SM Energy Co (SM) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2010 SM Energy Company earnings conference call.

My name is Stephanie and I will be your operator for today.

(Operator Instructions) I would now like to turn the conference over to your host for today, Mr.

Brent Collins, Director of Investor Relations.

You may proceed.

Thank you, Stephanie.

Good morning to all of you joining us by phone and online for SM Energy Company's second quarter 2010 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 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, our presentation posted to our website for this call and risk factors section in our 2010 10-K as well as our Form 10-Q that will be filed later today or tomorrow.

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

A 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 three-tier reserves and estimated ultimate recovery -- or EUR -- on this call.

You should read the cautionary language page on our slide presentation for an important discussion of the terms and 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 VP and Chief Financial Officer; and Brent Collins, Director of Investor Relations.

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

Thank you, Brent.

Good morning, and thank you for joining us for our second quarter earnings call, our first call under the new SM Energy name.

After a few brief remarks, I will turn the call over to Wade Pursell and Jay Ottoson for their respective financial and operational reviews.

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

I'm going to start on slide three, where I'll address the highlights for today's call.

For those of you who follow SM Energy on a regular basis, you know that execution of this year's business plan is a theme that we have focused on for 2010.

With half of the year behind us, I'm pleased to say that we're executing well for the targets we set our sights on at the beginning of this year.

Building on the positive results we had in the first quarter, our solid second quarter results were a great way to finish the first half of 2010.

We performed well against the guidance that we provided for the quarter.

We also topped our production guidance for the quarter, which bodes well for our proved reserved bookings as we look towards the end of this year.

The production beat was led by solid production contribution from the Eagle Ford shale program.

Both the operated and non-operated portions of the play are working well and on the cost side we met or came in below guidance on LOE, transportation, and production taxes.

We advanced our operated Eagle Ford program in a meaningful way by committing to a long-term, firm transportation and processing arrangement for up to 200 million cubic feet per day going forward.

On the operations front our announced results in the Granite Wash and the Niobrara are exciting new developments which could add meaningfully to our project inventory.

In the Williston basin, we are beginning to hit our stride.

We drilled our best well to date in our Three Forks program in Divide County and our first horizontal Bakken well in the Raven prospect was also a success.

Last night we announced that we are increasing our capital investment forecast to $871 million, up from $725 million at the start of this year.

This decision to increase our capital spend and go outside of cash flow, plus divestiture proceeds was not taken lightly.

If you look at the areas where we are increasing capital investment, they are all areas where we are seeing significant success.

They are oily or rich gas projects, which have stronger economics compared to the gassier parts of our portfolio.

Increasing CapEx allows us to increase or maintain our activity levels in these programs, which helps set up a path for growth in 2011 and beyond.

We pre-funded much of this capital increase with higher-than-expected divestiture proceeds from sales that closed earlier this year.

Our balance sheet is in great shape so we can fund this increase with our revolver and still maintain very strong liquidity.

Wade will discuss this a little more in a moment.

I'm very pleased with our performance to date.

As we enter the back half of 2010 we will continue to focus on the successful execution of our business plan.

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

Thank you, Tony.

Good morning, everyone.

Late yesterday, we released our second quarter earnings press release and highlights.

I'll touch briefly on some of the more important aspects of the announcement starting on slide five, which shows our performance in the areas we guided on.

Starting with production, production for the quarter was 276 million cubic feet equivalent per day, which was slightly over the guidance range of 253 to 274.

As Tony mentioned, we've seen very strong performance this year from our Eagle Ford shale program.

On the cost side, we came in at or under guidance for the majority of the cost that we provided guidance on.

On LOE our cost per Mcfe was $1.15, which was below our guidance range of $1.24 to $1.32.

Similar to the first quarter, we did not see the increased costs we were expecting to see.

However, given the level of activity in the industry we think it's only a matter of time before we start to see some increases here.

Total G&A came in at $1.01 per Mcfe.

We had guided $0.94 to $1.00, so we were slightly over guidance.

Came in a little above on cash G&A, $0.61 per Mcfe versus guidance of $0.53 to $0.55, largely due to the timing of the recognition of certain legal and admin expenses.

These are related to costs that we know we are going to incur during the year but don't always know exactly when they will happen.

DD&A for the quarter was $3.17 per Mcfe.

We guided to a range of $2.90 to $3.10.

Therefore, we exceeded our guidance.

Our DD&A rate is being impacted by upfront capital costs for things like infrastructure, science wells, with lots of coring logs, et cetera.

These costs don't generate a lot of initial reserves and accordingly the DD&A goes up as a result.

There's not a lot of unusual items this quarter.

We did have a gain of $7 million related to divestiture activities.

This primarily related to the sale of some minor, non-core North Dakota, Texas and Wyoming properties.

For the bottom line, we reported net income for the quarter of $18.1 million or $0.28 per diluted share.

Adjusted net income for the quarter, which excludes items that are generally one-time or infrequent items or items whose timing and/or amount cannot be reasonably estimated was $10.2 million or $0.16 per diluted share, which is right at where the Street was.

We provided an adjusted net income number because we believe it's most directly comparable to the estimates that financial analysts calculate and publish.

Cash flow from operating activities was $116.3 million for the quarter.

Operating cash flow for the quarter was $119.2 million, or $1.85 per diluted share, and this beat Wall Street consensus numbers.

If you go to slide six, you'll see that the balance sheet is in solid shape.

Our debt-to-book cap is 19% at the end of the quarter.

Jay will talk about our increase in CapEx more in a moment, but a key point to keep in mind with respect to funding that increase is that we have a lot of capacity in our balance sheet to fund these projects.

Moving on to slide seven, our borrowing base on the credit facility remains at $900 million with nothing drawn under the facility as of the end of the quarter, and I would add that we have nothing drawn as of this morning either.

