SM Energy Co (SM) 2010 Q4 法說會逐字稿

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

My name is Deanna, and I'll be the operator for today.

At this time, all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

(Operator Instructions) As a reminder, today's conference is being recorded for replay purposes.

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

Brent Collins, Director, Investor Relations.

Please proceed.

Thank you, Deanna.

Good morning to all of you joining us by phone and online for SM Energy Company's fourth quarter and full year 2010 earnings conference call.

Before we start, I'd 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 discussion of these risks, be sure to refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the risk factors section in our Form 10-K that will be filed later today.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance, reconciliations of those measures to most directly comparable GAAP measures, and other information about those non-GAAP metrics are described in our earnings press release from yesterday.

Additionally, we may use the terms probable, possible, 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; David Copeland, our new Senior Vice President and General Counsel; and Brett Collins, Director of Investor Relations.

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

Good morning, and thank you for joining us for our fourth quarter and full year 2010 earnings call.

After a few 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 yesterday, we have a presentation available on our website that we'll be referring to during the call this morning.

I am going to start on slide three, where I will address highlights for today's call.

Before we dive into the review of the quarter and our operational review, I want to take a few minutes to discuss 2010 as a whole.

Last year was a breakout year for SM Energy.

For the full year, we had record net income both in absolute terms and on a per diluted share basis.

We had near-record production for the year, with average daily production over 300 million cubic feet equivalent per day.

As a reminder, we sold a number of packages of non-core assets during the year which, if we had kept, would have allowed us to set a production record last year.

Proved reserves for the year grew 27% to 985 Bcf equivalent.

Again, had we not divested a number of properties, we potentially could have set a high mark for proved reserves last year as well.

We grew our proved reserve base while growing our PUD percentage from 18% to 30%, which is still below the peer group average.

Our drilling reserve replacement, excluding revisions, for 2010 was nearly 350%.

Drilling F&D for the year, which again excludes revisions, came in at $2.14 per Mcf equivalent, which is a significant improvement over 2009 and continues our positive trend over the last four years, as indicated on the graph on slide three.

We think this metric is an important one to focus on as a resource play company, since it shows how effective we are at adding reserves through the drill bit.

I think our 2010 results stack up well with what we're seeing in the industry, and our transformation over the past two years now has us well on our way in becoming a top performing resource play company.

Moving onto slide four, some operational highlights for the year include the following.

We significantly advanced our Eagle Ford shale program during the year, particularly the portion of the play that we operate.

We improved our understanding of the geology across our operated 165,000 net acre position, which helped us gain an understanding of where we are positioned in the oil, rich gas, and dry gas windows of the play.

As a result, we entered into a number of commitments throughout 2010 to secure most take away capacity, as well as drilling and completion services, that will allow us to continue to increase our pace of development in the play.

In the Williston Basin, we were successful in our test of acreage further West of the majority of the industry's Bakken and Three Forks activity during the year.

Several initiatives, like our retained energy frac stimulations, helped us to better understand the reservoir characteristics of the play and lower our spacing assumptions for future development.

In our Haynesville Shale program, we entered into a successful agreement that allowed us to drill and hold acreage that has both Haynesville and Bossier Shale potential, while expending very little of our own capital.

Our results have been highly encouraging, as we have had a string of wells recently with solid production rates, unrestricted chokes, with high pressures.

I look back at this transaction as a highlight, given that it allowed us to preserve what I think will be a valuable acreage position for the Company in both the Haynesville and Bossier intervals, while still maintaining discipline with our capital program.

In 2010, we tested a number of wells in the Granite Wash formation in western Oklahoma and the Texas Panhandle.

Our acreages in this area -- our acreage in this area is all held by production, so we are working deliberately to ensure we understand the drivers and the risks associated with all of the various stack pays in this hydrocarbon province.

We were also an early tester of horizontal drilling in the Niobrara in southeastern Wyoming during the year.

Lastly, we actively began testing the potential of 20-acre down spacing in our Wolfberry tight oil program in the Permian Basin.

The last year in review item I wanted to touch on was the rebranding of the Company.

As many of you know, we changed our name to SM Energy last June, following our stockholders meeting.

After 100 years of doing business as St.

Mary, we decided that it was time for a change, given our new strategic direction as a resource play-focused company and the national breadth of our portfolio.

Our new name is instantly identifiable with our ticker symbol while honoring our history and legacy as St.

Mary Land and Exploration Company.

As I mentioned a moment ago, I believe that last year truly was a transformational year for the Company.

We performed very well against the business plan, achieving almost every quantitative and qualitative target we established for last year.

I believe the investment community is beginning to take note of what we're doing, and our goal is to continue to maximize value for our stockholders through top tier project execution applied to our high quality portfolio.

With that I will turn the call over to Wade for the financial review.

Thanks, Tony.

Good morning.

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

I will touch briefly on some of the more important aspects of yesterday's announcement, and I am going to start on slide six.

Many of you are aware we announced fourth quarter production in late January, ahead of our bond offering.

At that time, we announced production of 31.7 Bcf equivalent, or an average daily production rate of 344.4 million MMCFE per day.

Slide six shows our production results for the past year and a half.

The trends are obviously good, up and to the right.

The only thing I would point out is that our natural gas growth is being driven by rich gas production in plays like the Eagle Ford.

