SM Energy Co (SM) 2011 Q1 法說會逐字稿

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

My name is Ann, and I will be your coordinator for today's call.

This conference is being recorded.

(Operator Instructions)

I would like to turn the presentation over to Mr.

David Copeland, General Counsel.

Please proceed, sir.

Thank you, Ann.

Good morning to all of you for joining us by phone and online for SM Energy's first quarter 2011 earnings conference call.

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 which may cause our actual results to differ materially from results expressed or implied in our forward-looking statements, for a discussion of these risks, please 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 factor section in our Form 10-Q that we file later today.

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 the earnings press release from yesterday.

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

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

The 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, Director of Investor Relations; and myself, David Copeland, Senior Vice President and General Counsel.

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

Good morning and thank you for joining us for our first quarter 2011 earnings call.

After a few remarks, I'll turn the call over to Wade Purcell and Jay Ottoson for their respective financial and operational reviews.

As noted in our press release yesterday, we have a presentation available on our website that we'll be referring to during the call this morning.

I'm going start on slide three, where I will address key points for today's call.

On a reported basis, we're off to a strong start in 2011.

We had average daily production over 400 million cubic feet equivalent per day, which is a record for our Company.

As those of you who have read our release will know, we changed our production reporting method this quarter which now allows us to report NGL volumes separately.

Even without this change, we would have posted a new quarterly production record.

Our production growth is being driven by the growth of Eagle Ford shale program.

In fact, today, Eagle Ford comprises approximately one-third of our entire Company production.

Compared to comprising only 7% of the Company's production in the first quarter of 2010.

We continue to ramp up activity levels in our Eagle Ford program.

We have added a third operated drilling rig during the quarter.

We are still on plan to be at six operated rigs by year end.

As previously reported we added additional rich gas take away capacity in the quarter through our agreement with Energy Transfer.

That capacity is scheduled to be available to us in 2013, and is part of our long-term vision to maximize the value of our Eagle Ford asset, through a well-executed development plan aligned with the acquired infrastructure build.

We remain well positioned financially.

Our high yield offering in February was very well received by the market.

We have a strong liquidity position and we are very comfortable with the amount of leverage we currently have on the balance sheet.

I know that some of the reporting changes we announced yesterday may create some noise for the investment community.

Wade will talk in more detail about some of those issues in a moment.

What I don't want to get lost in the discussion, though, is the fact we had a very strong quarter and are off to a very good start with our 2011 business plan.

We are performing well operationally, and have the financial capability to execute our plan this year.

With that, I'll turn the call over to Wade for his review.

Thanks, Tony.

Good morning, everyone.

We have a lot to cover this morning, so please bear with me.

I'm going start on slide five.

This morning I would like to start the update with a few reporting changes.

First is our change from two stream wellhead gas sales reporting to reporting on a three stream basis, which allows us to report NGL production.

The rationale for the change is primarily based on the projected rapid growth of our Eagle Ford program and the fact that our newer contracts in the play transfer title on a post production basis.

Accordingly, we are now reporting NGL volumes and revenues.

It is important to note that prior period amounts and metrics including production and revenues have not been conformed to this new reporting presentation and such volumes were immaterial in those prior periods.

It's our belief that reporting in three streams provides more transparency of our production stream.

However, I should note that the economics of our activities and cash flows are not impacted by how we report the volumes.

Moving over to slide six, I'd like to go through the other reporting change that we've implemented in the first quarter, the elections to discontinue hedge accounting.

We've previously disclosed that we would be making this change in our 2010 10-K in February.

First and foremost, I would like to stress the fact that our decision to discontinue hedge accounting does not change how we run our commodity price risk management program or the economics of our derivatives transactions.

This change only impacts how we account for them.

This change in accounting treatment greatly reduces the potential for reporting mistakes by simplifying our internal accounting for derivatives.

Since a number of the other ENP companies also choose to not qualify for hedge accounting we think that many in the investment community will be familiar with how to treat this change and the associated largely non-cash charge.

Nonetheless it's a meaningful change and merits some discussion.

In previous quarters, when we have elected to do hedge accounting we were able to record the majority of the change in value of our net hedge asset or liability as it changed to accumulated other comprehensive income loss on the balance sheet.

This accounting method allowed us to keep a majority of the unrealized gains and losses out of the income statement.

Now that we have decided to discontinue this accounting treatment all realized and unrealized gains and hoses will flow through the income statement each quarter.