With our planned increase in capital investment, we'll obviously be going into our revolver the latter half of the year.

You might remember that our plan entering this year was to fund our capital program with cash from operations and proceeds from divestitures.

Clearly, commodity prices will influence how much we need to pull down from the revolver.

But we did realize more in proceeds earlier this year than we expected and have been successful accelerating the receipt of some tax refunds, as well.

So, our use of the revolver this year should be fairly modest.

Finally, on slide eight, which is my last slide, there's a summary of our hedging position.

Our hedge position is designed to support the predictability of our cash flow.

We try to target a hedge base of 50% of our PDP.

We have a pretty solid position that goes out a couple of years.

In recent quarters we've been more active in our hedging of NGLs.

We see the same thing that many of you do with respect to the amount of activity pursuing rich gas.

We think that we can mitigate some of the price risk on the NGL front by hedging NGLs today.

A summary of our hedging position is included in the appendix of this presentation for the call today and details will be provided in our 10-Q which should be filed this afternoon.

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

Thank you, Wade.

Good morning, everyone.

Operationally, SM Energy had an outstanding second quarter.

We're well ahead of our rate forecast for the year at lower operating costs than we had projected.

As we indicated in our press release, we'll be stepping up the pace for our capital spending in the second half in several plays which we have proved of through our exploration and delineation program.

I'll provide a quick update of our operations and then review the changes to our capital expenditure forecast for the year.

I'm going to start on slide ten with the horizontal Granite Wash, where yesterday we released our results from our first operated horizontal wells in the Mayfield area in Beckham County, Oklahoma.

The first well we drilled, the Wester 2-34H, a Skinner interval test, is making about 5 million cubic feet equivalent a day and large amounts of water.

Although we think there's still significant horizontal potential in the Skinner interval, we're unlikely to drill another one of these until we determine where the water is coming from and know how to minimize that risk.

The better news is that our second well, the McEntire 2-27H, had a seven day rate of 14 million cubic feet equivalent per day and a 30 day rate of 12.9 million cubic feet equivalent per day.

These rates include the gas equivalent volume converted at 6:1 of approximately 500 barrels a day at condensate but do not include volumes associated with the almost 6 gallons per 1000 cubic feet of NGLs this gas contains, because with sell this rich gas at the wellhead and don't count the NGL volumes.

This well targeted the Marmaton B formation and was completed with a 4,400 foot horizontal-lateral.

We have TDd our third well in the area, the McGuire 1-6H, which is another Marmaton B well, and plan to complete that well shortly.

Given our encouraging results we're going to pick up a second rig in the play during the second half of 2010, which will increase our capital spend.

I should note that the area we're showing on our map on slide ten is only a part of our acreage position.

In fact, one of our upcoming wells will actually be in the Stiles Ranch area over in the Texas Panhandle.

Moving to the next slide, we also have some news on our exploration program targeting the Niobrara.

Our initial horizontal well in the Niobrara play, the Atlas 1-19H was completed in mid-May.

The well is in Laramie County, Wyoming, just south of the Silo Field.

We had a seven day production rate of 1,075 barrels of oil equivalent per day.

Two months later it is still making roughly 500 barrels of oil equivalent per day.

We're very happy with how the rates are holding up so far.

Based on our success, we've shipped in some exploration funds and are planning to drill another well in the play later this year.

We're actually looking for the rig to drill that well right now.

We have roughly 25,000 acres leased in that area.

Both the Granite Wash and Niobrara plays have the potential to be high-margin development programs and we believe they will add materially to our inventory of liquids-rich drilling opportunities.

Moving to the Eagle Ford -- I'm now on slide 12 -- let's start with operated activity.

We now have 25 wells producing to sales.

Our current gross operating production out of the Eagle Ford is roughly 41 million standard cubic feet a day of rich gas and 1,375 barrels a day of condensate.

This compares to end of last quarter -- our average last quarter when our production was 23 million standard cubic feet a day of rich gas and 420 barrels per day of condensate.

We're running ahead of our projections, even though we've been downstream facility constrained for periods of time.

We're currently bumping downstream limits again and expect that it will be early September before we can materially increase our operated rates.

We still believe that we'll be able to access close to 80 million a day of downstream gas outtake capacity that we have committed by year-end.

As Tony previously discussed, we just committed to a big traunch of additional downstream capacity with Kinder Morgan and Copano, which should become available by the middle of 2011.

We're working really hard to clarify what our downstream limits will be by month for the times between now and mid-2011.

Once we have some more certainty on that, we'll plan out our rig activity, which will drive our 2011 spending forecast.

Speaking of our rig operations, we're currently projecting that with our two-rig program, operated in the Eagle Ford, we will drill 40 wells in 2010 versus the 34 originally budgeted.

This increase is due to improved drilling efficiencies associated with continuous improvement in our field operations.

We believe that we will be able to complete a number of these additional wells in this calendar year, although the services environment has been tightening in the play.

In addition to being pleased with the increasing efficiency of our operations, we're also happy with the amount of important information we're gathering about the potential of our acreage.

We've been spreading our wells around to accomplish that goal.

We've been consistently drilling through 5,000 foot in-the-pay laterals and we're experimenting with a number of different things like frac formulations, downspacing tests, simul-fracing, and restricted-rate testing.

On the delineation front, we're currently drilling our first well on our acreage in La Salle County, and we're excited about the potential in that area.

We're just flowing back our first simul-frac pilot fest.

This test involves simultaneously completing two wells with 5,000-foot laterals 1,250 feet apart.

Our initial look at the microseismic from this test indicates that we can probably push the wells closer together and if that is verified by our flowback data we'll plan another test with closer spacing.

As I mentioned, we've done restricted rate testing on a number of wells at this point.