From a financial perspective, SM Energy performed well this year, and the fourth quarter results were outstanding.

Consistent with prior quarters of 2010, we rounded out the year executing very well on our business plan.

We came in over our guidance for production, and most of our financial results were better than we had guided for the quarter.

Our production increases come predominantly from the Eagle Ford and Bakken/Three Forks development.

Production in the Eagle Ford increased over 50% each quarter of 2010 sequentially.

The Bakken/Three Forks production saw a large bump the last two quarters of 2010 and continue to focus on oil and rich gas production.

And as you can see, the strategy is paying off.

Moving to slide seven, we'll quickly touch on how results compared to guidance.

Again, production for the quarter was 344.4 million cubic feet equivalent per day, which was higher than our guidance of 305 million cubic feet to 330 million cubic feet.

Consistent with recent quarters, our Eagle Ford Shale program, both operated and non-operated, was the primary driver behind this.

And Jay has some detailed slides later that emphasize this point.

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

On LOE, our cost per Mcf equivalent was $1.06, which was below our guidance range of $1.15 to $1.20.

Stronger than anticipated production was the primary driver for our out performance on an Mcfe basis.

Total G&A came in at $1.00 per Mcf equivalent, which was slightly higher than the $0.88 to $0.96 we had guided on.

Cash G&A drove the increase, coming in at $0.73 per Mcfe versus guidance of $0.54 to $0.58.

The variance from guidance reflects a full-year true-up to the Company's short-term incentive compensation accrual, as a result of the Company meeting or exceeding the majority of its targets for the year.

G&A cash NPP was $0.11 per Mcf equivalent, well under our guided range of $0.16 to $0.18.

Lower commodity prices realized during the quarter resulted in lower net profit payments for this legacy program.

Non-cash G&A was also slightly below guidance, largely due to better than expected production.

The Company was in line on other items that we provided guidance on.

As far as other notable items for the quarter, we had a gain from divesture activities of $23.1 million, related primarily to our divesture of non-core PDP properties in the Permian region, which closed in December.

We reported net income for the quarter of $37.1 million or $0.57 per diluted share, adjusted net income for the quarter which adjusts for items that affect comparability, such as one-time or infrequent items, or items whose timing and/or amount cannot be reasonably estimated, was $29.7 million or $0.46 per diluted share, which is higher than Wall Street consensus.

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

Cash flow from operating activities was $78.7 million for the quarter.

Operating cash flow for the quarter was $176.4 million or $2.72 per diluted share, which also beat Wall Street consensus numbers.

Slide eight summarizes our financial position at the end of the year.

On December 31, our debt to book cap was 21%.

Pro forma for the $350 million senior unsecured note offering that closed on February 7, our debt to book cap would be around 34%.

But even after the offering, our credit statistics are still some of the strongest in our peer group.

So speaking of the high-yield offering, now on slide nine, which provides the summary terms of our recently completed bond offering.

Based on the significant demand we experienced, we were able to increase the size of the offering to $350 million, compared to the $250 million originally contemplated at the time we launched the deal.

We feel great about the coupon rate that we were able to get, 6.625%.

I believe that's the lowest coupon achieved for a first-time energy issuer in the last two years.

Finally, moving to slide 10, our liquidity position stands at almost $1 billion, adjusted for the offering.

The proceeds from the offering are going to be used to fund a portion of our 2011 capital program.

With respect to our credit facility, our commitment amount from the bank group was not impacted by our high-yield offering.

However, our borrowing base was reduced by 25% of the total note offering amount, so our borrowing base went from $1.1 billion down to $1 billion.

I can tell you sitting here today the revolver is undrawn, and we have about $250 million of cash available.

I will also note a summary of our hedging position is included in the appendix of the presentation for today's call, and the details will be provided in the 10-K, which will be filed this afternoon.

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

Thank you, Wade.

Good morning, everyone.

Since this is a year-end call, we decided to provide a summarized overview of our current asset base, which is shown on slide 12.

I won't go through each of these boxes, but I think it is a great reference slide for investors, as it shows the footprint of our organization, as well as the contribution of the various regions and the plays we're focusing on in each region.

If you think of the Rocky Mountain and Permian regions as oil dominated, the South Texas and Gulf Coast region as rich gas and condensate, and then the Mid-Continent and ArkLaTex regions as largely dry gas areas, you get a sense of how balanced the Company is when it comes to its product mix and reserves.

I am not going to talk much about our year-end proved reserves today, since that information was released last month ahead of our high-yield offering.

Tony mentioned earlier that our drilling F&D came in at $2.14 per Mcfe, and our drilling reserve replacement was 349%.

These numbers are part of an improving trend of drilling performance here at SM Energy.

Although we optimize our project selection at a corporate level based on investment efficiency, there is good reason to be proud of our performance through the drill bit in each of our operating regions this past year.

All five of our regions replaced their production with new reserves, with four out of the five having more than 200% drilling reserve replacement.

Our South Texas and Gulf Coast region had a drilling reserve replacement percentage in excess of 800%.

The Eagle Ford is obviously driving this performance, and it demonstrates the tremendous growth engine that resource plays can provide.

That's a good segway to move to slide 13.

