SM Energy Co (SM) 2011 Q3 法說會逐字稿

Hello my name is Dawn and I will be your conference operator.

At this time, I would like to welcome everyone to the SM Energy third quarter earnings 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) I would now to turn the conference over to David Copeland.

You may begin your conference.

Thank you, Dawn.

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

Before we start, I would like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance.

These statements involve risks 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 Web site for this call and the risk factors section in our Form 10-K and our Form 10-Q that we will be filed later 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, Senior Director of Planning and Investor Relations; and myself, David Copeland, Senior Vice President, General Counsel.

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

Good morning everyone and thank you for joining for SM Energy's third quarter 2011 earnings and update call.

Our comments this morning will reference the slide deck that was posted on our Company Web site last night.

I'll now cover the highlights from the quarter.

I'm starting on slide 3 of the presentation.

For the third quarter we posted a 6% sequential increase and average daily production, and achieved a new company quarterly record by averaging 462 million cubic feet equivalent of production per day.

We met or beat all of our guidance metrics for the third quarter, which Wade will provide more detail on in his financial update.

Our production growth during the quarter was led by our operated Eagle Ford and Bakken/Three Forks programs, which add quarter over quarter increases in production of 32% and 35% respectively.

We are, obviously, very pleased with these results, especially considering the challenges each of these programs have faced this year with the addition of new infrastructure in Eagle Ford and a severe winter and flooding in North Dakota.

Lastly, we recently completed our semi-annual borrowing base redetermination process.

And our bank group has increased our borrowing base to $1.4 billion from $1.3 billion.

It is important to note that our bank group did not consider assets subject to close or pending transactions in this process.

The increase came in the face of declining commodity prices.

Overall, SM Energy experienced another solid quarter.

With that I'll turn the call over to Wade and Jay for their respective financial and operational reviews.

Wade?

Thanks, Tony.

I will start on slide 5.

At Tony mentioned, the Company performed very well in the third quarter.

We met or beat all of our guidance metrics we provided.

Our production was in line with our guidance of 453 million to 481million, coming in at 462 million per day.

Production mix for the quarter was a little gassier than we expected.

Jay is going to elaborate a little more on this later.

On the cost side, we met or beat all of our ranges for the third quarter.

I might point out the lower production tax rates as a result of certain production tax incentives associated with tight gas activity in our Eagle Ford and Haynesville shale programs in Texas.

Our GAAP net income was $230.1 million, or $3.41 per diluted share.

Our adjusted net income per share was $42.4 million, or $0.63 per diluted share.

The large difference between the GAAP and adjusted income is a result of gains that we recognized this quarter related to the sale of the Eagle Ford shale properties in LaSalle County, Texas and a large unrealized derivative gain due to lower commodity prices at the end of the quarter.

Speaking of lower commodity prices, lower natural gas prices at September 30 triggered an impairment of crude James Lime gas properties in the amount of $48.5 million.

With regard to cash flow, our operating cash flow for the quarter was about $185 million.

GAAP cash flow from operating activities was about $120 million.

This difference was drive by a large decrease in current liabilities between the second and third quarters of 2011.

Working capital changes primarily.

We've included reconciliations of both adjusted net income and operating cash flow to the related GAAP measures in the appendix of the presentation.

Now on slide 6, which highlights the key points relating to our long-term credit facility.

During the third quarter we completed our semi-annual redetermination process with our bank group.

The bank group redetermined our borrowing base at $1.4 billion, up from $1.3 billion earlier in the year.

As a part of the redetermination process, the bank group excluded the value of properties associated with recently closed and pending divestitures.

It is also worth noting that commodity prices were lower compared to prices at our last redetermination.

We think the increase should be interpreted as a positive reflection on the underlying reserve base.

While our borrowing base has increased, we chose not to increase our current commitment amount, so it still remains at $1 Billion.

You should note that our revolver at September 30 remained undrawn.

Moving onto slide 7.

We present our financial position at the end of the third quarter.

As I just mentioned, you can see our secured credit facility balance remained at $0 at September 30 and our debt to book cap ratio has decreased from 32% at the end of the second quarter to 28% at the end of the third quarter.

While commodity prices have deteriorated since our last earnings call, we still think that our balance sheet is more than capable of funding the program we laid out last quarter with the remainder of this year and next year, despite the decrease in expected operating cash flow.

