SM Energy Co (SM) 2011 Q4 法說會逐字稿

Good morning.

My name is Tina and I will be your conference operator today.

At this time, I would like to welcome everyone to the SM Energy fourth quarter 2011 earnings and operations conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question and answer session.

(Operator Instructions) David Copeland, you may begin your conference.

Thank you, Tina.

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

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 a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the risk factor section in our Form 10-K that we filed today.

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

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

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

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

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

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

Good morning and thank you for joining us for our fourth quarter and full year 2011 earnings and operations call.

I'll cover a few introductory comments and then turn the call over to Wade and Jay for their respective financial and operational reviews.

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

I'm going to review our key highlights for 2011, beginning on slide number 3.

On a production front, SM Energy had record production in 2011 of 169.7 Bcf equivalent or 28.3 million barrels of oil equivalent, which is a 54% increase over the 110 Bcf equivalent we produced in 2010.

Our production mix for the year was 59% natural gas and 41% liquids.

Looking at quarterly production, the Company grew 62% from the fourth quarter of 2010 to the fourth quarter of 2011.

Adjusting for divestitures that occurred over the same period, production on retained assets grew 65%.

Our production growth is being driven largely by our total Eagle Ford program, which grew over 275% year-over-year.

What a great year from a production standpoint for our Company.

Moving on to slide 4, I'll discuss our proved reserves at year-end 2011.

Total proved reserves grew 28% year-over-year to approximately 1.26 trillion cubic feet equivalent or 210 million barrels of oil equivalent.

The portion of our proved reserves which are reported as liquids grew 73% for the year.

Our reserves product mix at the end of the year stood at 53% gas and 47% liquids.

We added slightly over 50% of a Tcf equivalent through the drill bit, which results in a drilling reserve replacement of 310% for the year.

This growth in proved reserves was accomplished while keeping our PUD percentage relatively flat to the prior year.

At year-end 2011, our PUD percentage was 33% and the Company's PV-10 increased 48% to $3.5 billion from $2.3 billion in 2010.

Jay will comment further on reserves during our key plays discussion later in the presentation.

Reserve growth is another area where we had standout performance in 2011.

Slide 5 shows our recent performance on a couple of important reserve metrics.

Our drilling F&D was somewhat higher than 2010, coming in at $2.85 per Mcf equivalent or $17.10 per barrel of oil equivalent, due to our increased focus on plays with highly liquids content, significant infrastructure expenditures in the Eagle Ford, and general cost pressures in our industry.

As I mentioned earlier, our drilling reserve replacement was above 300% again this year.

I'm proud of our results for the year and think that they continue to demonstrate the dramatic improvement in our project inventory over the last few years.

I'm now on slide 6.

From a transactional standpoint, 2011 was an incredibly busy year.

SM Energy closed on nearly $1 billion in property transactions last year.

Obviously, the $680 million transaction with Mitsui that will result in them carrying substantially all of our drilling costs in our non-operated Eagle Ford program for the next several years, was the largest of these.

Additionally, we divested a small portion of our operated Eagle Ford acreage that was detached from our main area of operations for a very attractive valuation.

The combination of these two transactions resulted in the coring up of our operational footprint in the Eagle Ford, increased our percentage of operatorship in the play, and enhanced our financial position as well.

In addition to the property transactions, we accessed the public debt markets for the first time in 2011 and had two very successful high-yield offerings at very attractive interest rates.

Looking back over the year, 2011 was a tremendous year for our Company and our stockholders were rewarded for their confidence and investment in SM Energy.

Not only did we execute well on our business plan for the year, but we positioned ourselves for continued success in coming years.

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

Thanks, Tony.

Good morning.

I'll start on slide 8.

Total production for the quarter came in at 51.3 Bcf equivalent, which is above the guidance range of 44 to 47.

Higher than forecasted production from our Eagle Ford program was the largest portion of our production [beat] and our results from Bakken Three Forks were also stronger than we forecasted.

Production for the quarter was also slightly less gassy than we had guided.

With respect to the cost items that we guided on, we came in at or below our guidance for LOE, transportation, production taxes, and G&A for the quarter.

With respect to income taxes, our effective rate came in at the low end of the range that we provided.

I'll now cover a couple of unusual items that occurred in the fourth quarter that threw us into a loss on a GAAP basis.

The first is the after-tax $107 million impairment on proved properties.

This impairment relates to natural gas properties located in our ArkLaTex region, primarily Cotton Valley and Haynesville assets.

It's no secret that gas prices have been under a lot of downward pressure in recent months and we aren't alone in recognizing impairments on natural gas assets this quarter.

The other unusual item that needs comment is the after-tax loss on divestiture activity of $16 million.

As a result of Endeavour's failure to honor their contract with us to purchase the Marcellus assets for $80 million net to SM Energy, the accounting guidance dictates that we can no longer categorize those assets as held for sale and we're required to re-categorize them as held for use.