We currently have 250,000 net acres in the Eagle Ford shale play, which we believe makes us the most levered public company to the Eagle Ford shale on a per share basis.

This slide does a very good job of showing that the bulk of our acreage position sits in the high-value portions of the play.

I am moving to slide 14, which summarizes our operated Eagle Ford program.

As we reported a month ago in our January release, we had a very strong fourth quarter on the production front.

For much of the second half of 2010, we were bumping up against gas off take infrastructure constraints, and we were limited on how much rich gas we could move.

We saw improvements on this front in the fourth quarter, which is evident from the ramp-up in production that you can see in the lower right-hand corner of the slide.

As we have previously indicated, we expect to have even more rich gas off take capacity available to us in the second quarter of 2011.

I should note that we have also made recent commitments to some oil pipeline infrastructure, which should start up in the May time frame and will reduce the amount of trucking we are currently having to do to get our oil to market.

In general, there is a lot of activity going on right now in the area to bring additional oil infrastructure into the play.

And we're active in discussions with several parties to secure downstream oil pipeline space, which will support our continuing growth.

With respect to our 2011 plan, we are right on track to ramp up our rig count to six operated drilling rigs by the end of the year.

We will actually have a third rig in the play in the next week or so.

We have the majority of the drilling and completion services we will need this year and next committed at this point.

Our drilling performance in the Eagle Ford continues to improve.

We've made steady improvements in our drilling times.

For example, in the Galvan area, which is in the southern portion of our acreage, from the first quarter of 2010 to the fourth quarter, we were able to reduce our drilling time per thousand feet drilled from 32 hours to 24 hours, a 25% improvement.

Now that we've delineated our acreage, we're beginning to implement pad drilling, which will reduce our rig move times and further increase our efficiency.

We have several down spacing and retained energy frac pilots planned for this year as well, which should tell us a lot about the ultimate spacing for wells that we need to be assuming in our development plan.

All in all, it is a very exciting time for us.

Moving on to slide 15, I will now spend a couple of moments discussing our non-operated Eagle Ford program.

As we reported a month ago, production from this program grew significantly in the fourth quarter of 2010.

For 2011, we anticipate that Anadarko is going to ramp up to 10 drilling rigs.

In fact, we believe they will hit 10 rigs by the end of the first quarter.

APC announced yesterday that they are close to inking a further joint venture or farm down on their portion of our shared acreage, though there is a chance the level of activity we are currently assuming could change.

We are moving along quickly on our own plan to sell down a portion of our Eagle Ford position, which I will comment further on a little later.

Moving onto slide 16, I would like to briefly touch on our profitable Bakken/Three Forks program.

We currently have two drilling rigs operating in the Williston Basin.

A third rig should arrive in the second quarter of 2011.

We were able to increase our acreage position in prospective portions of North Dakota to approximately 85,000 net acres during 2010, up from the previously reported 81,000 net acres.

In general, our 2010 drilling program exceeded our budget expectations for both rate and reserves efficiency, which is remarkable, considering the cost inflation in the basin.

On slide 17, you will see our capital update and planning for 2011.

There have been no changes from our original capital budget plan that we released in late December.

I do want to note that over 90% of our drilling capital for 2011 is being invested in liquids and high-BTU gas projects.

Moving onto slide 18, there is a brief synopsis of our recent or ongoing transaction efforts.

We sold certain non-strategic PDP properties in the Rockies region in early 2011 for approximately $44 million.

Our marketing effort for our Marcellus assets has not yet resulted in us receiving a cash offer that we consider to be acceptable.

We're continuing to discuss potential joint venture or divesture arrangements with interested parties.

Our hope is to monetize all or a portion of these assets.

However, if these talks do not yield a satisfactory result, we will need to spend roughly $20 million in 2011 to maintain our leasehold position.

As I mentioned before, we are currently marketing some of our Eagle Ford acreage.

The data room opened this week.

If we complete this sale, we anticipate that we will reduce our total position in the Eagle Ford shale by approximately 20% to 30%.

It is clear at this point that the package is going to attract a lot of interest.

We are optimistic about our chances of obtaining a deal in the second quarter which, combined with our current liquidity, will put us in great shape to participate in non-op wells and optimize our operated development program.

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

Thanks, Jay.

Moving to slide 19, I would like to leave you with some key take aways from our call today.

We finished last year with a very strong fourth quarter, which included record quarterly production, largely due to our Eagle Ford shale program.

2010 was an excellent year for SM Energy.

We had solid financial execution with strong performance versus guidance, and we saw robust growth in both production and reserves.

I believe we're well positioned entering 2011.

Our financial position is in fantastic shape following our very successful high-yield offering, and we're also excited about our high-quality portfolio of resource plays that we've built as part of our strategic transformation.

We plan to focus our efforts for continued growth and success in these liquid-rich programs in 2011.

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

(Operator Instructions) The first question will come from the line of David Tameron, Wells Fargo.

Good morning, everybody.

Congrats, Tony and Jay, on a great year.

Good morning, David.

In the Eagle Ford have you -- before you said it could be a combination of operated, non-op position.

Have you decided yet what that package looks like and are you willing to tell us?

Sure.

Yes, David, this is Jay.

The package as we are marketing it -- if you look at our gross position in the Eagle Ford, we have a half a million acres gross, 250,000 net, and what we are marketing is a 15% working interest position, roughly.