Before I turn the call over to Jay, I want to add that we have included a summary of our commodity derivative positions in the appendix of the presentation and a more detailed schedule will be included in our Form 10-Q, which we expect to file with the SEC later today.

With that I'll turn the call over to Jay for his operational update.

Thank you, Wade and good morning everyone.

I'll start my remarks on slide 9 with a summary of our production for the quarter.

As you can see, production averaged approximate 462 million cubic feet equivalent per day, up from 437 million in the second quarter.

A 6% increase.

Although we were above forecast in most operated areas, our operated Eagle Ford assets produced right at our forecasts for the quarter, limited by intermittent constraints on our ability to move higher volumes.

In our forecast of the volumes we would book from Anadarko's Eagle Ford activity during the quarter was a bit too high.

As a non-operating partner, we have found it challenging to accurately estimate production volumes for this large and rapidly growing program.

Oil production grew 6% sequentially to 21,500 barrels per day, driven by growth in the Eagle Ford and our Bakken/Three Forks programs Natural gas increased to 281.2 million cubic feet per day, which is a 7% increase from the prior quarter.

Reported NGL volumes in the third quarter, however, were essentially flat to the second quarter on a sequential basis.

Which is due to corrections made to previously estimated and reported volumes largely in our non-operations assets.

Moving onto slide 10.

Our operated Eagle Ford program reported a production increase of 32% quarter over quarter, while running average of 3.5 drilling rigs.

A significant amount of this increase in production was from being able to open up chokes on previously restricted wells.

We are currently running 4 drilling rigs in a play and plan to add a fifth rig in the play by year-end.

We have another new build rig coming to us early next year at which time we could increase our rig count to 6.

Most likely we will let one of the non-walking rigs go at that point and maintain a 5 rig program.

We have begun pad drilling in play and as we begin to utilize walking rigs, we expect to decrease the amount of time it takes to drill and complete wells.

In addition to time savings, pad drilling reduces the surface impact and the cost of gathering assets.

Our expectation is that we will save about $1 million for every 3 wells we drill by pad drilling.

I should note that we have all of our frac services lined up to support our drilling program for next year.

We are starting to see indications that prices for services are softening, or at least not escalating in the play.

With respect to infrastructure, our off take capacity grew during the third quarter with the arrival of the Eagle Ford gathering pipeline, operated by Kinder Morgan and Copano.

That pipeline was commissioned in early September and adds approximately 75 million cubic feet a day of additional gross wet gas uptake capacity.

Our next major infrastructure hurdle to increase production is the start of our 16 inch gas gathering trunk line throughout the field.

Which we have been commissioning over the last few days.

With this debottlenecking of our gathering system, we should be able to get a number of additional wells hooked up and flowing, and continue to ramp up our operating production.

Moving to slide 11.

One of our major goals for 2011 was to improve our understanding of the ultimate of development spacing in the Eagle Ford.

On this map we have located the 8 down spacing pilots planned for this year.

Most of these pilots consist of 3 wells based either at 625 feet or 833 feet apart.

By year-end 2011, we will be operating by 5 pilots in Galvan Ranch and 3 in Briscoe.

We plan to drill several additional pilots in 2012 as well.

Although it takes some time to make judgments about spacing based on these tests, we believe that by year-end we will have a pretty good idea of what the general spacing will need to be in areas where we expect to be doing most of our drilling in 2012.

For those of you who just can't wait and are building production models out there, I should note that our expectation is that spacing will eventually be tighter in the shallower and oilier portions of the play.

And farther apart in areas where the drainage radius of each well is likely to be larger.

In addition to these spacing tasks, we continue to experiment with drilling longer laterals, up to 7,000 feet, more frac stages, up to 20, and different recipes for our frac designs.

We believe there is a lot of fruitful work to be done here in both improving performance and reducing costs.

We are sharing ideas broadly across our operating organization to ensure that we are trying everything that makes sense to optimize performance and maximize return on capital employed.

I'm now on slide 12.

In a non-operated Eagle Ford we saw net production grow 7% on a sequential basis to 60.9 million cubic feet equivalent per day.

As I mentioned before, our forecast of the [ABC] JVs production was overly optimistic.

And reported production was impacted by some prior period volume estimates, which particularly impacted reported liquid volumes.