So far, we've not seen much indication that restricting flowback rates will change our EUR significantly.

This outcome, frankly, does not surprise me a lot given the hardness of the shale, the relatively shallow depths and pressure regimes we're operating in on our acreage.

As a practical matter, we'll continue to have restricted rates on some new wells until we get more downstream capacity.

And if we see anything different in our additional data, we'll mention that in future calls.

With regard to the retrograde condensate issue, we've still not seen any indication of decreasing levels of condensate yield in our wells, which is obviously encouraging.

On the non-op side Anadarko has accelerated their pace and now has six rigs working in the field versus the two rig lines we originally budgeted for.

The portion of the play where we are participating with Anadarko has significant condensate yields and rich gas.

Obviously in the current commodity price environment, plays with lots of contribution from condensate and rich gas are where you want to be.

We think Anadarko's ramp in activity speaks for itself and we're increasing our CapEx forecast intending to keep up with them.

Since Anadarko is the operator, we'll defer to them as far as talking about specifics, and we believe they may be providing more information on their call on Wednesday.

I'm now on slide 13, the Bakken/Three Forks slide.

We maintained a two rig program in the Williston Basin for most of the second quarter.

We previously had disclosed in our IRR presentation some of the solid results that we've have been achieving.

Our most recent results are continuing that positive trend.

In Divide County, in our Gooseneck prospect area, the Radenic 14-20H Three Forks well looks to be the best well drilled in that area to date.

The 7 and 30-day production rates were 670 barrels of oil equivalent per day and 420 barrels of oil equivalent per day, respectively.

I should note that these wells are around $1 million less expensive than similar wells farther south in the play due to the depth.

In our Raven prospect area in central McKenzie County, North Dakota, which is basically the same areas as some other people call, Rough Rider, our first operated horizontal well in the area, the Johnson 16-34H had a 30-day rate of 700 barrels of oil equivalent per day.

This well used a ten stage high liquid volume completion and costs approximately $5.6 million.

Activity levels are high in North Dakota and costs are up substantially from the beginning of the year.

Our non-operated activity in the play is up sharply from the budget and our drilling efficiency again is driving us to drill and complete more wells than we had originally planned.

In total, we now expect to operate 19 wells in the play this year versus our original plan of 17.

I'll now turn to our updated capital investment forecast for the remainder of the year.

I'm on slide 14.

Our current estimate of investments for 2010 is now $871 million, as Tony mentioned.

A breakdown of this plan, and the changes from our last update, is shown on the slide.

The increase in capital investment is being directed to areas that I just reviewed, where we are seeing success and high returns.

And this revised capital plan allows us to accelerate value generation on these programs.

Additionally, as you all know, costs for dilling and completions have been rapidly rising across our industry as service companies are attempting to get back to the same levels of profitability they had before the downturn of 2008.

We now estimate that our 2010 drilling and completion costs will be up approximately 10% to 12% over our original budget assumptions.

Our previously announced carry and earning agreement in the Haynesville provided some cushion to absorb these cost increases and maintain the pace of our capital program.

However, this revised forecast does reflect those cost increases.

I would also like to note the increase in our facilities and infrastructure spend which we have partially offset by reducing our land spend.

This additional infrastructure spend is almost entirely due to success driven mid-stream spending in both the operated and non-operated Eagle Ford play and is required for us to maintain our production growth there in 2011 and beyond.

The capital is largely to cover in-field piping and facilities.

On slide 15, there's a summary of our revised production outlook for the remainder of the year.

Our new forecast is for a production range of 104 to 108 Bcfe.

With increased capital investment you would expect an increase in production and we are increasing our production forecast by roughly 5%.

Taking a step back, what I would like to make sure that people appreciate is that the Company has done a lot to improve its inventory over the last few years to get to a point where we can grow organically at high rates of return.

I think we're starting to turn the flywheel on the production front.

With that, I'll turn it back over to Tony for his closing comments.

Thanks, Jay.

With that, I'll move to slide 16.

I would like to leave you with some key take-aways from our call today.

The execution of our 2010 program is right on track.

Our second quarter results cap a successful first half of the year and we're seeing exciting developments in both our exploration and development programs.

The announced results in the Granite Wash and the Niobrara were obviously very encouraging and have the potential to add meaningfully to the inventory that Jay just talked about.

Our development programs are performing well, led by some very good results in the Williston Basin.

We also made a big step in moving the operated Eagle Ford forward with our commitment to long-term transportation and processing with Kinder Morgan and Copano.

The clear message is that we wouldn't be making these type of commitments if we weren't excited about the Eagle Ford program.

With respect to the increase in the capital investment forecast, there are a couple of key points I want to make.

First, the increase is due to the significant success we're having in a number of our key plays.

We want to maintain or increase our activity and the momentum in these plays going forward.

Second, our balance sheet is in great shape and can easily handle this increase in capital investment while maintaining the financial strength that you think of when you think of SM Energy.

We plan to continue our focus on the execution of this year's business plan and close strong through the rest of 2010.

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

(Operator Instructions)

Your first question comes from the line of Mike Scialla with Stifel Nicolaus.

You may proceed.

Good morning, guys.

Good morning, Mike.

Had a question on the Eagle Ford -- it seemed like you were pretty conservative at year-end with your reserve estimates there per well.

Do you have enough data now to boost that EUR up?

I think you were talking about two and a half BCF as kind of an average well.

Do you got confidence now to move that to a higher number?

This is Jay, Mike.

We don't guide on reserves in the middle of the year.

We'll see what we book at year-end.

I would say that when we look at the wells we had booked at year-end they are performing a little better than we had projected.

I think generally the trend is upward on those wells.