As part of this re-categorization, the assets are marked to their accounting fair values as of the end of the year.

As these are dry gas assets, we ended up impairing them at year-end.

However, the non-cash charges presented in the line, gain or loss on divestiture activity, because it had been held for sale.

Additionally, by re-categorizing the assets as held for use, accounting guidance requires that we recapture or capture the associated DD&A that would've occurred over the period, had the assets been held for use, and this explains why DD&A came in above our guidance range for the quarter.

What's important to note is that the accounting treatment in no way changes our legal position with respect to Endeavour.

We believe they breached our mutual contract to purchase our Marcellus assets and we are pursuing all legal options available to us as we seek specific performance and/or damages from Endeavour.

Based on all this activity, reported GAAP net loss for the quarter came in at $120.7 million or $1.89 per diluted share.

Adjusted net income came in at $40.9 million or $0.60 per adjusted diluted share.

GAAP cash flow from operating activities for the quarter came in at about $271 million.

Operating cash flow, which is a non-GAAP metric, came in at $275 million, which is a 56% increase over the same quarter in 2010.

I'll refer listeners to slides 32 and 33 in the Appendix for reconciliations of these respective non-GAAP measures to their most directly comparable GAAP measures, as well as explanations as to why these non-GAAP metrics are being presented.

Moving on to slide 9, our financial position at year-end remains strong.

Our debt-to-book capitalization stood at 40%.

Net of the cash of $119 million, our net debt-to-book cap stood at 37%.

Our debt maturity profile is very manageable, we don't have any maturities for term debt until 2019 and our revolver doesn't expire until 2016.

In April of this year, holders of our convertible notes will have the ability to put those notes back to us, although we believe it is very unlikely that, that will occur.

We will also have the option of calling the convertibles for redemption at any time after April 6.

We have a lot of flexibility on whether we will call these notes, as well as the proportion of cash and equity that could be used.

Our accounting approach has been to treat these as if they will be net share settled.

Finally on slide 10, I'll briefly comment on our credit facility.

The borrowing base currently stands at slightly over $1.3 billion and we have a commitment amount of $1 billion.

Our next regularly scheduled borrowing base re-determination will be in April and will utilize our year-end proved reserves.

While a lot will depend on what the bank group uses for their price deck, despite the significantly lower natural gas prices, I don't expect our borrowing base to shrink.

Certainly, nowhere near the $1 billion bank commitment amount.

As of year-end, we had no borrowings outstanding under the credit facility.

Lastly, an updated summary schedule of our current commodity hedging positions is included in the appendix of the presentation.

A detailed schedule of those positions will be included in our Form 10-K, which is being filed today.

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

Thank you, Wade, and good morning, everyone.

2011 was a remarkable year for us from a number of standpoints.

Our drilling program allowed us to achieve Company records for production and proved reserves and we made significant strides in understanding the development potential of our major plays, which I will summarize today.

These accomplishments required an enormous effort from our operating staff and I am very proud of the work they did this past year.

With that said, we have a very ambitious program laid out again for 2012.

I am now referring to slide 12.

Production for the fourth quarter of 2011 reached a Company record of 558 million cubic feet equivalent per day or 93,000 barrels of oil equivalent per day.

That is an increase of 21% from the third quarter.

Our production mix in the fourth quarter stood at 56% gas and 44% liquids, which is slightly less gassy than the mix Tony showed earlier for the full year.

I'll refer listeners to our 10-K we are filing today for more details on the regional breakdown of our production and proved reserves.

From our reserve standpoint, we saw positive performance revisions in our key plays that were offset by negative price and cost-related performance revisions in our gassy Mid-Continent assets.

The lion's share of the divestitures for the year resulted from our transactions in Eagle Ford.

The Rocky Mountain and Mid-Continent regions also had minor divestitures in 2011.

The net effect of this activity is summarized on the reserve role slide that Tony showed earlier.

I should note that during 2011, we converted only about 11% of our year-end 2010 PUDs to developed reserves.

This is a consequence of the fact that we are still early in the development cycle on our largest projects.

At this PUD conversion rate, we obviously would not get all our PUDs developed within a five-year time period, as the SEC PUD aging rules require.

However, our development plans do anticipate increased PUD drilling activity over the next few years and so we are comfortable with the slight increase we are showing in our overall PUD percentage.

We have a large inventory of high-quality probable and possible drilling locations in our major play areas that will also find their way to the proved developed category.

As I talk today about the plays where we are most actively drilling.

I'm going to try to give everyone a better idea of what we currently think about our potential project inventory.

I will be starting now with the Eagle Ford on slide 13.

At year-end 2011, we had 84 gross wells categorized as PDP in our operated Eagle Ford area.

We completed 44 of those in 2011, which is a substantially lower number than we had originally projected.

When we realized that our non-op sale was going to take longer to close than we anticipated and that we would need to invest more capital there.

We allowed our operated drilling program to ramp up more slowly in the second half than we had originally planned.