We also underestimated the scale and length of production downtime resulting from the shut in of producing wells adjacent to wells being completed, as well as the number of wells Anadarko would have waiting on completion.

I want to be clear that the issue here was completely our forecast.

And should not be construed as a comment on the performance of the operator or the underlying asset.

If you average growth over the last 2 quarters, our non-op Eagle Ford production has been growing at an impressive 20% per quarter and we are very happy with the investments we are making with Anadarko.

With respect to our announced agreement to sell Mitsui, a 12.5% working interest in our non-op position, we announced in mid-October that the outside termination date of the transaction had been extended by Mitsui and us to December 23, 2011.

The date was extended to allow for both SM Energy and Mitsui to continue working on meeting all conditions of closing, including obtaining certain consents from third parties.

In fact, one of the needed consents was obtained in just the last few days.

Our current capital and production plans for 2012 assumed that the deal will close by year-end 2011.

On slide 13 we provide an update of our Bakken/Three Forks program.

Production volumes were up 35% quarter over quarter to more than 5,000 barrels of oil equivalent per day.

Putting the flood issues that we and others in the basin experienced in the first half of the year behind us was a big part of the story here.

We were able to get back to work and reestablish essentially all of our impacted production.

Additionally, we were able to get back up to speed on completion operations.

With regard to Bakken well costs, I think it's worth noting that since our last earnings call, well costs have continued to increase in the Williston Basin.

Rig count has not been increasing much recently, however, and we are hopeful that most of the cost growth is behind us.

Moving on to slide 14.

We have provided a map of our Niobrara test wells in our northern DJ Basin acreage.

We have now completed 5 wells in our perspective areas south of the Silo Field.

The well results continue to confirm our original thought that the highly fractured nature of the Niobrara in this area may result in a wider distribution of outcomes and in many other resource plays.

We believe that it is logical to try to drill these wells with longer laterals similar to what we are doing in the Bakken, and that's the direction we will be moving in this area in 2012.

We are currently drilling our first Niobrara test well in the deep portion of the Powder River Basin where we have a significantly larger acreage position.

As for our other operations, we currently have 2 rigs running in the Granite Wash, 2 in the Permian Basin and 1 in the Haynesville.

We have solid production and well completion results in each of these areas in the third quarter.

I should note that we have not changed our capital guidance for 2011 at this point, even though we are continuing to participate with ABC in their program at a 27.5% working interest.

Our spend rate in other areas has been running somewhat behind our original forecast and we believe our annual guidance for CapEx and volumes are still appropriate.

With that I'll turn the call back to Wade to discuss 2011 and 2012 funding.

Thanks, Jay.

Looking at slide 15, as Jay mentioned, we have updated our 2011 and 2012 funding slide to show updated projected cash flow numbers.

At the last earnings call we presented this slide with estimated cash flow projections that assumed the strip price at the end of July.

As you know, the strip price today is significantly lower than it was at that time.

As you can see, our new expected 2011 cash flow amount is $795 million, down from the $860 million at the second quarter call, and our 2012 projection is now between $1.1 billion and $1.2 billion, down from $1.2 billion to $1.3 billion.

To reiterate, these changes merely reflect the change in commodity strip today versus the end of July before our last call.

As you'll notice, our funding gap for the years 2011 and 2012 have increased to $277 million and $325 million respectively, compared to about $200 million per year at the second quarter call.

You should recall that $277 million gap in 2011 was funded by the $350 million high yield bond offering earlier this year.

The $325 million gap in 2012, even assuming no further divestiture's, is very manageable and can certainly be covered within our revolver.

As a result, we are reiterating the production guidance that we laid out last quarter.

I'm now on slide 16.

We expect to produce around 164 Bcf equivalent in 2011 and 225 to 232 Bcf equivalent in 2012.

That represents 50% production growth in 2011 and 35% to 40% production growth in 2012.

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

Thanks, Wade.

Before we open the call up for questions, I would like to touch on a few key takeaway's from our presentation this morning.

First and foremost, production growth in our operated programs in the Bakken and Eagle Ford has been very strong, up over 30% in each play quarter over quarter.

I think these growth numbers are not only a testament to the top-tier assets that we hold, but also to the solid execution of our plan by our employees turning these assets into growth engines for our Company.

During the quarter we completed our semi-annual borrowing base redetermination.