The result is that our net income will be somewhat more volatile than it has been historically.

That should be enough on the reporting changes.

Jumping to slide seven, I will quickly touch on how our results compared to guidance.

The guidance table on this slide has three columns, first columns are reported metrics based on new three stream reporting method however since the first quarter 2011 guidance which was given in our fourth quarter 2010 earnings release in February was based on the two stream wellhead sales reporting method we have shown in column two how we estimate our metrics would have looked based on its legacy method so our performance can be compared to our guidance.

So for this discussion, I will only go through the legacy two stream wellhead sales reporting results and how they compare to guidance.

Production for the quarter was 373.1 million cubic feet equivalent per day, which was slightly higher than our guidance range of 333 million to 366 million.

On the cost side, we came in at or under guidance for nearly all of the components that we provide guidance on.

On LOE our cost per Mcfe was $0.98, which was below our guidance range of $1.10 to $1.15, stronger that anticipated production was the primary driver of this outperformance.

For transportation our cost per Mcfe was $0.45, which was higher than our guidance range of $0.30 to $0.35, part of the miss is simply a bucket issue where we budgeted certain transportation related items as revenue deducts and the accounting treatment requires them to be reported as costs.

The economic substance has not changed, but the reporting has.

We also, frankly, were off on some of our budget.

As Tony mentioned earlier the Eagle Ford is growing tremendously fast, there are a lot of parts of our business that are changing particularly in the transportation front that make forecasting a difficult exercise, we will get better and improve here.

Total G&A came in at $0.77, lower than the $0.82 to $0.89 we guided came in below guidance on cash G&A, which was $0.49 per Mcfe, well below the guided range of $0.54 to $0.57.

G&A cash MPP and non-cash G&A were both at the lower end of our targeted guidance range for the quarter.

As far as other notable items for the quarter we had a gain through divestiture activities of nearly $25 million, related primarily to our divestiture of noncore PDP properties in the Rockies region, which closed in January.

For GAAP purposes we reported a net loss for the quarter of $18.5 million, or $0.29 per diluted share, adjusted net income for the quarter was $28.1 million or $0.42 per adjusted diluted share.

I will come back to this calculation in a moment.

Operating cash flow, which is a non-GAAP metric, was $161.4 million, or $2.43 per adjusted share.

Cash flow from operating activities $156.7 million for the quarter.

In the next slide, slide eight, we have a reconciliation of GAAP net income to adjusted net income, adjusted net income for the quarter adjusts for items that affect comparabilities such as one time or infrequent items or items whose timing and/or amount cannot be reasonably estimated, including large non-cash items.

We provide a majestic net income number because we believe it is the most directly comparable to the estimates that financial analysts calculate and publish.

The reconciliation you'll notice a line labeled unrealized portion of derivative gain loss.

As I mentioned a moment ago the majority of this amount used to flow through the balance sheet and as such had a much smaller impact on the income statement.

Want to point out a couple of items, with regard to our calculation of adjusted EPS this quarter.

Because the Company had a loss for the quarter on a GAAP basis, we do not report any potentially dilutive securities for the period.

However, since we have income on an adjusted basis, we have determined the best disclosure is to provide a pro forma diluted share case that assumes we earned income for the period.

Equity-based performance share awards, which evaluate our performance in absolute terms as well as our performance against our peers are one of the potentially dilutive securities which would be included in our diluted share count.

The strong performance of our stock price in recent quarters has had an impact on the number of these potentially dilutive securities increasing the number of shares that need to be included in the calculation of diluted EPS.

In addition to the dilutive effect of the equity based performance awards, the stock price averaged above the convertible note conversion price of $54.42 per share during the quarter, and this results in potentially dilutive securities for EPS purposes.

Our adjusted EPS for the quarter calculated as I described came in at $0.42 for adjusted diluted share which is slightly below Wall Street consensus.

Let's move on to slide nine.

Our financial position remains strong, our debt to book cap ratio stands at 34%.

As of the end of the quarter.

And our debt to a trailing 12 month EBITDA is 1.2 times.

We have roughly $200 million in cash on the balance sheet, and no debt maturities until 2012.

Slide 10 summarizes our long-term credit facility.

The borrowing base urrently stands at $1 billion.

We have no outstanding borrowings as of the end of the quarter.

We are currently in discussions with our bank group about potentially amending and extending our current credit facility sometime in the second quarter.

Finally, on slide 11, my last slide, which summarizes some key points pertaining to the convertible notes.