It may be smaller than that, depending on how the deal actually works out, but this is the kind of base case.

It is about a 15% working interest position in that entire half a million acres.

Okay?

So the way that would end up working out, we have roughly a 25% working interest in the non-op and 100% working interest in our operated acres.

So the way it would end up working out is we would end up on our operated position with about an 85% working interest after this deal.

We would end up selling down our non-operated position from about 25% down to 10%.

So again, the buyer would be buying a 15% working interest in this whole half million acres gross.

That accomplishes a couple of great things for us.

First of all, I think from a buyer's perspective, it is very attractive because you get a very broad exposure in a great part of the play and two good operators, both Anadarko and ourselves.

From our perspective, it sells down somewhat disproportionately the non-op, which puts us more in control of our capital spend.

I would also note that some of the very best areas of the Anadarko-operated acreage, we actually have slightly higher than a 25% working interest position.

We have 50% in some areas, 30s in some areas, so we actually think it leaves us in a position where we actually have a higher interest in some of the very best portions of the non-op acres.

Clearly, it puts us in a better position to manage our capital program, and so I think it accomplishes a number of good things for us.

That's sort of the base case we're going with right now.

Okay.

And JV or straight sale or just --

You know, it is hard to know the difference between a JV and a straight sale.

We're looking for a large carry.

Okay.

So that's really how we'll structure it.

Okay.

All right.

And then jumping over to the Niobrara, the second well you talked about drilling in, I guess it was in the third quarter you talked about it.

Is there any update there?

This is Jay again.

Yes, I'll be happy to -- let's talk about the Niobrara a little bit.

I think it is a great play, but people -- again, as we've talked about over the last few calls, I think it is variable, and you have to start as we start looking at it, you have to say what really makes this productive.

With our second well we were intentionally testing an area which on our maps had lower resistivities, and the well is not a good as well as our first well.

It IPed about 300 barrels a day.

Today, it is making about 100 barrels a day.

It is actually holding in a little better than we thought.

It's kind of flattened out.

But it clearly is not as good a well as the first well we drilled, which was in a much higher resistivity area.

And frankly, I think a lot of that is driven by fracture.

So as we've looked at the acreage, we have -- a very high percentage of our acreage is in the higher resistivity areas, but it has allowed us to essentially hydrate a few locations out of our potential program as a result.

And we frankly have not been pursuing acreage in some of the lower resistivity areas.

If you start to look at some of the wells that have been drilled that aren't so good, we think we understand why.

I think it is important as you look at all these plays, and I will throw the Granite Wash into this as well.

You have seen some mixed results recently or some changing estimates coming out of the Granite Wash.

These plays are not the same as, say, this great Eagle Ford play we're in, where almost every well we drill looks really good.

And we have been deliberately cautious about this as a result.

We're trying to test these areas, trying to understand them.

It's not as easy as some of these more ubiquitous looking shale plays.

I think the Granite Wash is a great example of that.

We have been very cautious about that.

We're testing multiple intervals.

We've addressed it, I think, as more of an exploration effort.

Same thing is true in the Niobrara.

We will be drilling another Niobrara well here shortly, and we have some more activity planned, but we clearly tried to take a more exploration-oriented approach to this, which we think is appropriate.

So that's the second well.

Okay.

I would love to tell you that every well we drill up there is going to be great.

That one, I think, we really tested the edge and got what, frankly, sort of what we expected.

So we'll be backing up and going back into the higher resistivity portions of the play.

That's fine.

That's consistent with what other operators are saying.

Last question, Eagle Ford.

Can you just talk about what you -- the wells have you on line, are they holding up, and how did the reserve engineers treat you at year-end as far as -- if you want to give us numbers, fine -- but what you thought you were going to get versus what they gave you?

Can you just talk about how you looked at that year-end reserve reporting for wells?

Yes, this is Jay again.

In general, we're going to focus on 1P reserves here, not on our 3P reserves.

Okay.

That's fine.

We -- the 1P numbers were up somewhat from what they were last year.

Again, this is just kind of the evolution of -- you get a little more data and you can book a little more aggressively.

And in general, we were very close to our reserves consultants.

We use Ryder Scott.

They were very comfortable with what we booked.

No question that in large areas of the play, we expect our reserve numbers to be much higher eventually, but in general we only booked about one PUD per well drilled.

Some of that was some netting.

We took off some PUDs in the far south portion of the play where -- in the dry gas area, where our higher costs just don't make those wells economic.

We booked more in the rich gas portions of the play.

But I think we're fairly -- we're pretty conservatively booked.

Clearly, I think as you start to look at the results, both from us, Anadarko, Rosetta, there's some areas of the play that we have nice positions in that are just tremendous.

I mean, it is hard to say it any other way, and we would expect our reserve bookings in those areas to increase significantly over time.

But I think we're appropriately booked, given the data we have right now.

I would also note that we are a two-stream booker.

We book -- at this point, we're booking wet gas and NGL -- wet gas and crude, which impacts, if you're making comparisons between us and some other people, and we're booking -- it makes us look like we have smaller reserve numbers booked.

You have to add the value of the reserves associated with the NGLs into that to get a truly comparable number, so that's something we're considering this next year.