Results of the redetermination included an increase to our overall borrowing base despite a reduction in asset base from properties that were excluded from the process due to announced divestiture's and a lower commodity price deck.

Lastly, it is worth noting that while a decreased commodity strip price has created a larger projected funding gap than we have assumed at the second quarter, we are still projecting a gap that we feel is very manageable as we have a strong balance sheet, including a $1 billion revolver with no borrowings as of the end of the third quarter.

The depth and strength of our balance sheet will allow us to grow the Company at the rate we had previously guided.

As we always do, we will keep an eye on commodity prices and completed well costs, and it warranted, we will adjust our program accordingly.

As you've heard us say, we are not interested in growth for growth sake.

At this point in time, however, we are comfortable reiterating the capital and production forecast that we provided on our last call.

With that, I'll open up the call for questions.

(Operator Instructions) Your first question comes from the line of Welles Fitzpatrick with Johnson Rice.

There was a little bit of acreage bump in the Bakken, is that just lease clean up?

I did not know we -- yes, Welles, it is.

I didn't even notice it actually on the slide, but yes, it is just some additional acreage we picked up.

Is there any way we can get an update on the Permian leasing efforts?

I don't think we have anything that we can say really about our Permian leasing efforts.

Okay, one more if I could, the slight bump in Eagle Ford well costs, it sounds like you guys are optimistic going forward.

Can you talk a little bit -- I'm assuming that is on the completion side.

Can you get any more granular?

Is it prop in, is it asset?

Is it --?

No, I think we are just seeing some indication that we are not getting demands for cost increases every time we -- every time we bid a job.

I think we are starting to see some indication that there is a little bit of excess pumping capacity in the Eagle Ford.

It's not huge, and we're certainly not seeing cost decreases at this point.

But I think it is starting -- the pressure is starting to come off a little bit.

We expected that, obviously we are hoping for it.

We may be a little too hopeful, but I'm fairly comfortable as we go into next year you are going to see costs flatten.

In addition to that, of course, we will be pad drilling, which should cut our costs.

Our water handling system is going to cut our costs as well.

So, I think in general, we are comfortable that if you forecast our cost in the Eagle Ford forward into 2012, that we are going to be relatively flat.

Perfect.

That's all I've got.

Thanks so much, guys.

Welles, let me make a comment that some of the reason you are seeing increases in our well costs are because we are pumping more stages on a lot of these frac jobs as well.

I mentioned in the call, but we are trying to do a number of jobs in which we pump higher stage counts at closer spacing.

That's driving our well costs as well.

Thank you.

Your next question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Last quarter you guys gave some proved estimates for the operated Eagle Ford wells, handful of wells that I think were around the 7 BCFE range.

Just wondering how those wells are tracking, and can you guys give any more updates on, overall, how the wells are stacking up versus that estimate?

This is Jay.

Brian, I actually haven't looked back at those wells in the last few weeks.

I don't have any reason to believe that they are any different than what we gave you.

We, obviously, gave you numbers we thought were fairly conservative to begin with.

And what we indicated when we gave those numbers was that we thought those were consistent with a down-spaced case.

I would say, in general, as I mentioned in the call, I think the Galvan area is likely to be not down-spaced as much as potentially some of the -- some of our tighter, oilier areas.

I think those numbers we gave you are good numbers.

In fact, there is probably some upside to those based on what I think the ultimate spacing is likely to be.

And Jay, do you have a sense of what a 2P case would be for the 7 Bcf well?

Brian, I don't think we have given those numbers, and I'm not sure that I actually can have an estimate of what the 2P case is.

It is north of those numbers, that is all we can really say.

Okay, and then the -- looking at the volumes for Q3.

Can you guys give an update of what the current corporate-wide production rate is, and then maybe what your planned exit is for year-end 2011?

Could you repeat that question, Brian?

Yes, Jay, I'm just looking for a current rate on company-wide production.

And then the exit for this year?

I don't have a current rate.

We typically don't guide on those numbers.

I know what our numbers were in October -- or in September.

I know what I think they are in October, but I don't even have final October numbers yet.

Okay, last question for me.

You talked about intermittent production volumes in Q3.

Any way to quantify how much volumes were curtailed or lost in the quarter in the Eagle Ford?

I don't have an exact number.

A lot of the curtailment in both Enterprise and Kinder were up and down.

We had some compression issues where we were up and down.