These notes have a face amount of $287.5 million, and are convertible into SM stock at a price of $54.42.

Because, as I mentioned before, our average stock price for the quarter was higher than its conversion price we would normally be required to equate potentially diluted securities related to the convert in our EPS.

Holders of notes can put the notes due us during the second quarter of 2011 as a result of the stock trading at certain levels during the first quarter of the year.

I would add that we don't believe that holders currently would have any economic incentive to put the notes to us during the quarter.

The notes can be called by SM in April 2012.

SM can settle the conversion of these notes and any combination of cash or equity that it deems appropriate.

We currently account for the converts assuming that we will net share settle.

Which means we will pay the face amount of the notes of in cash and issue equity for the remaining upside.

This is a decision that is likely a year away.

We will see where things stand as we get closer to April 2012 and make the appropriate decision at that time.

Our appendix includes an updated hedge position summary, detailed hedge positions will included in our Form 10-Q, which we expect to file with the SEC later today.

That's probably more than you wanted to hear from me today so I will turn the call over to Jay.

That was something.

Thank you, and good morning to everyone.

Slide 13 updates our production performance over the last year, I would like to note that the first quarter of 2011 is reported on our new three stream sale production reporting model while prior periods are presented on the legacy two stream wellhead sales basis.

We have continued to significantly increase our production and as Tony mentioned we hit a new Company record in the quarter on any basis reported compared to our production plan for the quarter, we performed slightly better than we anticipated.

You'll notice in the bottom right-hand corner of the slide a breakout for NGLs.

This three stream reporting method will be our standard method going forward.

There is product mix -- there is a product mix pie chart on the upper right hand corner of the slide and we are showing about a 40/60 split between liquids and natural gas.

I should note that we still do have some sales contracts that are on a wellhead sales basis.

For those contracts we will still report on a two stream basis, which is why you will still see us hosting a gas price which is above NYMEX for the first quarter.

I'm now on slide 14, which summarizes our operated Eagle Ford program.

Net production for the quarter was approximately 92 million cubic feet equivalent per day on a three stream sales reporting basis.

As Tony mentioned, we added a third rig in the quarter, and have also contracted additional gas take away capacity that will become available in 2013.

Our fourth rig should also be in the field in the second quarter.

In the near term we are bumping up against capacity limits for gas off take, our recent gross wet gas production has been limited to between 80 million and 90 million a day, due to pipeline issues on the enterprise system we are currently flowing into.

We do have a meaningful amount of capacity choked back at this point and we believe that we will be restricted to rates below 100 million cubic feet a day until around June 1.

Which is a lower offtake capacity than we expected for much of the second quarter.

We now expect to have 150 million cubic feet a day of offtake capacity by around July 1, and still anticipate additional capacity later in the year as we previously described.

Our downstream partners are working hard to meet their scheduled commitments to us, but these are large and complex projects and there will be occasional delays.

At this point we feel confident that we will have wet gas capacity in the second half to accommodate our ramp up and as a result we have not changed our drilling or completion scheduled.

We have also previously mentioned that trucking capacity for oil could be a constrained at various points in time, and that proved to be true for portions of the first quarter.

For the present we have adequate trucking capacity to handle the oil produced and we are working to make trucking operations more efficient.

We should have access to a pipeline which will allow us to move our oil to a paved road later this quarter which will be a big help.

Longer term, long distance oil pipeline infrastructure projects are going to be required to meet the demands of the play and we certainly plan on participating in some of those.

I will note for those who spend time analyzing the data we report to the Texas Railroad Commission that as a result of the production constraint issues I just talked about you'll see us increasing and decreasing production rates on individual wells as we manage production in the field to maximize value on any given day.

In general we are very happy with the performance of our wells and I'm pleased with our performance on operational aspects of the business that are within our control.

Slide 15 talks about or nonoperated Eagle Ford program with Anadarko.

In the first quarter we saw another big increase in production from the play.

Anadarko is currently operating 10 rigs, and we believe that this is the pace that they will maintain for the remainder of this year.

With respect to the on going marketing effort of or portion of Eagle Ford shale position, we are winding down the data room and will be receiving bids in the next week or two.

Given where we are in the process we really can't say much more on this subject other than to reiterate we will only sell exceptional assets like this at compelling valuations.

Consistent with what we stated previously we think we will be able to provide more clarity on our forward plans in the Eagle Ford to you by the end of the second quarter.