On the newer wells we drilled we've been pumping so many different frac jobs and doing so many different things it's very difficult to say "Well, okay all of these wells are looking at a higher reserve level." So, I think it's pre-mature to make that kind of a judgement.

I think it is fair to say that the wells we booked last year, when we look at them now, all of the wells that we booked which we only had seven or nine of them at the end of the year.

We booked them again today, they would be at a somewhat higher level.

Not a lot higher, because we're not going to go crazy on this, but somewhat higher.

Okay.

And then you're comment on the restricted rates that don't really seem to be making much of a difference.

I guess does that mean you're going to abandon that as soon as you have sufficient capacity and if restricted rates aren't making difference is there anything different at this point -- it sounds like trying bunch of different completion techniques but do you feel like you're honing in on the optimal completion techniques at this point?

Well there's two questions there.

One is -- and this is Javan again.

One is about restricted rates.

I think in general our view in the shallower portions of the play where your pressures are lower and closure stressors are lower that the restricting rate is less likely to benefit you, and given adequate downstream capacity our intention would be not to restrict rates in this well.

In the deeper portions of the play, maybe on the far south portion of our acreage, there may be some value to it.

Still a little early, I think, for us to judge that.

In either case, I don't think it's going to be a massive benefit, and obviously there's PW benefits to producing the wells earlier.

So, I think at this point if we had enough downstream capacity to open up all of these wells up, we would do that.

On the second question--trying to remember what the second question was now.

Completion optimize--

Optimize completions.

We have tried a number of different frac techniques.

At this point, I would have to say that pumping large volumes of slick water has shown to be the best technique for completing these wells.

We have tried a number of different fracs with linear gels and other types of gel fluids to try to reduce the water usage and do other things with them.

But at this point slick water appears to be the right technique for at least in our area of the play and I think it's very clear that's not going to be true for everybody and it's probably isn't even true across our acreage but in general large slick water jobs appear to be the way we're going.

I appreciate that.

One last one if I could.

Wanted to ask, on the Bakken play--or actually the Three Forks--with the latest well looks very good.

Do you have an estimate on what an EUR might be and you alluded to less expensive completed well cost due to the depth there.

Could you give an average completed well cost for that area as well in Divide County?

Well, they're about $1 million less than our typical Bakken well so you're in the high 4s, probably, for a completed well cost.

We typically complete them again with a ten stage high liquid volume kind of frac.

We're experimenting with more stages closer together as we go into some of these wells just to see what impact that has but the big volumes appear to be working for us.

You know, EURs in Bakken you hear these big numbers from some people.

For our economics, our AFEs we still run most of these wells at around 400,000 barrels.

The wells up in Divide I think we're running a slightly smaller number than that.

At our well costs and 400,000 barrels, these wells are very economic.

Clearly there are people putting larger reserve numbers on these wells than we and we hope they're right, but we don't have enough data to be able to project that out.

I guess I lied, but one last one.

Do you plan on continuing to run one or two rigs up there -- are you going to keep one in Divide County and one down in McKenzie?

Well, we won't always have one in Divide.

We're moving back and forth.

I think for right now we've drilled a number of wells in a row up there.

We'll be drilling -- I forget the exact well count, but we'll have a couple of rigs running in McKenzie in that area for awhile.

We have a significant simul-frac test coming up where we've drilled three wells--three long lateral wells and a 1280 and we're going to simul-frac those later this fall.

And we're getting all those wells lined up.

So, there's a period of time where our rate is not growing as much while we wait to simul-frac these wells and will have a big bump in rate later in the quarter.

Our people in billings who run that program have just performed marvelously over the last year and our rig efficiencies have improve dramatically and we're really proud of the costs that we're drilling these wells for and our results are really -- I think we've really demonstrated we can drill these over the past six months.

So, our plan is to keep two rigs in play and potentially in 2011 we may go higher.

And I hope we will.

Mike, this is a good example of where we're having excellent success and we want to maintain the rig fleet that we currently have because the efficiencies have dramatically improved and I think in this market the last thing you want to do is lay down rigs and crews and for that reason, matched with the success we're having, that's why we want to apply some additional capital on this play as well.

Your next question comes from the line of Derrick Whitfield with Canaccord.

You may proceed.

Hi, good morning, guys.

A few questions on the Eagle Ford and Bakken.

Jay, just to clarify on the restricted flow rate testing.

Was it limited EUR benefit or not enough, incrementally, you already justified the loss in PV?

Well, there are some cases where it looks like it has some benefit, but it's not material enough to justify limiting rates for long periods of time and I think that's probably the best characterization of it.

Okay.

And then your current completion recipe in Webb County.

How much stages do you guys currently pump and what is your early rate on the simul-frac test?

Well, we're getting really interesting results from the simul-frac [compiling] and we haven't--we're flowing the wells back now and so I don't have production data but the microseismic indicated we could push these closer together.

We didn't see a lot of overlap.

So, again, I think this play eventually goes to 80-acre spacing or something close that.

So, that's a huge uplift in potential reserves for us, if that works out, without spending more acreage money, which is really what we're chasing here.

And we want to find those things out early because that drives our infrastructure spending to be more efficient as we go forward.

In terms of what we're pumping we pump a lot of stages in Eagle Ford--say 17, 18 states' jobs.

17 states is very common and we pump a lot of fluid and that's sort of our recipe and so far what we've seen is that's the best recipe in our particular area.

Great.

And then on the Bakken, it appears that Johnson well came on as a fairly strong producer with only ten stages.

The rates there appears you're really generating similar productivity with less stages.

Do you attribute that productivity gain just though--or equivalent productivity through increased fluid pump alone and do you guys plan to stick with the strategy in both the Raven and [Bierden] areas?

We do believe that if you look at the correlation between productivity of the wells and a number of different variables that the strongest variable you can put on the chart that has the highest correlation coefficient is fluid volume.