Despite the lower well count, during the fourth quarter, our gross operated Eagle Ford production averaged 158 million cubic feet of wet gas production per day and 4,400 barrels of oil per day.

These numbers translate to an average net production stream of 180.5 million standard cubic feet equivalent per day for the quarter.

In January, our gross operated Eagle Ford production averaged approximately 170 million cubic feet a day of wet gas and roughly 5,000 barrels of oil per day.

We are right where we planned to be starting the new year.

We had 45 PUD locations booked on our operated acreage as of year-end.

This level of booking is consistent with our expected PUD conversion rate in the play over the next few years.

Our average PUD at the end of 2011 was booked, for SEC purposes, at a 5.4 Bcfe gross EUR, which is an increase from our average of 3.6 Bcfe at the end of 2010.

Our current operated acres position stands at roughly 149,000 net acres.

We have five rigs currently running on our acreage and anticipate picking up a third rig customized for pad drilling in late March for a total of six rigs.

Our plan is to hold onto six rigs for a few months, to drill some more remote locations.

Then reduce rig count to five and focus on pad drilling of development wells.

I'd like to now give a brief update on where we stand on our current estimates of future development well spacing and expected EURs.

I'll start with slide 14, which identifies two down-spacing pilots we have completed that now have meaningful production history.

Our delineation wells in the play have typically been drilled at 1,250 foot well spacing or higher.

A down-spacing pilot consists of a group of three or more wells drilled and completed at tighter spacing.

Production rates and wellhead pressures are then monitored during production to see if the wells perform differently than wells in the same area drilled at wider spacing.

It generally takes about six months of production to get enough data from a set of down-spaced wells to reach a conclusion about whether the wells are going to meaningfully interfere with one another.

These two pilots, both of which were drilled at 625 foot spacing, have generated enough data for us to reach some conclusions.

The spacing of 625 feet corresponds to roughly 72 allocated acres, if you do the area of math, assuming a 5,000 foot lateral length.

The first test is shown as Pilot Number 1 in the Galvan Ranch area.

Our test here indicates to us that wells drilled in that area at 625 foot spacing are too close together.

Our projections, based on the rate and pressure data we have collected, indicate a loss of more than 30% of each well's EUR at that spacing versus our delineation wells in that area.

Pilot 2 is located in our Briscoe Ranch project area and is indicating essentially no reduction in projected EUR at 625 foot spacing.

These results agree well with predictions we had made prior to collecting the data.

It appears our reservoir model is generating reasonable results.

For the area around Pilot 1, our model indicates that the optimum economic spacing is going to be roughly 900 feet, or essentially 100 acre spacing.

The model also indicates that in the Briscoe Ranch area, we can likely go tighter than 625 feet, but we have no field data to confirm that as of yet.

We will have more data coming in over the next year from other pilot tests, which will help us further refine our development assumptions.

On slide 15, we have then broken our operating acreage down into five areas, based on our current view of what the data indicates development spacing may be in those respective areas.

We have averaged together our current expected, or 2P EUR estimates for wells in each of the five areas to generate an average expected EUR for each area on the map.

To be clear, the reserve figures shown on this page are not what we are currently booking for SEC purposes.

Our SEC bookings are lower than these figures.

There is a lot of data here.

But if you do the simple acreage math and add up all the potential locations at their expected EUR level, our current estimate of total unrisked expected remaining resource for the acreage is roughly 5.3 Tcfe spread over about 1,450 remaining drilling locations.

We hope that additional spacing tests will indicate that we can increase projected well count further in some areas, but we will have to wait on the data for that.

In addition to doing more spacing testing, we are also testing different frack designs, longer lateral completions, and tighter frack-stage spacing within laterals; any and all of which we hope to improve our expected reserves per well and enhance the drilling economics of these projects.

I am now moving to slide 16.

As most people know, we closed a transaction in December which transferred a 12.5% working interest in our Anadarko operated acreage and associated gathering system to Mitsui in exchange for a drilling carry.

Our interest in the ABC acreage now averages about 14.5% with approximately 46,000 net acres.

90% of substantially all our drilling and completion costs will be covered by Mitsui, until $680 million has been expended for our benefit.

Additionally, the reimbursement we receive for the period between the effective date and the closing date will be used to pay for the remaining 10% of well costs.

SM will essentially be 100% carried for most drilling activity in the Anadarko operated acreage for the next three to four years.

We are not carried for mid-stream infrastructure spending by Anadarko.

We will have to continue to pay our proportionate share for that.

As Anadarko is the operator of the project area, we will let them speak about the details of the program.

As the production graph shows, we have seen solid production growth over the last two years in the program.

Given our lower working interest, post the Mitsui transaction, the rate of growth net to SM will obviously be lower going forward.

Anadarko was running 10 drilling rigs at the end of last year and we expect them to run a similar number of rigs in 2012.