Moving to on slide 16, we currently have two drilling rigs operating in the Williston basin focusing on the Bakken and Three Forks intervals.

The third operated rig is expected to arrive in June.

We have approximately 200,000 net acres in the total play area.

Of which 85,000 is in the Bear Den, Raven, and Gooseneck programs in McKenzie and Divide counties, North Dakota.

These three areas are where we have been active with operated drilling in recent quarters.

However, we probably don't give ourselves enough credit for the potential value of our acreage outside of those three areas.

Many of the wells holding acreage on our HBP acreage were completed before the advances and completion technology that we've seen in recent years and I believe there is a lot of infill and recompletion potential on large portions of our acreage that we will be able to exploit.

Right now we are letting other people prove up some of this potential near our held acreage specifically in southern McKenzie county.

Moving on to slide 17, as noted in our press release from last night, we are increasing our capital expenditure budget by $40 million, to account for increased operating activity in the Haynesville shale.

Our carry and earnings agreement was completed in the first quarter or the spend under that old agreement was completed in the first quarter and our budget assumption was that we would have another arrangement similar to that deal in place by this time, which would allow us to drill our wells without spending our own money.

Our revised guidance pushes the start date for a new deal to July 1.

We are still talking to several parties at this point about potential JV arrangements.

I should note that our additional spend for the remainder of this year if we don't get a deal done would be another $90 million.

In order to maintain the schedule we need for holding all of our acreage.

Of course, that $90 million would generate additional rate and reserves as well.

Speaking of guidance, yesterday's press release included updated performance guidance for the second quarter and for the full year.

This is also included in the appendix of the presentation.

The guidance has been revised based on three stream reporting.

Our original guidance at the beginning of the year was a range of 128 to 132 Bcfe on a two stream wellhead sales basis, so a midpoint of 130 Bcfe.

On a thee stream basis that 138 Bcfe would translate to a guidance at the mid point of approximately 145 Bcfe.

We increased our production guidance today to a range of 146 to 152 Bcfe, which reflects a number of changes, the $40 million additional investment in the Haynesville I just discussed as well as our pushing back our closing date on our planned Eagle Ford sell down.

Our original budget assumption in the Eagle Ford was that we would have a deal closing at the end of the first quarter and the process has taken a little longer than we anticipated.

With that I will turn it back over to Tony for his closing comments.

Thanks, Dave.

As I mentioned we are off to a strong start in 2011, and I'm very pleased with how we are performing so far this year.

I believe we are very well positioned for executing on our business plan for the rest of this year.

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

Thank you.

(Operator Instructions)

Brian Lively with Tutor Pickering Holt.

You discussed previously about 160 million a day of additional capacity in the Eagle Ford, I think, through year end 2012.

I was just wondering, what is the throttles for the timing of that ramp?

Is that based on your commitment to the ship or pay contract or is that a function of actual infrastructure build out?

Brian, this is Jay.

It's a function of the infrastructure build out.

Our commitments are lower than that.

What we described is the capacity of the system if you added up over that period of time.

Then the additional deal we announced was on top of that but it starts in 2013.

So, if I were thinking about year end our First Quarter next year, what is the chance that you will actually have 160 million a day of actual infrastructure available at that point in time?

We think whether he be above 160 by August, September this year.

Again, assuming that people deliver on the commitments they made to us in terms of schedule, we should be in the-- I think we said in the past about-- by the way these are all gross production numbers we are talking about here, I need to make sure we clarify that.

These are not net production, they're gross wet gas volumes.

If you look at our current plan we should have in excess of 200 million a day of capacity by year end pretty easily.

Right it just seems like some of the comments from the midstream parties are suggesting that their actual build out of the pipeline will be sooner than late 2012.

I was just wondering if you get the infrastructure sooner, you are going to fill that with your restricted volumes I assume.

Yes, I think we always been very careful to make sure we've said that look, these are capacities.

That doesn't necessarily mean that's the volume that we are going to be delivering to the pipe.

We have a ship or pay volume which is somewhat lower than these capacities.

All we try to indicate with the capacity numbers is early on here when we are constrained they are probably very indicative of our rate.

As we get in toward the end of this year and into next year, we hope we are producing in to a unconstrained system.

So, then it will just be a function of out rig ramp up and all you guys who are building those models with all the little cells that have a rig in them, will be able to make a projection and get a lot closer to what our actual volumes will be.