Not stage count, necessarily.

We're not saying that stage count doesn't matter but we will say that it costs more money.

And so, in our way of looking at this, we wanted to try the high fluid at the same fluid volumes as the guys that are pumping these big stage counts again and see what results we got and we've had very positive results.

So,that doesn't mean we won't up our stage count some just to see "Hey, what happened now if we split this volume of fluid up into more stages?" Does that have some benefit?

In a way we're kind of doing a parametric look at this trying to understand--what really gains you the benefit here?

At the same time, trying to keep our costs down so our margins are what we want them to be.

But I think that's probably the easest way to characterize it.

We're not at all criticizing people who pump big jobs.

We think big is important.

We're just not 100% convinced that you need all of these stages that people are pumping.

Still learning in this play, Derek, so obviously if we can learn how to optimize completions from other operators we're certainly willing to do that.

And are you all three in the completion [study], all in Divide being in shallower [net] part of the Bakken?

I don't want to talk too much about specifics on what we're doing there but we have modified our pump rates some in Divide to try and improve our results.

And that's all I'll say on that.

Thanks, guys.

Thanks, Derrick.

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

You may proceed.

Morning.

It seems there is going to be a little bit of gap in the first of 2011 with the 70 to 80 million a day limitation.

At this point does it look like the answer is going to be restricting those wells or are there other outlets you think that will get you beyond that 80?

This is Javan again.

We're working really hard on exactly what that limitation is going to be month by month especially between now and mid-next summer when we see Kinder Morgan system coming in.

We're negotiating with a number of parties over additional capacity that would allow us to continue ramping our production.

We want to make sure that we get the very best economic terms possible for that.

We're not going to commit to large volumes in the first quarter on a deal that doesn't look economically attractive to us.

I think right now and this is, folks, why we're not announcing our 2011 capital right now, is because we're trying to understand what kind of deal we're going to be able to get to bridge that gap and how economic that will be and that will drive our rig count in the operated Eagle Ford which obviously is the largest single portion of our capital program.

So, we're working really hard on it, we're making some progress.

And we're talking to a number of parties about it.

Other than that, we really can't say a lot at this point about what the first half of 2011's going to look like.

Okay.

So I guess that's $30 million on the operated Eagle Ford shouldn't really be viewed as a run rate going into 2011?--I'm sorry, the $30 million increase in spending in the Eagle Ford?

No, I think--we're at two rigs right now, clearly to fill up the pipe in the second half, we need to be at a higher rig count and you will see us ramping rig count in 2011.

The question is, when do we to start ramping?

And, is it late this year?

Is it early next year?

Is it more toward mid-year?

Depending on what capacity we have beyond the $80 million and below the [200].

It really is that timing is just uncertain at this point and it does have a material impact on what we spend in total because it's such a big part of our program.

I hope we have--we're going to have resolution to this before I take the third quarter call and I think we'll be able to talk more succinctly about what our plan is to ramp in Eagle Ford and what our total expenditures for 2011 is going to look like at the third quarter call.

Okay, and with the acceleration is there any chance of you all going back to Kinder Morgan and trying to tie up even more capacity beyond that pipeline or is that probably set at the 200 level?

Well, again, I'm not going to talk specifics about our negotiations.

Kinder, obviously--Kinder and [Copen] have other people they're talking to as well.

And we have other people we're talking to.

So, one of the things we've said all along is that we want to have multiple outlets for our gas.

We don't want to be completely committed to one pipe for obvious reasons and looking for diversity for downstream take-away capacity.

That is a priority for us.

Other than that, I don't know that I can comment on our negotiations.

Okay, and one more if that's all right.

On the NGLs, can you just talk about your thoughts on what that situation's looking like.

Obviously ethane has been hit pretty hard this year but if you could talk a little bit about propane and the butanes and natural gasolines--where you might see those going.

And also have you and been seeing the processing plants running in ethane rejection mode yet in south Texas and, if so, what is that and the subsequent gas treatment due to the economics in the Eagle Ford?

This is Javan.

Obviously, that's a very large question.

I'm going to tackle it a little bit.

I'm very glad that in the way you asked the question that you recognize the fact that NGLs are not a monolithic product.

What they really are is a number of different hydrocarbon components, all of which end up in different markets and are used for different purposes.

The prices for components of the NGL stream are heavier than ethane.

Generally, are tied to crude prices pretty strongly.

And actually, if you look at that, that pricing is not far out of line with historical averages relative to crude oil.

If you look at NGLs other than ethane starting from, say, the heaviest, say, ten [tanes plus], then normal butane and isobutane and propane, The data I have here on the desk says that they're currently trading at about a 3% premium.

A 2% premium, a 6% premium, and a 9% discount to their average relationship with crude oil over the last five years.

And I would note that there's an active import/export market for all of those heavier products and there is significant amount of export occurring on them when prices get weak.

Our conclusion on that, propane's been hit a little bit recently just because of the tanking ethane's done and that's due mostly to some turn around in ethylene plants recently.

I think the conclusion on our heavier products other than ethane is that as long as crude prices remain at high levels we expect those prices to stay pretty strong.

You're right, the ethane market is different, as the only real use for ethane, apart from a part of the gas stream, is chemical feed stock for production of ethylene.

Recent prices for ethane are trading 26% below the five year average relative to crude oil price again, as a percentage of crude oil.

And actually, our lower relative to crude in the annual average for almost any time in the last 20 years.

Part of that as I said is due to turn around in ethane plants in this last quarter, as I said.

Which also had an impact on propane.

Ethane is historically the most volatile of all of the components and the value of that is typically regarded as being the gas price is the floor.

And as you mentioned it's more attractive economically to leave is in the gas in some cases and we elect to do that if we can do that through our contracts with gas processors.