All right.

I will let somebody else jump on.

Thanks for the answers.

Sure, Dave.

The next question will come from the line of [Wellen] Fitzpatrick, Johnson Rice.

Good morning.

Good morning, Welles.

If I remember correctly, you guys had a 80-acre spacing well pair on deck in November.

Can you guys give us an update as to the progress on that or how those are producing?

Welles, I assume you're referring to the Eagle Ford, is that right?

Yes, sorry.

We have done a couple different down spacing pilots.

We did a pair in Galvan.

Both wells are very, very strong wells.

We did a three-well retained energy frac over -- more to the west recently, which we really don't have final results on yet, so I am not sure I can help you much on that one.

We're still looking at it.

The three wells all look good, but whether they really -- we'll see what the depletion looks like over time in them.

But I think we're -- you hear some of our competitors talking about -- I know Anadarko talks about 1,000-foot spacing going to 500-foot spacing.

Our development plan right now is based on 1,250-foot spacing, which is roughly 100 -- if you think about that in terms of 120-acres.

We're going to look at some 620 -- we're going to look at 625-acre or foot spacing, which is sort of a 60-acre look, and we have several more tests of that this year.

So I think it is a little early to judge, but I think in some of the higher reserve areas of the play, there is some real good reason to be confident that you're going to be able to get to lower spacing.

All right.

And on slide 14, is it still safe to assume that around 40% of that gas production is NGLs on a post-processing basis?

40%?

Brent, is that a reasonable assumption?

I never look at it on that kind of way.

It is a big number.

It is 1,250 BTU gas, so it is very high NGL quantities.

Well, I think you can see that in our realizations this quarter.

What we're getting compared to NYMEX for our natural gas.

And that's obviously a reflection of the rich gas we're getting.

I know if you pull the NGL volumes out, the gas volume shrinks by about 30%.

But then you've got to count the NGLs as a separate stream, so I hope -- I don't know if that's helpful or not.

Welles, this is Tony.

I think your question is a good one in terms of what Jay was mentioning a few minutes ago, about us considering going from a two-stream to a three-stream reporting process.

So we're looking at that right now, but that would split out crude gas and NGLs if we get to that point.

Okay.

Perfect.

And if I can get one more, can we get an update on the potential for a second Haynesville JV offering?

We're currently in negotiations with some parties on that, had some interest.

And I wouldn't say everybody in the world wants to get into a Haynesville deal right now, but I think there is some interesting opportunities in that.

I will say our folks in Shreveport who run that program are making it incredibly difficult to want to do a deal.

Our costs are coming down, and the wells look really good, so we're very close to the point where those wells will be stand-alone economic and actually meet our drilling hurdles, even with pricing where it is.

So it is not a must -- it is not a hill to die for, for us.

We want to get a deal done to manage our capital, but clearly at this point, our economics are looking better than they were six, three, four months ago, so we are working on it.

We do have some interest, and we're continuing our marketing process.

Perfect.

That's all I have.

Thanks so much, guys.

Next question will come from the line of Joseph Bachmann, Howard Weil.

Good morning, guys.

Hi, Joe.

Just a few questions.

One, follow on that Haynesville JV comment.

Just wondering, do you guys still need to drill about 16, 18 wells there this year to hold that acreage?

Is that still accurate?

That's 18 over two years.

Two years.

Okay.

It is actually about 12 or 13 this year.

I know that doesn't seem like that big of difference, but it is a significant amount of money.

And what we really -- the wells we're drilling this year are on the southern end of our acreage, so they're in the higher pressure areas.

And what we have seen there is we're making some really great wells.

Last well IPed about 12 million a day at 8,650 pounds on an 1864 choke.

I mean, there is some really great wells in here, and then we've got a Bossier section behind pipe that looks as good as the Haynesville.

So again, you really have to think hard about how much of that you want to give away.

Wade and I look at each other all the time, and he wants the money and I want the reserves.

We're kind of arm wrestling over this, but we are pursuing a deal.

We to want get a deal done to manage our capital, but the wells are really good.

Great.

And then the last question was on the Woodford.

With what Newfield is doing up there and their recent comments -- and I think their oil wells are in Cole County and correct me if I'm wrong, but I think a lot of your acreage up there is in Cole County as well.

Do you guys see any of that in your current activity, or what are your thoughts on that?

This is Jay again.

If you look -- at I am thinking back to one of the Oklahoma geological maps that the survey puts out up there, and if you look at the -- I think it's the TOC map -- as you get down into our area, it tends to narrow up.

So there is a narrower window there in our area of where you might find oily -- where the transition is from dry gas to oil.

We don't see a lot of potential for significantly oily wells on our acreage.

We do have some areas that have higher or richer gas that we were drilling toward the end of last year.

Right now, we're basically in a position where we've got the whole Woodford HPPed.

We don't have any activity planned this year.

We don't really see a lot of potential for the oilier leg here on our acreage.

Okay.

The last one with the Permian.

I know that it is not a big part of your overall drilling program, but it produces a lot of cash flow.

You guys still in the mindset where you are going to hold onto that, because it contributes such a large amount to your overall cash flow?

Yes, Joe, this is Tony.

In regard to our Wolfberry position, you're right.