Moving to our Bakken Three Forks program, slide 17 shows our acreage position in the Williston Basin, which totals roughly 202,000 net acres.

Our major drilling focus areas over the past two years have been the Raven, Bear Den, and Gooseneck areas, which total roughly 87,000 net acres.

We currently have three rigs running in the play, with a fourth coming in the second quarter.

Our volumes have been coming up nicely in these development areas, as indicated.

We finished 2011 right on our plan for completed well count, which is remarkable considering the flooding issues we had during the first half of the year.

Slides 18 through 20 show the three current development areas in more detail.

Each slide shows our year-end 2011 PDP and PUD well count in each area and the proved reserves remaining on those wells.

Our spacing assumptions for future development and average expected EURs at that spacing are also shown.

It should be noted that the data we are using to estimate expected EURs for these areas includes data from non-operated wells, not just our own wells.

If you add up all the locations at the expected EURs, this data indicates that we have about 140 million barrels of unrisked resource potential in these three blocks spread over 375 net wells.

These resource figures do not include any locations on our other acreage in the Williston Basin.

We do believe that our other acreage is prospective in a number of areas, but our focus has been on getting our newer leasehold held by production.

Our remaining acreage is largely held by production and remains to be delineated.

I'm now on slide 21.

In the Granite Wash, we are not as far along in our understanding of the potential of our acreage.

At year-end 2011, we had 40 gross and 9 net Marmiton horizontal wells producing on our acreage, and 13 gross and 3 net Missourian wells.

We have picked up a third rig to accelerate our operated drilling program and intend to split activity between Marmiton and Missourian targets this year.

We have very few PUDs booked in the Granite Wash and it is too early to comment on our expected reserve levels or projected unrisked resource or well count.

However, it is fair to say that we think there are hundreds of wells to be drilled on our acreage and we will provide more data on our expectations over time.

Essentially, all of our Granite Wash acreage is held by production.

On page 22, I'll quickly review some of our other activities.

In the Haynesville, we have recently decided to drop the last four operated Haynesville wells we were planning from our schedule.

We are currently drilling the last well we intend to drill this year in the play and at that point, we will have held about 80% of our operated acreage by production.

In the Powder River Basin, we participated in the completion of two wells in the quarter that are of note.

First, our operated 640 acre Niobrara well, the Discovery 135-NH, on which we had a 50% working interest, at a 10-day initial production rate of 330 barrels of oil equivalent per day.

The well encountered light oil, overpressure, and a high GOR, but the rock appears to be very tight.

We also participated in a partner-operated 1,280 acre Frontier well, with a 23% working interest that had a 10-day IP of 1,100 barrels of oil equivalent per day.

We will be completing additional wells in both the Powder and DJ Basins during 2012 in multiple intervals and with longer laterals.

I think it is just too early to say what value this acreage may eventually have for us.

In the Permian, we plan to focus on delineation drilling in our Mississippian limestone acreage and doing some infill Wolfberry drilling on our operated assets.

We also have a few Bone Springs horizontal wells we'll be drilling on acreage we hold in New Mexico.

Our capital guidance for 2012 is summarized on slide 23.

We expect to invest between $1.4 billion and $1.5 billion in CapEx this year, which includes the effect of the carry in the non-operated Eagle Ford shale.

Approximately 75% of our drilling capital will be invested in operated activities in the three plays highlighted today -- the Eagle Ford, the Bakken Three Forks, and the Granite Wash.

We expect that roughly 90% of our total drilling capital will be operated by us.

Our planned levels of activity are essentially in line with what we have previously communicated, with the exception of the reduction I previously discussed in the operated Haynesville.

The differences that some of you may be noticing from our detailed guidance last August in the various drilling programs are the result of truing up capital to reflect carry-ins and carry-outs of cost.

We intend to manage our capital program to the $1.4 billion to $1.5 billion range.

Our updated production outlook is presented on slide 24.

We are slightly reducing our 2012 production outlook to a range of 220 Bcfe to 227 Bcfe.

This is a reduction of 2% from our earlier forecast and results from our reducing capital investment in high-rate Haynesville gas wells.

The slight reduction in our production outlook for 2012, combined with more production in late 2011 than forecasted, will result in a slightly smaller growth percentage in 2012 than we previously guided.

Nonetheless, we are still expecting to grow over 30% this year on a reported basis.

With that, I'll turn the call back to Tony for his closing remarks.

Thank you, Jay.

Before we open the call for questions, I'd like to touch on a few key takeaways from our presentation on slide 26.

First and foremost, I want to re-emphasize the tremendous growth the Company experienced in 2011.

It is a testament to our people and their efforts in executing on these large-scale projects.

With regard to drilling inventory, we have now proved up a large amount of economic inventory on our acreage in the Bakken Three Forks and the Eagle Ford.

The significance of this expanded resource means that SM Energy has many years of drilling inventory remaining with its current asset base.

Finally, we are focused on executing our plan for continued rapid growth in 2012, while investing in new ideas and play areas to expand our project inventory well into the future.