There are a number of cases where you can't get that price because of contractual limitations you're not allowed to reject.

I can't talk about specific arrangements with have with our processors in our [growing place], in our Granit Wash, the Eagle Ford, where these numbers are really important due to confidentiality arrangements we have right now.

But let me walk you through an example so you can see how much variations in the price of ethane can have on our revenue streams.

For a typical well drilled in our Eagle Ford core area with a 40-barrel a million [kind of] condensate deal ethane is about 35% of the NGL product we sell and at current prices of about $0.46 per gallon it contributes about 12% of the gas revenue from a well.

Our calculations indicate that even if we were to give the ethane away for free our returns on that well would only drop by 4.5%.

I have to note in that we don't normally give people forward-looking returns because there's a lot of ways to mess with those.

They're very healthy rates of return, and a 4.5% reduction is not going to impede our program.

In general, we're not pessimistic about ethane prices moving much lower because we think low ethane prices will create demand for ethane and will allow that to prose above BTU parity with natural gas and replace other ethane feed stocks.

I refer you to a couple of articles in this a week's Oil and Gas Journal, which I think are very optimistic about potential demand for ethane and which talk about the North American advantage for production of ethylene and I think there are some good reasons to be optimistic that you'll see expanded ethylene production using ethane.

However, NGLs are a big part of our Business and our cash flow and our future and we do actively hedge these components.

There's a good market for doing that out in a couple years.

After that it gets thin and trades at bigger discounts to oil than it should relative to the front part of the curb.

So we don't go out too far.

You can see all our hedging in the queue.

I'm not aware of anybody in south Texas that's rejecting ethane right now.

The agreements that we do, some of them allow you to reject, some don't.

Again, we want to have some diversity in our contracts and we will have some that will and some that won't.

Typically you like to have that ability to reject if you can but generally you're going to have to give something to get that.

I guess that's pretty lengthy --

That's perfect.

I appreciate the detail.

Thanks so much, guys in.

Thanks.

Your next question comes from the line of Rhett Bruno with Bank of America - Merrill Lynch.

You may proceed.

Hey, guys.

Good morning.

In the Bakken, could you give me a rough breakdown of the acreage split between Raven, [Baredan] and Gooseneck?

Yes, this is Javan again.

Raven's about 30,

Let me double-check that.

We're going to check the numbers.

Raven's about 30,000 if I remember the numbers right.

Okay and maybe while you're looking that up.

On the non operated mid stream side in Eagle Ford do you quantify what the incremental spending or what your total spending this year is expected to be?

Where was that again?

On the non operated mid stream buildout?

Yes, I think our non operated Eagle Ford is going to be something around $20 million.

The last number I saw.

Okay and is there a rule of thumb, not that you guys plan to doing this, but is there a rule of thumb for gauging potential penalties if you guys were to go non consent on any of that drilling?

Well, in general you're going to lose participation in the well.

In some cases you will lose participation in additional acres associated with that and generally our intent is to participate in all of these wells.

But in a lot of cases you'll just lose the well or a minimal amount of surrounding acreage.

There are cases you could learn substantial amount of acres.

We don't anticipate not participating in wells at Anadarko.

Get back to your earlier question.

If you asked for a breakdown in Raven, Baredan, and Divide.

Raven is about 36,000 acres.

Baredan's about 17.

The Divide area is 25,000 acres.

25?

Yes.

Does that add up right?

We rounded off a little built.

That's fine.

Those are ballpark.

Okay, great, thanks.

Your next question comes from the line of Jack Aydin with Keybanc.

You may proceed.

Hey, guys.

Couple of questions.

A, for 2011 do you have an idea of how many rigs you might want to have?

Well, Jack, this is Javan again.

We haven't put out a forecast yet, I think general census is going to be up from where we are today.

Probably on a ramp consistent with the kind of ramp we're showing in the second half.

Again, it's very dependent on our infrastructure, how much infrastructure we're able to secure in the first half in the Eagle Ford.

We don't want to end up with a bunch of wells drilled that we can't produce or have to restrict too much.

That's really -- because that's such a large part of our program, we really need to get some definition around that before we get too specific about 2011.

Generally it's going to go up some.

Not hugely.

But some from where we're at.

This is Tony.

One of the things you'll see directionally from SM Energy is we'll be talking more about our capital guidance earlier this year than we typically would and primarily because with our significant resource plays we now have a more consistent inventory and ability to kind of predict and forecast what our program will look like.

So directionally I would say you'll be seeing that sometime around the next call and instead of waiting until December, each year to get the guidance, you'll be hearing from us early about our 2011 plans.

Second question, how much more acres would you like to have in the Niobrara?

Have you got a bunch in your pocket, Jack?

No, I mean sure, if I had, I would be in Denver area.

I guess you would.

Jack, this is Javan again.

Obviously, we would love to have had a larger position than Niobrara.

Our strategy is to try to enter early at low cost and when acreage starts to expensive we typically try to stop leasing and do with what we have.

The Niobrara for one reason or another went wild a lot faster than -- well, faster than any play I've been involved in, just on the release of some data got out and acreage costs just rocketed up and prevented us from buying more acreage than we did.

In retrospect you always kick yourself about, "Well, maybe we should have been more aggressive early on." We just didn't anticipate how fast things would heat up.

At this point the acre village pretty darn expensive and it's probably not something we're not spending lot of time attempting to buy expensive acreage in any play.

I'm looking at your capital budget.

I know that [other drilling] you have about [110 million].

Would you consider other drilling which haven't been named.

[Nemcore] that you might be consider selling to finance your capital budget going forward?

Jack, based on the growth and quality of our portfolio now, we're going to have a lot of optionality going forward.