We are not trying to say that if we have 300 million a day capacity at the end of the year, we are going to fill that.

It will be constrained at that point then, by our rig count and completion count.

Okay.

Could you estimate today what your-- how much restricted flow capacity you have?

We probably have 25 million or 30 million a day right now behind the choke.

That's going to get a little higher during this quarter as we add wells.

What we've said is that once we get the Eagle Ford deal done, we will be able to talk more straight forwardly about our forward ramp in terms of production.

That's probably a second quarter call event for us.

I don't know we will talk about it at that call, but I think in the time frame we will be able to start talking about what we really think our ramp in production might look like over a period of a number of years.

Okay.

My last question is just thinking about the Eagle Ford rate of returns.

What are your -- have you compared the rate of returns in, say, your gas condensate window area versus the Anadarko, little more oily acreage on a per-well basis?

We certainly do compare them.

In fact, if you look across the acreage position, we made the statement before, you get higher levels and higher volumes in the southern portions of our acreage in the wet gas windows.

You get lower volumes with higher margins in the northern areas that are oilier.

The economics are not that different when you look at it on a rate of return or pd basis.

So, in general we think it's pretty strong.

The areas where you obviously don't have returns is in the very, very dry gas areas on the far southern end.

We are really not drilling many wells there.

I think if you look across this, these-- as you get deeper and higher reserve counts with wet gas, those wells are very economic.

As you get shallower, at lower costs, and oilier, those wells are very economic.

All these wells make the hurdles easily.

We don't talk about forward looking returns, because we don't think that's good practice.

In general, the wells are very positive and not that much different actually from a rate of return stand point.

Thanks for the added color.

Scott Hanold with RBC Capital Markets.

I think you guys made a comment to the effect of obviously as you look through doing the Eagle Ford JV that you'll clearly focus only on-- it sounds like a price set for you to make economic sense in.

Obviously, with the Haynesville carrying earning agreements sort of being pushed out a little bit, how do you look at that cash flow deficit as you go forward in it and where you decide to price that JV?

Well, we are going to price it based on getting a really good number for it.

We don't feel like we have the do a deal; we certainly don't.

We have financial capacity, if we need to do something we got almost $900 million worth of liquidity right now.

We certainly don't want to be in position where we are negotiating with someone who thinks we have to do a deal and we don't.

As I mentioned in the script, in my conversation earlier, we are only going to sell these assets at what we think is a truly compelling valuation.

I look at Haynesville decision as kind of a separate issue.

I will say that our Haynesville wells look better and better and our costs are coming down.

We expect to see additional cost decreases in the Haynesville in the second half.

I think for us it's a matter of drilling wells that meet our hurdles.

If we can do, that obviously we have a low cost of capital.

We are going to look at all the things in that calculation.

We have pursued Eagle Ford deal for three reasons, really.

One, we wanted to sell down our non-out position to some extent, because we wanted to be in more control of our capital.

Second, was to lock in some rates of return, really a hedge against either higher costs or lower prices in the future.

I think that's still a legitimate reason to do a deal.

The third, is because we really felt that we could lock in some returns, we're a return-focused company.

However, if we don't get a value we like, we don't have to sell it.

We look at these assets as being extraordinary.

We think that Eagle Ford is one of the best shale plays in the country, if not the best, in terms of margins.

And we really believe that we deserve and ought to get a compelling valuation for the assets.

As we go forward that's the basis on which we are working.

We do believe there is an opportunity in this to fill our gap between cash flow and CapEx and we are certainly looking at what we think that gap is as we go into this calculation.

There is not a real-- there's certainly no need for us to sell a lot more beyond filling our gap, other than if we get a really compelling number.

Okay.

Remind me, how many operator rigs would it take to hold your acreage?

If you're just in theory here to do [the loan]?

Four or five.

It's really not a-- we are basically going to be there this year on average rig count basis.

It's not a huge rig count to hold operated acreage.

This is Tony.

As you might recall, a lot of our leases are large blocks, so they don't require a section by section drilling commitment.

That allows us to go with a more moderate rig fleet.

Okay.

Back to the Haynesville Carry and Earning Agreement.

Given that you didn't have an agreement in place, was that due to price, just sort of a difference in the opinion in price?

Can you give us a little color on why that was pushed a little bit or was-- I guess another one was enclosed?

When we look at it, again, these wells are close to making our drilling hurdles.

This is Jay again.

We really don't need that much of a boost to get them over that hurdle.