With that, I'd like to open the call up for questions.

(Operator Instructions) Brian Lively, Tudor Pickering Holt.

On the Briscoe area, the EURs and the breakdown that you guys gave were quite a bit more oily than were my expectations.

With that, I'm just wondering, could you provide some update on the oil infrastructure and takeaway from that area?

At the present, we're still trucking all our oil, Brian.

We're working on getting that into a pipe.

We have a contract coming.

No question that they're oilier than we really anticipated, as well.

It does introduce some issues with respect to piping and other things that we have to -- tankage, other issues.

In general, I think we're going to be in pretty good shape.

As I said, we are trucking everything.

We have some pipeline contracts coming and we expect to have that pretty well in hand as we get later in the year.

Okay.

Then I know you guys won't comment on what other operators are doing per se, but if you look at the down spacing tests you guys have had versus even some other operator that's near you guys with the similar productivity, it seems like they're coming to different conclusions on what the lower spacing assumption should be.

I'm just wondering, is there a difference in the rock between you and that offset acreage or does the completion technique in any way drive what the spacing of the wells should be?

Let me make a couple of comments about that.

No.

I won't comment on other people's work.

I'm sure that they're doing fine technical work.

First of all, as we indicated, this is one spacing test that we have data on and we may get other data as we go forward.

I feel fairly confident with the 900 foot-type spacing that we've talked about in the Galvan area, which is really what you're focused on.

Secondly, I think as you go north in the play, you get to higher liquid contents in a product stream.

Clearly, if you start to look at the economics of accelerating higher revenue per [M] product, the economics of acceleration get better.

Even if you had an EUR impact and even if it was similar to ours, as you go north, you can probably tolerate that and still have acceptable economics.

It could very well.

I haven't done the math, but I'm assuming that you potentially could.

I think it's clear that where you get into the rock that's really good rock, it has higher porosity and potentially better productivity, that you're more likely to have interference.

I think that's what our model predicted; that's what we see.

What other people see, I really can't comment on.

Okay, that's helpful for context.

Last question for me, you guys are adequately capitalized.

But given your discipline and the outspend for 2012, are you guys looking at other options to raise cash like -- via asset sales or anything like that?

Or are you comfortable with just where the revolver stands now?

Yes, I'd say primarily, we're very comfortable with where the revolver stands and debt's very cheap right now and our balance sheet is in great shape.

If you look at where we are currently and just project forward to the end of the year, based on the midpoint of our guidance on capital and cash flow based on the strip right now, you're still looking at debt just a little over 1 turn, 1.2, 1.3 turns.

We're very comfortable with the balance sheet right now and intend to use it to fund the [cap] in '12.

Great, guys.

Thank you.

Welles Fitzpatrick, Johnson Rice.

I was wondering if we could get an update on completed well costs in the Eagle Ford and maybe your thoughts moving forward, and how that interacts with the pad drilling and what you might save there as well?

Yes.

In the slide deck, in the appendix, there's a pretty good summary of well costs by area.

So many people have asked us for more detail on these, that we finally broke down and did it, I guess.

There's actually a completed well cost number in there for each one of those five areas and I'll just refer you to that.

The pad drilling savings, would you guys take that in the $0.5 million range that other operators have talked about?

I think the number we quoted was about $1 million for three wells per pad, $333,000 a well, something like that.

Okay, perfect.

Can you give us a split out of where those five or six rigs are going to be located within those five new areas?

If you look at the five rig program, I think you can pretty much count on that two will be in the oilier areas, over in the Briscoe area and two will be in the Galvan area and one will be, I'll call it, flitting back and forth holding acreage and participating in one of the other areas during the year.

Okay, and one last one if I could, I know the EURs aren't what you booked them at, so presumably, they're not P90s and presumably, they're not P50s either.

Can you guide us in as to the interval of confidence you all have on those?

I think in a general sense, you could probably assume that we book at about 20% lower than our expected cases.

Okay, that's perfect.

Thanks so much and congrats.

Stephen Shepherd, Simmons and Company.

Of the five to six rigs that you're going to run and operate in the Eagle Ford acreage in '12, you said that three of those are designed for pad drilling.

We've already talked about the cost savings, but what about efficiency gains in terms of days to drill?

Can you quantify that for me?

Maybe what you could shave off with those rigs?

I think what we have shared is that we think we can drill and complete, when we get really going well here, we can drill and complete three wells in 80 days from first spud to end.

That's our target.

We do have a couple of rigs out there.

They're are actually pretty versatile rigs even though they're not ideally set up for pad drilling, they don't have feet to move.

We can pad drill with our other rigs, it's just it takes a little more time to move it.

None of these rigs can't drill pad wells, it's just that some of them are better set up for it.

Okay, that's helpful.

I've got one more for you.

The production mix improved sequentially this quarter and it looks like it was really NGL volumes as a percentage of the total that was driving that.