It has been the largest cash-generating asset in our portfolio for a number of years, and continues to be.

As we mentioned, we have done some down spacing testing, down to 20-acres.

Initial results are looking positive, but it is still early.

So we would intend to retain our position there until we better understand the full value and contribution of the 20.

Okay.

Great.

Thanks, guys.

Thanks a lot, Joe.

Next question will come from the line of Derrick Whitfield, Canaccord.

Good morning, guys.

Nice quarter.

Thanks, Derrick.

Good morning.

Thank you.

Staying on the Permian, can you offer any incremental color on your findings from the 20-acre down spacing program and as maybe one additional point, could you also comment on how deep you're drilling your Wolfberry wells?

Well, this is Jay.

On the 20s I think what we have seen is our IPs are a little higher than we had -- we put our tight curve together based on a percentage of the 80s and a percentage of the parent wells and in general, the 20s we drilled so far are out performing our curves.

These aren't huge wells.

They're going to IP in the 100-barrel a day plus kind of numbers, and the real question once you get this is what they do over time, as you have 40s and 80s producing with them, and how much depletion do you see, and that's really what we're waiting for, is just an update to really feel comfortable with the economics of these wells.

Again, as with all of these resource plays, really the value is generated in the first couple years of production, so if you can get a pretty good idea what the first two years looks like, you can feel comfortable going on.

I don't think 20s, we will be able to drill 20s on all of our acreage.

I am trying to understand where the potential really is, is important.

Typically we'll drill them where we've had better parent well performance, so that's another issue, is to really try to understand where are they going to work, where are they not to make sure we can understand that.

There haven't been very many 20s drilled out there yet, and we're pretty early on.

As far as how deep we drill, we have typically, when we got into this play back in 2006, one of the things we noticed from some of the earlier drilling is that they have not drilled even to the bottom of the Wolf Camp section.

There are lobes at the bottom we thought we could add which we did.

We have done some testing down into the Strawn and so we typically do some completions in the Strawn intervals.

There is some up-hole stuff as well that we typically put in these wells.

There is a lot of talk in the Permian now about how various intervals and how much their contribution is, and I think we understand our acreage pretty well, and we have a stand alone that Atoka well out there that has been doing very well.

We think that Atoka potential is kind of spotty, but, yes, we typically have drilled our wells pretty well deep, pretty much to the base of the Wolf Camp and we picked up additional intervals below it when we saw potential.

Perfect.

Then maybe moving over to the Bakken, what's your latest thoughts on industry activity in and around your legacy bar trend area, and with the third rig arriving in April, are you inclined to test this acreage for Three Forks potential, and I am specifically thinking about North Dakota side?

Well, let me divide this into two parts.

The old Elm Coulee bar trend, Richland County, Montana.

With respect to the Three Forks, the shales between the Three Forks and the Bakken in that area are pretty thin, and in general, our view would be that we probably are getting Three Forks reserves in some of those wells.

Of course the wells weren't completed very well.

We did a lot of open hole single-stage fracs.

I think the real potential in the Montana side is refracs.

However, it is very difficult to get frac equipment to go do a refrac right now, so a lot of that work I think is going to end up getting put off until you see activity levels maybe come down a little bit.

Other than that, on the Montana side, there is some kind of mixed results going on in the Bakken over there.

We see some encouragement in some areas, and then you will see wells that don't look that good, and we do have some acreage over there, not active right now.

As you move into the North Dakota side, following the bar trend, again, we have a pretty good HPP position there and really more watching that than anything else.

I think the area that we get the most comments about, the Divide area, which is up against the Canadian border, where we have been drilling a number of wells, we get comments occasionally that people have looked at public data up there and they don't think it is that great an area, and I would caution people about that.

A lot of the public data you will see were shorter wells that were drilled on 640s, very short laterals, and if you look at some of our more recent wells, the 10,000-foot laterals, 20 stage completions, we have some very nice wells up in Divide County.

They don't IP like some of the higher pressure Bakken wells but they hang in really well and they're shallower and cheaper, so this year, we'll be spending most of our time drilling in the Raven area, which is what I think Brigham calls Rough Rider and in Divide, getting our acreage HPPed, and we have been very satisfied with our results.

Terrific.

And just one final question if I could.

Could you comment on the location of the 4,000 net acres you added since your last update?

Most of that was in Divide.

Terrific.

That's all I have, guys.

Thanks a lot.

The next question will come from the line of Brian Lively, Tudor Pickering Holt.

Good morning.

Just thinking about what seems to be good capital efficiency gains over the last few quarters, and what I mean is it seems like production is coming in higher than guidance, CapEx lower than guidance, just curious, if the reasons for that, is that a learning curve impact?

Is it conservativeness in the guidance or is this just some structural shift in the Company?

This is Tony.

Let me comment and the other guys can jump in if they would like.

I think this is part of the transformation we have been talking about over the last few years, and I think what you're seeing now is that the quality of our inventory continues to improve and we have been able now to high grade to our highest-return projects, our most productive projects and we're seeing that in spades with a couple of our key projects, namely the Eagle Ford, but also in the Bakken and some of our other liquid-rich plays, and one of the things that we also focus on is making sure that we give realistic estimates, and then we work to deliver on that.

So I think that's been a very deliberate strategy and approach and I think you're now seeing the outcome of that.