Some of the deals we seen, frankly, were probably people want to do a deal that's a little more attractive to them than perhaps we think we need to do.

I mean, I have to say I think we are on the fence here.

We are looking at some arrangements, we're talking to people about deals and at the same time we're watching our well results and our costs.

We are still talking to people and we're pushing it out a little bit, trying to make a decision.

To some extent how much flexibility we have on capital will have something to do with our decision.

At this point we are manning on trying to make a deal, but that deal doesn't have to be as big as it needed to be six months ago, because frankly, the wells look better.

I think it's changed and evolved a little bit.

I will say, there's not a lot of people out there right now, especially operators interested in taking on more obligations in Haynesville.

And that's been true for quite some time.

You are talking to some nonconventional people who have a little different take on this, on why they want to be in these plays, and that makes the conversation a little bit different than what we are normally used to.

That makes sense.

A couple of quick ones; you all didn't really provide well data points on some recent drilling in the Eagle Ford.

Is that something that you are going to plan doing going forward or was there is a reason not to do that?

On the 25 million to 30 million a day rate that you said was sort of being choked back right now, is that a gross or net number?

Well, it's approximate enough it can be either gross or net number.

I would say we don't intend to give detail.

We have got a lot of wells drilled here, we are not going to give detailed individual well number-- well rates on a consistent basis going forward.

Okay, but everything is coming in as expected so far?

Yes.

As I mentioned earlier, we are very happy with our well results.

I think if you are out there looking on state reported data, you can see we have really big wells in this play.

Thank you.

Thanks, Scott.

Jack Aydin with KeyBanc market capital.

Jake, could you give us what you are budgeting per well costs in the Eagle Ford and also in the Bakken?

Well, what we budgeted and what we're experiencing are a little bit different.

Typically --

Give me both.

Typical well costs in Eagle Ford range from about $5.5 million, in the north, to as much as $7.5 million on some of the very southern tip wells we are having to haul water to, that cost will come down as we have to build out our water infrastructure.

You are seeing costs in that range; $5.5 million to $7.5 million.

On the Bakken side we are still seeing cost escalation particularly non-off AFEs.

We are drilling wells there for-- say, in the northern area, in the divides area, probably in the $5.5 million to $6 million range.

It's quite a bit cheaper up there, because it's shallower.

We've seen non-off AFEs well in excess of $8 million in the deeper portions of the play.

Our well costs are still in that high $7 millions, probably in the deeper portions.

It's getting more expensive all the time in the Bakken, there's no question about that.

The wells look pretty good, but you really, at this point the costs are high and you really need these kind of oil prices to make this a real attractive play.

Would you care to give us a PV 10, for some of those wells in the Eagle Ford?

No, we wouldn't care to do that.

Okay.

I knew that.

Okay, thanks.

Now, Jack, I'm not trying to be difficult with that.

But people who sit in front of their own contractors and hand out information about what kinds of rates of returns they make on wells?

That doesn't make a lot of sense to us, okay?

Yes.

Thanks a lot.

Dan Guffey with Stifel Nicolaus.

You mentioned you are going to run 4 to 5 rigs, or you need to run 4 to 5 rigs to hold all our acreage in the Eagle Ford.

I was wondering at what point will you start drilling down multiple wells off a single pad and how much cost savings you can see from that?

Well, we already are starting pad drilling, the third rig we picked up, really is focused on pad drilling.

So, we are already engaged the in that and experimenting with what we can do and how fast we can move on it.

I don't know that the-- I'm not prepared at this point to tell you how much we think we can save, because we are going to see how it really works out.

I think there is a couple of things, thought, that will drive our costs lower.

One is water infrastructure; we are building infrastructure to move water around the field so we don't have to truck as much.

That will have a big impact on our well costs.

Then, the second issue is this pad drilling concept.

The good thing, as tony mentioned about our acreage, is that we don't have to drill a well on every section before we can go back and start pad drilling and down spacing program.

So, during this year we have some pad drilling pilots and down spacing pilots we're working on.

We hope to be able to develop the field-- to do significant development in the field at the final, at the spacing we determined being optimum, using pad drilling.

So, I think the combination of down spacing, pad drilling, and water filling infrastructure is going to drive the well costs substantially lower over time.

We are excited.

This year is the year when we really learn a lot about that.

Dan, this is tony.

One of our initial plans on pad drilling is to see if we can-- and of course we are just getting started with this, but our intent is to see if we can drill 3 wells from spud to first production in about 80 days.