Take a look at areas to potentially core up and areas where it may make more sense to look at generating funds from proceeds if we're elected to do a JV or selldown or sellout.

Very similar to what we did in Canada with our sharing and earning agreement but we now have a lot of currency relative to the plays we have in inventory.

So I think what you'll see going forward is opportunity for us to look at those where we see significant value, from maybe looking at [selling] out some of those particular positions.

It's just good right now to have a lot of that optionality we didn't have a short time ago.

Final question.

What level of debt-to-total cap you feel comfortable with?

Right now 19.

What would you ideally like to stay around.

Jack, this is Wade.

From a debt-to-cap standpoint I would change the question a little bit.

I would look at debt to EBITDA first.

I would feel comfortable to taking it up to two times--if you want to think in that direction.

On the debt to book cap side keeping that below 40% would always be a goal I think.

Thanks a lot.

Thanks, Jack.

Your next question comes from the line of Kristal Choy with Raymond James.

You may proceed.

Good morning.

On the Niobrara well, trying to analyze the decline here.

It seems a bit steep.

And obviously it's just the first well.

But what have you seen so far geologically with regard to the fractures especially since the well was producing while drilling and what are you thinking in terms of completion on your next wells?

Well we're pretty happy with how that well looks compared to some of the silo wells to the north that were completed over the -- the horizontal well up there -- I think it's performing very well.

Obviously our concern in this whole area is can we stimulate the matrix in between the large natural fractures.

We think we did.

We're continuing to look at that and figuring out how to do better.

We're pretty happy with the well.

It's doing better than our type curve for the wells and we're pretty satisfied with it.

Otherwise we probably wouldn't be talking about it too much at this point.

I think it's a little early but I think the frac technique we used on this well will probably be very similar in the next one but with we are learning from it.

We have done some blogging and additional work.

We daily microseismic to look at how we think we can improve it but I think the well can [accume] something similar to what you'll see to other operators in the Niobrara.

Pretty encouraged.

Okay.

And switching over to the Granite Wash, Jay, how extensive do you think the Marmaton B is across Mayfield and have you identified other targets there this year?

Horizontal targets.

We've done a lot of work.

Part of the reason we're focusing our efforts right there in the Mayfield area is that's where we really started our geologic work and we've done an extensive look there where there's a number of vertical penetrations in the area and extensively mapped.

We have a good sense of where the Marmaton B can be productive.

I can tell you there are also some very nice looking Marmaton intervals that we'll be drilling.

We have a lot of locations, and part of the reason we're stepping our rig count up here is if you start to look at how much value you can create by accelerating the program it's really compelling when you're borrowing money at 2% or whatever our debt number is right now.

I think we have a lot of locations to drill.

We're really excited about it.

I think you can anticipate us continuing to ramp up that rig count into 2011.

And do you have an acreage breakout between Mayfield and Stiles Ranch?

The Stiles Ranch isn't a lot.

You're talking about a couple, three sections there with interest.

Mayfield is a pretty big chunk.

Our total acreage position is about 34,000 acres net.

Again all of which is essentially [HBP] but what you have to look in the Granite Wash you have multiple pays so you can start multiplying that acreage count by multiples of well count.

About 20,000 of that.

We have quite a bit.

If you start to move down and towards the east area we call 66, we have a lot of acres down that way and we're still doing the mapping down there.

We haven't gotten a full -- we don't have a total location count yet but it's a big number.

Great, thanks a lot.

Thanks, crystal.

Your next question comes from the line of Joe Allman with JP Morgan.

You may proceed.

Thank you.

Good morning, everybody.

Good morning, Joe.

Back to the spending question.

If you were to run spending at the same rate in 2011 that you're running in the third and fourth quarters or higher, how -- I know you talked about the ability to access debt.

Would you cover the shortfall primarily with debt or would you be looking to drop or reduce activity in some areas, sell assets, raise equity?

Can you talk through the different options and how would you prioritize those options?

This is Wade, Joe.

I would kind of reiterate some things we said earlier that we are going through that process right now looking at '11 and beyond and included in that exercise is looking at our portfolio and the optionality we have and what potential optimization is there.

The balance sheet, again, has a lot of room to leverage to.

I think that is clearly an option.

I think using equity would definitely be last on the list and I don't foresee a need for that.

We're going through the exercise now and we will be giving you more guidance this year.

I think on the leverage side, we talked about the revolver being undrawn and that borrowing base should grow with success and the reserves growing and clearly the high yield market is wide open.

I think we have a lot of options.

I know we have a lot of options we're looking at now.

Looking into 2011 and the other thing is what is the production growth going to be out of the success we're having and cash flows we're going to be generating.

Thanks.

In the Woodford shale.

What are you doing there now?

We're basically -- this is Javan -- we're doing what we had budgeted.

We had one to two rigs budgeted for the year.

Basically in an acreage-holding kind of mode there.

So we're just continuing that program out.

It's included in our other drilling piece there so we have -- we're actually drilling a number of wells in one section to simul-frac them later on.

We think the Woodford is one of the most misunderstood assets in the shale plays.

We think it's actually pretty economic if you look at our [F & D] with our results recently.

Our reserve numbers are better.

The costs are lower in the Woodford than they are in most of the other shale places because it's not so hyped up and we see pretty good results there and so we're continuing to chip away at it.

It's a really good low-cost option on gas prices, and we expect to be in Woodford for a while.

As Tony and Wade have both indicated we're going to be looking at our portfolio very closely to understand which pieces fit, which pieces we can use to fund our programs going forward, and clearly the dry gas portion of the portfolio is something you have to look hard at now.

Have to add the drilling we're doing on the Woodford now meets our economic hurdle even at current pricing.

So we're pretty focused with a kind a minimal program.

It's very economic and meets our hurdles.

That's helpful.