Is that something that we should expect to continue into 1Q or is that just an anomaly?

This is Jay.

I don't think it's an anomaly that the liquids percentages are increasing and we would expect that to continue.

We don't necessarily guide that, because it is difficult to know exactly how the mix of production will change.

But I think, in general, we're going to go to higher liquid contents over time.

Okay.

Just as a follow-up on that, the NGL realizations have been weak this quarter.

That's kind of been a recurring theme across various operators.

Is that a function of takeaway capacity not being in place or is that just more driven by general market weakness for the NGLs?

What are your thoughts on that?

I think the latter as opposed to the former.

We haven't had issues with respect to our takeaway.

Okay.

That's all I got, thank you.

Ryan Todd, Deutsche Bank.

A couple questions on production.

You talked about a little of that, but can you help us understand a little bit more what drove the much better than expected production in Q4?

How that translates through to 2012 and maybe what the production delta lost from the Haynesville was?

I will start with production improvement.

Clearly, a lot of that happened because we invested a lot of money in the second half, particularly in the non-operated Eagle Ford and they performed well.

We out-performed our expectation.

As far as 2012, I'll just refer you to our guidance.

I think you will see in the first quarter, of course, now we've sold significant interest in the non-op Eagle Ford, so we have to make that up before we start growing over on a total rate basis again.

To some extent there is some, as we shift over to pad drilling and more development in the Eagle Ford, there is some additional downtime in the base that you have to account for, as you have to shut a number of wells as your fracking development wells.

We've had to factor in a certain amount of additional downtime in the base, which reduces our growth rate somewhat.

Almost all the difference between the two forecasts we presented from what one clear back in last August to now is based on the fact that we cut those Haynesville wells.

Really, they're just very prolific wells and that difference that we're talking about is largely due to that.

Great.

The shift away from the Haynesville wells and the increased focus on the Eagle Ford and -- thanks for the granularity that you guys gave us there, the higher liquid contents -- how do you think about mix shift going forward for the Company over the next 12 to 24 months?

Again, we don't guide to that because it is a little difficult to predict.

Generally, we believe our liquids percentage is going to go up.

I would say though, that our Eagle Ford assets are, because of a lot of our production comes from the southern end of that gas condensate window, we're not going to become an oil company overnight.

Clearly, we're going to produce a lot of associated gas with this.

Any change you're going to see is going to be fairly gradual.

It's not going to be a rapid change and again, it depends, to some extent, on how our infrastructure builds out and exactly which wells we can flow at what rates.

We're not going to guide to it, but I think generally we're going to get oilier, but it'll be a fairly slow change.

Thanks.

If we think about it down the line a little bit in terms of potential acceleration, you'll go to six rigs, drop back to five.

How do you think about the potential to add back the six rigs at some point in the future?

When do you see infrastructure -- is it infrastructure limited?

When will infrastructure allow you to re-accelerate to some extent?

Our next big tranche of gas off-take infrastructure doesn't appear until mid-2013.

At this point, we think we can basically get the pipe full with the plan we've laid out.

We may need a little additional capacity along the way before we get to that.

After 2013, then it just comes down to what additional capacity we can secure.

But I think a five rig program certainly fills the pipe for us until that point.

Great.

Thanks, gentlemen, I appreciate the help.

Gil Yang, Bank of America Merrill Lynch.

Regarding the interference or the down spacing in Galvan versus Briscoe, is it rock permeability that's different or is it just that one's gassier than the other and so the effective permeability is different?

There is a difference in porosity and permeability between that Galvan area, especially in that particular area, and the Briscoe area.

The Briscoe area rock is typically a little tighter than most.

It is oilier, however, as well.

Both points you're making are accurate.

Briscoe's a little bit different rock, a little less porous, a little less permeable, and it's oilier.

I think the combination of those things means that you're draining -- it's also a little thicker, I should say.

The combination of those things means you're draining a relatively -- you don't reach out quite as far with your drainage, so you don't see as much interference and that's essentially the answer.

Right.

Is there any opportunity to change the spacing pattern with different spacing -- clustering of frac stages?

We're looking at moving our frac stages closer together, actually, across the entire play.

We typically have used 330 foot frac stage spacing and we're doing some testing clear down to 220 foot frac stage spacing.

Obviously, it increases the cost of the wells, but I think a pretty good chance that there's some optimum spacing level that may be lower than what we're showing.

I don't believe that that will necessarily allow us to push wells closer together.

Generally, that would lead you to think you might want to put them farther apart, you'd get better drainage, again.

I really don't think, when you look at the Galvan area, at least for us, I think that 900 foot number is a pretty good number.

Again, in Briscoe, I think there's a really good chance it will go lower in the oilier area.

But I don't want to everyone to be thinking that some other shoe's going to drop and we're going to down space the Galvan area a lot more than what we've indicated.

Fair enough.