That is a pretty aggressive target, but it's one that we think will significantly improve our efficiencies and costs if we can get there.

Okay great.

I know you guys have done some tests on some 60-acre spacing.

Wondering if you have any other tests for the remainder of the year?

Down spacing?

We have several other down spacing pilots that we're planning on this year.

I don't remember the exact numbers, but it's multiples.

We will be doing that in various portions of the field and, I should say Anadarko is doing the pilots as well.

They are testing down to what we would look at as something like 50-acre spacing.

I think the down spacing potential in here is substantial and there is no acreage costs associated with doing it.

So, the economics for that look pretty strong.

Great.

Then, switching over.

You guys didn't talk about recent [Niobrara] activity.

Wondering if you could kind of give the results on that Polaris 124H well and plans going forward in the play.

Well, we haven't completed a Polaris well yet, that's why we haven't talked about it.

We got the well drilled and we are working on another well right now, actually, the Jupiter, and we're going to get that well drilled.

We borrowed a rig for a window here to get the two wells done, so we are going to drill and complete those two wells should be completing a little later this summer.

Then, we are probably going to come back and drill another one later on in the fall if we can find another rig window.

So, we would expect to have 3, maybe 4, wells drilled by year end in our Niobrara position.

No results to announce as yet.

Okay.

Great.

Then, one last one.

You mentioned Eagle Ford wells in your operated acreage are $5.5 million to $7.5 million depending on where you're at in the play.

Just wondering where the Anadarko wells are coming in at.

When I said $5.5 million, I was referring to Anadarko.

You were?

Okay.

North?

North of mouth, yes.

Okay.

Makes sense.

That's more their kind of number at this point.

Okay, fantastic, thanks, guys.

Nick pope with Domen Rose.

I was curious in terms of the EUR you are looking at in the Eagle Ford, whenever you go to the three-stream accounting.

What the percentage uplift would be on the EURs from the previous-- the two-stream accounting.

Do you have that number?

That's a good question.

It's going to vary depending on obviously the liquid content of the wells.

I got an example here.

For example, the well that was booked in the area that we call gal van10, which means it's got 10 barrels/1 million of condensate yield.

It's going to have about a 1250btu per standard cubic foot NGL content.

We booked the well at about 2.6 Bcf.

One a three-stream basis it's going to be 3.6 Bcf.

So, it's a significant uplift in reserve add.

You have to remember, though, to be really careful when you apply these.

That uplift is only going to apply on these high NGL wells.

It doesn't apply to our entire reserve deck and it doesn't apply to even all the entire Eagle Ford.

But, it is going to have a substantial impact on [crude] bookings and potential numbers on Eagle Ford wet gas wells.

Okay.

That's helpful.

Then, earlier you spoke about where current rates were, and what they were bumping up to.

I was hoping-- could you clarify when you said 80 to 90 was that gross number on the operated area?

That's the gross wet gas produced number.

So, that includes the royalty-- it's the gross number going down the pipe.

All the numbers we talk about in terms of pipeline capacity, are gross operated numbers, but wet gas.

That's just the operated area, is that right?

That's right.

Anadarko has their own system.

They will make whatever comments they make about their constraints.

All right.

That's all I had, thanks, guys.

Welles Fitzpatrick with Johnson Rice.

I was wondering, could we get update on the Marcellus?

I think last at IPAA you guys were looking around for some other type of structure up there?

I would say at this point, Welles, we have continued to work in terms of looking for a compelling sale up there.

I won't say a whole lot more about it other than the fact that we are continuing to work that and hope to be through that process here shortly.

Since we are still in the negotiating phase and looking at options, probably ought to leave it at that for the time being.

Okay.

Given your comments on 60- and 50-acre tests, is it fair to a assume that those gal van 80-acre tests are holding up well?

How much data would you be looking for, before moving the development program to tighter spacing?

That's a great question.

How much data do you need?

I would probably say you want about 18 months of production before you make a big commitment to a certain spacing.

Because, really, what you are looking for is that first couple year payout before you would say okay, I'm going to make that judgment.

Ultimately, it's not the ultimate reserves that matter as much as it is getting the well to payout quickly, because it's at the end of the day it's a present worth question.

I would think-- you know, you get a pretty good indication of our decline rate.

If the wells come in and they start and hang in there with their parent wells for a while, I think if you get 12, 18 months out, you get a pretty good idea what you've got.

