- anything you can give us on that, any color there and anything you guys have tested or looked at?

I guess you haven't tested it yet, but anything you've looked at as far as that acreage is concerned?

Well, I guess I will continue standard comment that we don't comment on our exploration efforts.

We do have opportunities there, David, we've had it for some time but other than that we are not saying much about it.

Okay.

Fair enough.

Thanks.

All right.

Thanks, David.

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt

Good morning, guys.

Just two quick questions for me.

Good morning, Matt.

To start off on I guess the operating efficiencies that you're starting to see in the Eagle Ford and the Bakken, could you give us an update on where well costs are currently running for you guys and maybe where you see those trends moving forward?

We gave a lot of data on well cost at year-end and I would say that those numbers really have not substantially changed, and I will just refer you to the presentation that has all that data because it gives a whole bunch of data on well costs.

In a general sense, as I mentioned in the earlier, we think we see our Eagle Ford frac costs coming down about -- we are thinking about 20% average for the year.

In general, I think our well costs, however, are going to stay about flat.

We are going to use most of that cost savings in putting more frac stages into these wells.

So about -- we're going to say about 20% per frac stage, we're going to put about 20% more frac into it.

That is kind of like when you buy a high mileage car, you tend to drive more, that's what we are doing here with our frac.

Other than that, though, I think the best thing for you is to go look at that data we've already provided on area-by-area well costs and I think it's very, very close to the right numbers.

Thanks.

Just wanted to check on the update there.

And then on the Eagle Ford, just wanted to clarify, again, I think I missed the response in the prepared remarks, but could you just remind me how many wells you completed in our operated acreage in January, February, and March?

We didn't actually give the exact number, but I will be happy to do it.

We completed six wells in January, zero in February, and 12 in March.

So, again, two thirds of our completions were in the month of March, and then, of course, we got those done and stumbled right into a pipeline interruption in April.

That's just the nature of the beast.

That wasn't our pipeline.

That wasn't ours, yeah.

That was a third-party offtake.

But that zero in February, obviously, that's the result of all these pad drill wells getting completed essentially together and not in the month of February, and that's the way it works.

Thank you very much.

Thank you.

Your next question comes from the line of Dan Guffey with Stifel Nicolaus.

Hi, guys.

Hi, Dan.

You are still moving rigs around Galvan and throughout Briscoe.

At what point do you think you will have the acreage held enough to where you will focus primarily on pad drilling?

Well, let me back up and talk about leases in these areas.

You don't ever get this held in the sense that you are thinking.

These are paid up leases.

We are under continuous development clauses on all of this acreage.

So the obligation is to keep drilling.

So you never have a situation where you get a well drilled at some spacing and then you got it all held.

You hold essentially 600, 640 acres every time you drill a well.

But in order to hold it all, you essentially have to drill it all over a period of time.

So the -- it is not going to be that we can -- we get to a point and then we go to development.

We are in development and as we pad drill wells, we hold the acreage that those wells drill and we fulfill our continuous development obligations to keep moving in those leases.

The smallest lease we have down there is something like 5,500 acres, we hold quite a bit with a single rig as it works.

But we will have to drill around the acreage in all of the leases over time in order to hold this entire position together.

So you will continue to see us -- we got three rigs that move very easily.

They will be pad drilling essentially all the time and the other two, we'll be moving around some, they'll be pad drilling some and moving to drill lease holding wells or continuous development wells over time.

We don't have to drill very many wells in the dry gas portion of the reservoir, hardly at all, based on the way the leases look, and we won't be -- but we will have to drill a couple a year, a few a year in order to hold it all together.

Okay.

Great.

And can you talk about the cost savings between the three rigs that are drilling on pads and two that are moving around?

Well, I think the number we have always said is $500,000, $600,000 per well cost savings for pad drilling.

Now, I want to be frank about this.

From a stewardship standpoint, we've got to pad drill.

We can't go down there and put a pad out there for every well we're going to drill on.

It would be an enormous impact on the surface anyway and we are not going to do that.

So pad drilling is a necessity of development here, but we do think we save $500,000 or $600,000 per well for the three wells that we put (inaudible).

I think as Jay mentioned earlier, we're very early in the pad drilling cycle, so those efficiencies will improve.

But we got to get up to speed and we are just now getting our walking rigs in place with our pad drilling program.

So we got a ways to go.

We are off to a reasonable start.

Okay.

Great.

Thanks, guys.

Nice quarter.

Thank you.

Your next question comes from the line of Nicolas Pope with Dahlman Rose.

Good morning, guys.

Good morning, Nick.

Quick question just on the Eagle Ford capacity, the takeaway slide that you have in the slide deck, I notice there was a change in the net volumes versus gross volumes.

It looked like it dipped from like a 14% uplift to 7% uplift, and I was trying to figure out what caused that and if we should expect that going forward or if it was just near term kind of issues with the Eagle Ford production?

Those are just our 1Q volumes and so they change it every quarter.

I don't think -- the number that I always use in my head is about a 10% uplift, so I think this seems a little low to me.

But if you are using a 10% uplift, that's probably a reasonable number over time.

At one time, it was a little higher, it was almost 20% in one quarter early last year, but I think a 10% number is probably good average.

Got it.

I just wanted to clarify that.

Thanks.

I appreciate you pointing that out.

I am embarrassed I actually didn't notice that on the slide.

It sounds like it just bounces around that 10% number, which is just what I was trying -- I wanted to make sure I was correct on that.

Yes, it goes up and down, and I think if you are out there building models, I would use the 10% number.

Got it.

And then the Mid-Con, you guys are talking about a lot of activity.

Do you have the production rate for the Mid-Con in the first quarter?

They are in the Q.

I don't have them right here.

Got it.

I think that's all I really had.

I will think everything else has been answered.

Thanks, guys.

I appreciate the time.

Thanks, Nick.

Terri, do we have any other questions out there?

I'm showing no further questions in queue.

All right.

Well, again, thank you very much for your focus and attention on SM Energy this morning.

Stay tuned for our next quarterly report.

Thank you all for dialing in.

Thank you for participating.

This does conclude today's call.

You may now disconnect.