Just to complete that thought, though, is it possible that in Briscoe, you don't have enough test data to know how much interference there's going to be?

Or would you have expected to see interference already at this point if there's going to be any?

I think we would have seen something.

Our modeling indicates that the 625 foot spacing probably wouldn't see it and we haven't.

We're just not comfortable, and the model would say that we can go lower.

We're going to be doing (inaudible) clear down to 150 foot offsets, which we would think should see some interference.

We're just not comfortable extrapolating our data below 625 feet without some data at some lower level.

We'll get to that at some point this year, I think.

Okay.

Just quickly turning to Haynesville, what happens to the remaining 20% of the acreage that is not going to be held by the end of this program?

Eventually the acreage will expire.

Most of that acreage is interior to our position.

We could potentially go re-lease that acreage if things turn around and it looks like an economic opportunity.

Obviously, acreage costs there are quite a bit lower than they were, although maybe not as low as they ought to be.

We have the opportunity go back out and re-lease that acreage.

If you look at the economics of the wells right now and look at the value of the acreage you would be saving or what it would cost, say, to go re-lease it, it just doesn't make sense to drill the wells.

That's the decision we came to.

Great.

Okay.

Fine.

Thank you.

Anne Cameron, BNP Paribas.

I just have a question about your operated Eagle Ford.

What do you think, from a logistics perspective, the maximum rig count that you'd comfortable running on that position?

Anne, we really haven't looked at that because our focus has been more on gas optic infrastructure.

Obviously, you could run a lot of rigs, but it really comes down to how much gas you can take away.

I don't know that I can give you a number other than the numbers we've given you.

Okay.

Then, on your reserves, the 37 BCF positive revision from the three stream conversion in the engineering, can you break that out between what is performance and what's the accounting change?

The three stream conversion accounted for 59 BCF of upward revisions.

If the rest of it is a negative performance revision, could you specify where those were?

It's all in the K.

Anne, it's in the K, as I indicated.

Okay.

Okay, thanks, guys.

Nicholas Pope, Dahlman Rose.

Just a couple quick questions.

I know you guys had talked about starting up a water distribution system down in Eagle Ford and I was wondering where you guys stand now in terms if you think you could drive some cost down on completions?

How much is being provided right now across your operated position in terms of access to that water?

We are using the system in the Galvan area.

The cost you see on this operated Eagle Ford slide in the appendix are essentially assumed those facilities.

Our Briscoe area water system is not completely done yet, but again, our costs for trucking there aren't as large.

In general, we have most of our water system in place and we are starting to recycle some significant quantities of water.

I think the well costs you're seeing on this sheet are probably mostly reflective of the cost after that system is in place.

All right.

Got it, thank you.

You mentioned January production on the operated Eagle Ford and you gave it, I think you said 170 million wet and 5,000 of oil.

Do you have that as where you are on a net basis to SM on an as-reported basis?

We didn't report it.

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

It's typically going to be 10% to 20% above that number on a net basis.

Got it.

Okay.

This is Brent.

You can [calc] that off the infrastructure slide in the appendix.

You can walk the math through kind of what we gave you.

And those were gross numbers, right?

The 170 and 5,000?

Yes.

Okay that's all I had.

Thanks, guys.

Mike Scialla, Stifel Nicolaus.

On the three rigs that you have running in the Bakken, where are those located and where do you plan to add that fourth?

I think we have two rigs running in the Raven area right now and one in Gooseneck.

Its kind of flopped back and forth, so sometimes it's two at Gooseneck, one in Raven.

But right now, there's two in Raven, I believe, and in one in Gooseneck.

As we move into the year, we'll be moving some of our activity back into the Bear Den area and starting our infill program there.

When we bring in our fourth rig, I think you can assume that we'll certainly be drilling in Bear Den for a good portion of the year.

Okay.

In that Gooseneck area, it looks like you're getting better results than some others up there have had.

Anything you're doing differently than other operators?

A lot of the early wells in Gooseneck area were 640 acre laterals, they were short lateral wells.

We've had a lot of questions about this, because people look at the old public data and they say these wells aren't very good.

They haven't actually looked at the 1,280 acre wells.

Our 1,280 acre wells up there are really very good, very economic.

But a lot of people do look -- there's a number of wells that were drilled up there that were 640-acre wells and they are not nearly as good of wells.

Given that some others did not have the success you're having, do you see any opportunity to add acreage in that area?

We have added acreage in the area over the last year.

I think the cat is pretty well out of the bag there.

Most people are in the industry who watched us know that we're making some pretty good wells.

I don't think you're ever going to get a really cheap deal up there from anyone.

Got you.

The other 120,000 net acres or so that you have in the Williston, I know you had some legacy acreage over in the Elm Coulee area, where else is that acreage located?

I think there's actually a locator map in the package.

We have a lot of acreage in Southern McKenzie County.

We have some acreage in Stark.

We have quite a big of acreage in Montana.

There's certainly a lot of re-frac potential in the old Elm Coulee area.