I think people should understand, we contracted our mid-stream business through Regency back at -- it was right at the end of first quarter, beginning of the second quarter.

In that timeframe, between then and now, these guys have done an enormous quantity of work in the field.

At one point in time, in the third quarter we had 600 contractors in the field building our 16-inch pipeline.

As a result of all of that construction activity, there are times when you have to shut in wells, you have to shut in production, you have to curtail production.

This last week we lost rate because we had to pack the line, the 16-inch line all the ways, there were several days when our production was down.

So, there is a lot of start-up related stuff that -- where you are up and down.

In fact, I think the fact that we made our operated forecast in the middle of all of this is actually a testament to our guys in the field doing an exceptionally good job.

I recognize that a lot of people for one reason or another believe that we are always going to outperform our forecast.

But I think we hit our forecast in the Eagle Ford this quarter, and I'm actually very proud of that.

I'm not so proud of the fact that we overestimated some volumes in other areas.

But the operated stuff really worked very well.

As of this morning, we were making about 136 million a day of gross wet production capacity, and we are still coming back up after packing that line.

And we have a number of additional wells to hook up and put into production.

So, that 136 million is a gross wet operated number.

Kinder Morgan/Copano is flowing, and we're flowing gas to both Enterprise and them.

Although they had a few start-up bobbles, in general it was a fine performance by all of them.

Brian, if you look at the guidance update in the appendix, we are showing fourth quarter average daily production 479 to 509.

If you are thinking about fourth-quarter production on average, it would be in that range.

I think he was looking for December instantaneous rate at the end of the year, and we don't -- I don't know that number right now.

All right, guys, thanks.

Your next question comes from the line of Jeb Bachmann with Howard Weil.

I had a couple questions.

First, Jay, any early comments on the performance of the 7,000-foot lateral, 20 frac stage wells in the Eagle Ford?

No, I don't.

In general, what we are seeing as we have brought our frac stages closer together is we are getting better overlap on our microseismic, haven't really seen any interference yet.

We are moving to higher frac stage counts, and we are going to be experimenting with some Bakken style sleeve type jobs in order to be able to get those jobs pumped quicker.

We have some interesting test work going on.

I don't really have any results to share at this point.

Maybe by year-end I might be able to say something additional on that.

Okay, and then, you have talked about this in the past.

I was just kind of wondering on the Permian down spacing, if you guys are ready to talk about results there, or are you still monitoring that program?

Well, we drilled six or eight wells.

In general, they are performing about to our forecast.

The big issue we have, I think, in the Permian right now is those Wolfberry wells are over $2 million a piece.

And it cuts down the number of PUDs you have as a result.

The wells we drilled are performing fine.

We're just not that excited about going in and drilling a whole bunch of them right now.

Okay, last one for me, Tony, any update or comments right now on a Haynesville JV?

You guys still looking at doing that at this point?

Yes, Jeb, at this point, we are moving on.

Basically we went out and worked that for some period of time to find an appropriate partner to bring in.

But quite frankly, there wasn't any compelling offer.

And now we've gotten to the point where we have about seven wells to drill next year, including one sidetrack.

We expect to have that done by September of next year.

So, pretty modest program, one rig, and we expect to have that HBP by September of next year.

The importance of that is not only the Haynesville potential, but also we retain rights in the Bossier by completing those wells.

That was my next question, if you guys had any Bossier wells planned within the next year?

We do have a Bossier test that will be drilled right around the first of the year.

It is a block that, in fact, if you drill a Bossier test you can hold all depths.

We are going to take a well that we had completed vertically in the Haynesville, and we're going to turn that around and complete it with a lateral in the Bossier, and that will be somewhere around mid-first quarter.

Okay, great; thanks, guys.

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

I was hoping if you could provide some Eagle Ford numbers on the operated stuff.

Perhaps number of wells producing and/or number of wells in backlog?

I will start by saying we don't have a number of wells in backlog because we don't drill wells and not complete them.

We have about 70 wells drilled, and I think the number completed is close to that.

But that is not an exact number.

We can get you that, and Brent can get it to you.

Okay.

And the 70 wells was a gross or a net?

Our net and gross is essentially the same.

It is 100% working interest.

Okay.

I will just get it from Brent then.

In the dry gas acreage, what is your -- do you have some drill-to-hold budget that is going to kick in any time in 2012?