I really agree with that comment about trying to give realistic estimates.

Clearly as we moved over the last year or so, two years, and we had a lot of exploratory delineation risk in our program, and we tried to make forecasts that we thought were appropriately risked, based on those forecasts.

As it has turned out, a lot of our programs have gone better than we expected.

The Eagle Ford has gone very, very well, haven't drilled a dry hole in a play.

I think even though our costs are up, our results have been better than we expected, so we try to make forecasts that are appropriately risked, and when we do better than that, we're really happy about it, but we try not to put forecasts out there that we can't meet, and I think that's the way you should run your business.

That's great.

Thanks for the color on that.

Other question, just on the Eagle Ford and clarification on the asset sale package.

Within that 15% working interest that you're selling down, should we assume also that you're going to sell the 15% of the 60 million a day of production that you have?

Actually, it will be more than 15% of our production, because a lot of that acreage isn't producing.

It will end up being about 30%, somewhere between 20% and 30% of our net acreage that is sold, because again, it is a 15% slice of our half a million gross acres, okay?

It is going to be about a 20% to 30% chunk of our net acreage position, and therefore it will be a 20% to 30% chunk of our production as well.

Thanks.

That's all factored into our guidance and we still our guidance is still to grow 20% on a reported basis year-over-year.

That was my next question.

Thanks a lot, guys.

Thank you.

The next question will come from the line of Nick Pope, Dahlman Rose.

Good morning, guys.

Hi, Nick.

I was hoping to get a little help reconciling the CapEx number.

The number that's in the cash flow statement that the number that's seems like it is lower than the $877 million that you show for the costs incurred during the year.

What else is included in the costs incurred, relative to kind of that $870 million that you guided and that you showed us for year-end?

Brent is looking up the numbers.

I will tell you that the biggest difference most likely, when you're comparing anything to our cash flow statement is going to be accruals at the end of the year.

We had very active program at the end of the year, and so you will notice on the balance sheet that the accruals went up sharply.

That's probably the biggest difference between accrued CapEx if you will, cost incurred versus just pure cash flow with respect to the CapEx.

This is Brent.

I guess I just want to -- this is kind of a common theme question.

You have to distinguish between costs incurred and cash flow CapEx.

Right.

For costs incurred, which is what we guide on for a capital program, so the $1 billion we're providing for 2011, that is a cost-incurred number that includes load and exploration costs, and so we came in at $877 million, which was right in line with the $872 million we had been guiding for the year, and that includes all the non-cash stuff that you see like ARO, et cetera, and if you look at the cash flow statement, we came in at $668 million for the year, and that is, as Wade mentioned, that's a cash flow number that does not include accruals, cash out the door, so as we ramp up and you're getting invoiced, that's not -- that's going to show up in your costs incurred, but it is not going to show up in your cash flow statement.

Maybe answering your question a different way, but --

That's helpful.

I appreciate that.

And then, just as I kind of look at the guidance that you all are providing on the cost side for LOE and transportation, it seems like you all, there have been a little trend going down the last several quarters, and the number, at least for LOE, and that looks like the guidance you all gave for 2011 is kind of showing that it is moving back up on a unit basis.

Like how do you all view that, and what's causing that, and is there anything we can do to get that number going back down?

Sure.

This is Jay Ottoson.

On the transportation side, you're going to see increases in our transportation line because the Eagle Ford in particular has higher transportation costs on average than our other assets, so as the Eagle Ford production grows, transportation costs are going to follow.

That's just a function of, it is a long way from market, right, and those transportation costs are fairly high, so relative to other plays that we're in.

On the LOE side, there is no question you're starting to see some cost pressure now that we expected last year that is coming now.

If you go look at what pulling units are running, labor-related costs, some of those things that we expected to happen in 2010 which didn't, we're starting to see.

So we do think our base LOE will be moving up this year.

It is just a function of the general economy improving, and some of those labor-related, trucking, those kinds of things, obviously fuel costs are up, and those are the kinds of things that flow through your LOE and we do expect them to be higher this year than last.

All right.

Thanks for the time.

Really appreciate it.

Thank you.

The next question will come from the line of Patrick Rigamer, Iberia Capital Partners.

Good morning, guys.

Good morning, Patrick.

You mentioned earlier in the call that the Haynesville wells are becoming almost economic on their own, and I was just curious, is that a result of service costs coming down or EURs increasing, or what's driving that?

Our estimates of EUR are come up based on the results we have had, and we're in a very good portion of the deep Shelby trough.

We were pretty conservative initially on how we looked at reserves, and both our own drilling and other people's drilling around us are showing us the reserve numbers are quite a bit higher than we expected them to be.

Our early declines haven't been nearly what we originally assumed in our type curves.

It makes a huge -- that initial decline makes a huge difference in how that number ends up getting forecast.

Our costs are also coming down, and a lot of that is just, we had two rigs running in there and we're making efficiency gains, the last well we drilled, drilled significantly ahead of our curves, and we keep building these perfect well curves that we try to drill against on a time basis, and we keep beating our curves, so we are getting better at drilling the wells.

That's just a function of staying after it.

On the frac side, we're really not seeing a lot of reduction in frac costs.