But, of course, a lot of that has already developed in the Bakken.

But if you start to look at where the potential is, I think there's some potential in Western Montana, there's some potential in that Southern McKenzie County area.

We would probably say is the most prospective acreage there.

Okay.

How about Stark?

Are you doing anything there or any plans to do anything there at any time?

We're currently completing a well in Stark.

I know there's been some negative results in Stark County recently from some other operators.

We're certainly not trumpeting anything at this point.

We'll see how the well works out.

There have been some pretty wet wells drilled down there recently.

Okay.

You mentioned in the slide deck that you have some acreage that's prospective for the Bone Spring in New Mexico.

How much acreage do you have over there?

Not much.

We're talking about four or five wells to drill, single rig program for six months.

We're just trying to help people understand how we have these spending in rigs in the Permian.

It is literally four or five wells that we'll be drilling.

It's a nice little program and I think they're going to be great wells, but it's not a huge material position that we would talk too much about.

Okay.

In the Mississippian play there, you still have roughly 90,000 net acres and can you talk at all about what you're seeing in that play?

I would say that the results are somewhat mixed.

We've had some good results and some not so good results and we're still really delineating.

We're completing a horizontal well right now that we'd hope can be interesting.

We'll see.

I think the jury is still out to some extent.

But we do have a meaningful position.

We just need to do more testing and see how that pans out.

Safe to say that it's maybe more of a conventional type than a broad resource-type play or is it still too early to even make that claim?

It's a carbonate, Mike.

There are a lot of these carbonate plays around that are going to -- you're essentially playing the idea that it's going to have porosity someplace.

In a sense, it is a conventional play, but you're using unconventional techniques to get to it.

But carbonates, there are some aspects to that, that make it tougher, can potentially make your results distribution wider, which exposes you to more risk on the front end.

That has to be managed.

That's why we've been a little slow on talking about it, because it takes a while for you to really know what you've got.

That said, as Tony indicated, we have a nice position.

We've drilled some pretty decent wells and well costs aren't super high there.

I think it's something we'll continue to work.

As we move into the next couple of years and we have more cash flow, we get closer to our cash flow, I think this could be one of those plays that's kind of the next leg of our growth story.

We're hopeful for that.

Can seismic help you there or do you have seismic in the area?

We've got it.

I certainly hope it will help.

I'll say it that way.

Okay.

Last one.

Can you say on that Frontier well, who the operator was there that you're partners with?

I don't think I will.

It's a private operator.

Okay, fair enough.

Thank you, guys.

[Yiktat Fung], Jefferies & Co.

I was just wondering how many months of data do you have for the other, I think, four down spacing pilots over at Galvan Ranch?

Just trying to get a sense of how much data you have seen to support your 100 acre spacing?

We are not relying on those other pilots to get to this conclusion at this point.

Some of those other pilots are really, literally very, very new.

There were a couple that we drilled last year that are starting to indicate data, but we did some other things in terms of frac stage spacing and some other things on them, that are probably going to mean they're not necessarily the greatest [comparitors].

It's going to be a while before we talk about any more data out of spacing pilots.

The 100-acre assumption, is that just based on that one pilot that you have six months of data for so far?

Or have you drilled other wells at 100-acre spacing that looked all right?

That assumption or the prediction -- we made a prediction based on some modeling we had done.

We used a [Vicket] modeling tools.

We have a number of different ways we look at these opportunities.

The results we're getting match pretty closely to the modeling we had done.

We feel our model is a pretty good predictor of what the outcomes are going to be.

The model, coupled with our economics program, would indicate that the optimum spacing is somewhere around 900 feet.

I think we're fairly comfortable that the model is predicting -- we have quite a bit of rock data to feed that model in terms of comparative data at wider spacing.

I think we're fairly comfortable that that 900 foot number is a reasonable number for you to use for estimating potential at this point.

We will get some more data later.

If I were you, I would not be assuming that number's going to get a lot tighter.

I see.

Got it.

Thank you for that.

Just one last follow-up question.

I was just wondering if you could clarify for me again why the non-op CapEx was going up?

Non-op CapEx going up?

We ended up staying in the non-operated Eagle Ford for much longer than we expected.

We were expecting to close that deal the first --

Sorry.

I was actually referring to CapEx forecast.

I think you also operated a portion of that forecast increased a bit or am I mistaken?

I'm sorry, I mistook your question.

I think for this year, it's largely non-op Bakken spending that's driving that.

Obviously, rig count's going up.

We have a lot of non-operated acreage, or a fair amount of it.

We just expect more development there.

Okay.

Thank you very much.

Are there any closing remarks?

First of all, we'd like to thank you for joining the SM Energy call this morning.

We appreciate your interest in our program and look forward to our next update with you coming up in May.

Thank you for joining us this morning.

This concludes today's SM Energy Fourth Quarter 2011 Earnings and Operations Conference Call.

You may now disconnect.