In terms of -- Jay, in the Niobrara, did you talk about that first of all because you're not buying any acreage and no need to not disclose stuff for competitive reasons?

Generally, yes, that's right.

We have not been successful in adding materially to the position we had at what we think is a reasonable cost and once we get to that point we'll be happy to talk to you about our expiration results.

Unless you've got acreage in your pockets Joe that we can get at a decent --

No, I'm not as wealthy as Jack, so sorry about that.

Lastly, in the [Marcelle] shale I think you have to drill 60 wells by 2012?

Can you talk about how you're going to go about ramping that up and the capital required there?

Well, there are some substantial commitments to 2012 and we're looking hard at that.

That's a big factor in our 2011 capital exercise.

I think that's one of the big considerations for us in how we operate a portfolio and how we manage this going forward.

I don't have a plan to layout in front of you today on how we're going to do that but it is a significant consideration in the process.

Very helpful, thanks, everybody.

The last question comes from the line of Scott Hanold with RBC Capital.

You may proceed.

Thanks.

If I could ask one Niobrara question.

I know if you look at the Legacy horizontal walls being drilled through in that area where you all had yours.

Some of those were drilled a good 10 to 15 years ago that have already accumed 250,000 to 300,000 in [BUE] Are you aware of how they completed those wells versus what you're doing now?

When you look at the outlooks, do you think it can be pretty competitive with some of those wells?

If you look at the average horizontal well drilled at the Silo Field.

What you're doing is picking out some of the good ones.

There were some that weren't so good as well and the average EUR we forecast in an unsimulated well lateral in that area is below 100,000 barrels to my recollection.

There were some exceptional wells in that bunch that we think were highly naturally fractured and contributed a lot.

We studied those extensively before we fraced our well and tried learn as much as we possibly could from them.

We did some unique things in fracturing our well as a result of the study.

I'm not going to talk about what we did because I think there's some things with did that I think are important in our material that were different.

But yes, we looked at all of the offset wells and all of their performance and understood those very well before we started our work.

So the differentiator between the good and bad well is kind of what I'm trying to get at is how naturally fractured that specific area is there and that much variance within I guess that relatively small area that you've got to be very selective about your locations.

How do you set your drilling program around that?

Well I think what your pointing out is in an area where you go into just drill naturally fractured rock in essentially unstimulated way you're going to get wide variation in results because of the amount of fracturing you've going to have.

The question is can you stimulate the rock?

And if you can do that successfully, then you can go into areas that have less natural fracturing and make good wells.

And really that's the story in that particular area.

I'm not trying to speak for the entire Niobrara because I think it's a lot more complicated then people think it is about what is going to be the sweet spots and what drives that but in the particular area we're operating in we think natural fracturing is a very important factor and your ability to get the rock in between those fractures to contribute we think is going to be really important to making the play extensive.

I think it's clear from the Silo results that if you get into good fractures can you can make a well.

The question is what about the areas where the fractures aren't so good and how can you increase your chance of making repeatable good well and that's all about the stimulation.

We think we've learned a lot.

We studied a lot.

To be honest I think we have a certain amount of expertise on this because we've spent a lot of time on it.

I'm not saying that works everywhere from the Niobrara.

We haven't studied everywhere in the Niobrara and other operators may have might different views on that in their areas

I'm going to hit on the CAPEX again.

It seems like it's been the topic du jour this morning.

When you look at leaseholding over the next couple of years, is there any specific area that it's pretty low where some activity there is clearly a decision that you all can make right now not to drill?

Well clearly we could slowdown the Woodford extensively.

If we could chose to do that we could stop.

The Granite Wash we could stop drilling.

It's all [HPV'ed] If we chose to do so, it would be foolish to do that but we would do that.

We could maintain a two-rig program in the Eagle Ford for another year if we chose to do that.

We don't have really big lease obligations down there that drive us to expand in our rig count.

All of our Bakken leases are relatively new.

We can pace that out.

The big lease-holding commitments to us are really the Haynesville and [Marcellus] and those are things we have to deal with.

The rest is we are drilling it because we want to drill it and the returns are really high and it make a whole lot of sense to accelerate activity and I think over the next six months you'll see us deal with all of these issues.

I think you called the Woodford an option on gas but it doesn't sound like you need to be.

How much of the other drilling is being spent on the Woodford and why not just stop there?

Part of it is because it's economic at current levels and we look at that and say we want to keep a rig up, keep our efficiencies up, keep our people working.

It's not completely about lease holding.

I think we had to drill eight wells there over the year this year and next year in order to hold all of our leases together.

There's some leaseholding we want to do and we would like to do that.

We could probably ratchet activity back a touch in the Woodford some more if we elected to do it, but it's economic right now.

So that's the judgment call but I think if you really look at it from a big picture standpoint where are the big issues we need to deal with.

We've got to deal with the fact we've got the big obligations in Haynesville and Marcellus and we need to make sure those programs are going to carry their weight.

Okay and just so I got the numbers right you all spent about what $300 million in the first half of the year so [871] would imply somewhere around $550 yes, I think that math is correct.

And then again keeping that budget going and in '11 if you're looking at about $1 billion or so dollars of CAPEX, then?

Assuming the same portfolio is maintained and we continue at a relatively comfortable pace.

Fair enough, appreciate it, thanks.

All right, Scott.

Thanks.

Thank you.

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

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

Tony Best for any closing remarks.

You may proceed.

As you've all heard we've had have a very strong and positive first half for 2010 and we expect to continue to deliver on that high level of performance through the rest of this year.

Thank you operator and thanks for everyone for your interest in SM Energy.

We'll talk to you again next quarter.

Thank you.

Ladies and gentlemen, that concludes today's conference.

Thank you for your participation.

You may now disconnect and have a great day