We are optimizing our program to try to reduce that, and we're getting smarter about what pressures we pump at to try to manage the costs, and it is a combination I think of higher reserves, better wells than we expected, at least on a proved basis, and then we're getting better at drilling them.

It is both ends are working for us.

Okay.

And what are some like recent EURs in that area?

You're getting into numbers I think now, that you're probably on a proved basis, we're looking at reserve from 5 to 6 Vs, which when we came into this, we were talking about fours.

The last numbers I have look more like high fours to low sixes.

Our well costs have come down, and our first few wells in the area, of course they had a lot of science in them, were in the $12 million kind of range and now we're in the $11 millions, and so as you start to come down here, again these numbers I am showing are I am talking about are more proved numbers, but our expectations are getting higher for the wells, and as we get more efficient, we think an $11 million, $10 million to $11 million well is possible in here, and that's, you start to get down to below $2 for a proved F&D kind of number, and when you run that out, you can get pretty darn close to a well that will make our hurdles.

So we're encouraged about it.

Again, we're not changing direction.

We're still moving forward to try to do a deal, but, I think the opportunity is there, potentially to drill economic wells that hold acreage.

There is probably, if you look at that total acreage position, I think we said this publicly, we think there could be a Tcf or resource here, Haynesville and Bossier combined, and so it is an interesting thought process, when you think about how low the option cost is to really hold onto that whole thing.

It is something we're thinking about.

Okay.

You touched on this, but I guess the outlook for service costs in that area, sounds like the frac costs are kind of, there no real decline in sight unfortunately?

Well, I think the industry conventional wisdom is that it is going to come down.

The other thing everybody knows is there is a lot of wells out there drilled but not completed yet, so there is still a lot of frac activity going to be going on in the Haynesville.

We expect to see frac costs come down over time, which again, would lead you to the idea, well, okay, maybe if you stick around here for another six months these things really get to the point where they're really economic, and if you do a deal now, maybe you're give ago way something that you could have kept, so I keep -- Wade and I keep wrestling over this, but we're clearly still in the mode at this point of finding a partner.

Okay.

Thank you.

And then just last question real quick.

You added some acreage in the Williston Basin.

Just curious if you had a rough cost for the recent acreage?

Yes.

We don't typically talk about that.

I will tell you it wasn't what the numbers you hear for some other folks.

Okay.

Fair enough.

Thank you very much.

Thanks a lot.

The next question will come from the line of Andrew Coleman, Madison Williams.

Good morning, folks.

Good morning.

I had a question on the changing of your disclosures to break out the NGLs here.

When you look at the PV 10, are we going see anything different there or where would the NGLs flow through that?

Is it a reduction to future production costs or is it an increase in revenues?

Andrew, this is Brent.

I think when you start to think about the NGL question, it does not affect value so the PV 10 role does not change because we're getting credit for the NGLs in our gas stream, so the revenues stay the same.

When you really talk about NGLs, making that conversion, all you're talking about is a volume issue.

It clearly would be beneficial to us to do that because it makes your reserve metrics -- it makes all the metrics look better on a per-unit basis.

From a value standpoint, and this is what people need to make sure they understand, nothing changes between two stream and three stream reporting.

Your values stay exactly the same.

Okay.

It was my understanding that the in-flows would go up, and then you would see sometimes in the future production costs reflect the reduction from those, backing out those NGL volumes, so you get a lower cost structure on a wet gas number, but I will watch to see how you guys change the disclosures and look forward to the extra detail.

We said we are studying this.

Every cost and every revenue item would be lower on a per unit basis is what you need to keep in mind.

Right.

As Brent said, no dollar changes here.

It would just be additional total volumes and additional total reserves, if we make this change.

This is Tony.

Like we said earlier, this is under consideration now, so we're working that as we speak, and the real driver here is the significant ramp-up in our NGL stream from our Eagle Ford, so now it has gotten to kind of a meaningful volume, and that's why we're considering it.

Okay.

And if you think about the whole Company, if it is 1250 BTU gas for the Eagle Ford, what does it look like for the whole production base right now?

If you were to take a look at it just split between dry gas and crude and liquids, we're basically balanced between dry gas and the liquids side.

And crude is about a third, so the difference between a third and a half is all NGLs.

Okay.

Thank you.

Thanks a lot.

This concludes the question and answer session of today's call.

I would like to turn the call to Mr.

Tony Best, President and CEO, for closing remarks.

Thank you all for those insightful questions.

I did have a couple of comments before we wrap up.

First of all, again I want to introduce David Copeland as our new GC.

Brent mentioned that he was sitting in on the call.

David just joined us, and he was a key player in our recent high yield offering.

This is part of his orientation to the Company.

We wanted him to be able to sit in and hear a lot of your questions and commentary.

Secondly, as many of you know, we have a field trip to our Eagle Ford operation coming up in a couple of weeks, and Brent tells me that we have a few spaces left, and we would certainly invite you to join us.

It is going to be a very informative trip, and one that I think you will learn a lot from, if you are able to join us for that.

If you are interested, please give Brent a call, and we'll get you signed up.

With that, operator, thank you, and thanks to everyone for your interest in SM Energy, and we'll talk to you again next quarter.

Ladies and gentlemen, this concludes today's presentation.

Thank you once again for your participation.

You may now disconnect.

Have a great day.