We never said that down spacing is going to apply to all areas of the field.

I don't think it necessarily will, but I think there is a good chance that we will be down spacing a lot of the acreage.

Both on our own acreage and Anadarko acreage.

Okay.

Perfect.

Could you remind us, how long ago those initial 80-acre tests were done?

I think the first ones we did were about 6 months ago now.

They were in 2010, so I think it was in maybe third or fourth quarter.

I think that's about right.

I don't want to say exactly, because I don't exactly remember.

We drilled a lot of wells last year, but I think it was third or fourth quarter.

I think we have 6 months of data and the data I've seen, the wells look good.

They are about what we would have expected.

Perfect.

Thanks, guys, that's all I got.

Patrick Reganger with Barrett Capital Partners.

I have a question on your oil production, looks like it was relatively flat quarter over quarter.

Is that just declines in some of the other operating areas, like Permian and Granite Wash or--?

Well, certainly, there are underlying declines.

We were constrained, to some extent, during the quarter by trucking in the Eagle Ford.

Okay.

Looks like at the low end of the guidance, it will be kind of flat in second quarter?

Yes.

We also sold some assets in the Rockies that closed in-- was it January?

Which I think is what is really driving the numbers.

Okay.

I want to go back on the question I just answered with respect to how long those down space wells would be.

I think I may have confused with the down space wells with the simul frac wells we drilled 6 months ago or so.

I think the down space wells are newer than what I just said.

I don't think they have been on 6 months; I think it's only been about 3, but the results I've seen from them, again, still look good.

I just don't think we have a full six months worth of data on those.

Okay.

Then, my other question was in the Haynesville you mentioned that the well rates were improving.

Can you give us just a ballpark range on what some of those recent rates have been?

Well, we have been consistently making wells that are blowing at 10 million to 12 million a day on restricted chokes at 8,500 to 9,000 pounds.

As we move to the southern end of the acreage, the wells get stronger, the pressures are higher, and our reserve estimates are getting higher as well.

We've made really good wells.

Really the only issue there is getting our well costs down some to get them to where they will make our hurdles and drill out.

We have a target in mind for what we want to get our well cost to.

I think that target is achievable over time and certainly gas prices perked up a little bit, so that has helped us as well.

I think if you are thinking about better wells in east Texas, you know, that 12 million, 13 million a day kind of number, at high pressures, that's the kind of volumes we are is been making.

That's all I have, thank you very much.

Our last question today comes from the line of Andrew Coleman with Madison Williams.

Good morning, folks.

I guess question was here on the Bakken, can you go over what type you are using for the divide county wells?

Have you given that somewhere?

I don't know we have.

My recollection is that that number is around be 300,000 barrels.

Okay.

How much water production have you seen from those wells?

They do produce at a higher water cut.

That area up there has higher water saturations.

I think that's frankly one of the reasons we were able to get the acreage, is people looked at that and were afraid of it.

As it's turned out, the wells produce very well.

They do produce at a little higher water cut, but at pretty decent rates.

As I said it's a little shallower, a little lower pressure, so you don't make the big IPs that you make in some portions of the Bakken.

They are [Freeport's] wells, I should say.

They are pretty economic.

Because you have lower well costs.

Right.

So well costs then, $5 million?

Yes.

If you are using $5.5 million, probably right now if you use $5.5 million to $6 million, that's probably not an un reasonable number.

It's $1 million, $1.5 million lower than our typical Bakken three-fourths completion.

Okay.

And you said these are three-fourths completion.

From a stratigraphic column standpoint, is the [middle] Bakken present in this part of the play?

Yes.

It's present, but looks wetter.

So, we haven't done a Bakken completion.

I think there are some guys doing Bakken completions not far from us and up into Canada and as you go I think [farther west].

This is one of things we probably need to try, is to put another lateral in the Bakken and see what happens.

At this point, we have not done that, because it just looks wet.

But I think there is some additional potential the Bakken section.

We've stayed in the three-fourths, because the saturations look better.

Thanks a lot, guys.

Ladies and gentlemen, this concludes today's question-and-answer session.

I would like to turn the call back over to Mr.

Tony Best for closing remarks.

Thank you, operator.

Thanks to everyone for calling in this morning and for your interest in SM Energy.

We will talk to all of you next quarter.

Thank you very much.

Ladies and gentlemen we thank you for your participation in today's conference, this concludes the presentation.

You may now disconnect.

Have a good day.