We will have to drill a couple dry gas wells in 2012, but it is really minimal.

They are very large lease blocks.

They are continuous development clauses.

Essentially, we only have to drill one well every 120 days or so.

We can generally push those up into the wetter gas portion of that.

I would guess we will probably drill one or two dry gas wells, truly dry gas wells in 2012.

We are going to plan to drill 95 wells next year.

Okay.

All right.

Then finally, you kind of provided this in the Q, but hopefully you have the numbers in front of you.

Do you have the production by area breakdown in the Mid-Con, ArkLaTex and so on?

You will have to give us a minute to pull it up.

Okay, thanks.

Do you have another question, and we will come back to that.

Yes, I guess, this might be more -- first, 136 million a day gross wet operated, how does that compare to the 128 million net that you reported for the quarter?

The 128 million net is about 10%, maybe 11% higher than our gross wet produced, so take 12 million off of that, what do you get, 116 million?

We average about 116 million for the quarter, somewhere in that range, and now we are at about 136 million, and I think we are limited a little bit today.

So, it's significant growth.

What we said and we have -- as opposed to a total company exit rate, we have said repeatedly that we are going to be at about 170 million a day gross wet operated production in December, we believe, on our operated Eagle Ford.

Again, add 10% or 15% to that to get to a net MCFE number.

Okay.

Finally, again, it might be more minutia than you want to share.

I am just taking the mid-point here, but 30 million, 40 million a day sequential growth in Q4.

Can you sort of have a sense how that might break down Eagle Ford operated, non-operated -- the contribution?

Well, in general, I think you can tell from the numbers I just gave you, we should be -- more than half of that is going to be just operated Eagle Ford growth.

The rest of our assets are going to grow some, and then, of course, the non-op, I would expect it to grow a lot as well.

Most of the growth is going to be in the Eagle Ford.

More than half of that is going to be operated.

I guess you can kind of say, I think you will have a little bit of Haynesville growth in the fourth quarter.

We completed a couple of wells right at the beginning of October.

I think you will see some gas growth in the Haynesville that is not insignificant.

Half of it is probably going to be operated Eagle Ford and the rest will be non-op Eagle Ford.

Brent has those numbers, I think, for you.

Perfect, thank you.

The 462 million a day equivalent, 70 is Rocky Mountain, 31 is Permian, 196 is South Texas Gulf Coast, which is the Eagle Ford, 81 is ArkLaTex, 84 is Mid-Continent.

Sure, fantastic.

All right, thanks, everyone.

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

I'll confess, I was one of those guys that thought you'd always beat the high-end of your guidance.

I wanted to see, you'd mentioned, Jay, that the non-op production the Eagle Ford was below your forecast, can you quantify how much that was off?

I'm not sure I know the exact number.

It was like 0.7 B's.

From our forecast -- from our internal forecast -- this is Brent, it was about 3.5 to 4 B's light.

The 0.7 was just NGLs, right?

We were just overly optimistic about their ramp, and part of that was that we, frankly, overestimated the second quarter some, so we were on the wrong trend line.

We had to go back and correct the volumes that we booked in the second quarter, which, obviously, made it look even worse.

That was the 0.7 I was talking about.

Again, it is not the performance of the asset.

They are doing a lot of really good things.

They are completing a lot of wells.

They have had -- the way they are going about this is they are mowing the grass with drilling all of these wells, and as a result, they have a lot of wells shut in when they are fracking offset wells, and we didn't account for that correctly in our forecast.

And then we have had a lot of trouble on the NGL side making forecasts of their NGL numbers for one reason or another.

We just blew the forecast on that, and hopefully we've got our fourth-quarter forecast in line, and we won't do that again.

Got it, okay.

On the spacing test that you are doing on the Eagle Ford, is the 625-foot spacing something that you are thinking might work now in the wetter portions of Galvan, or is that the tighter spacing that you are thinking about for the oilier parts of the play?

It is still a little early.

I will just say, because I am sensitive about all the folks out there who are trying to understand this -- I don't think you should assume 625s at Galvan.

I think it is probably going to be more like 830-foot-type spacing.

I think you will get to those lower spacing numbers in the tighter and wetter portions of the reservoir, maybe even lower.

But I think in the very best parts of the reservoir, we have more porosity, and wells drain larger radiuses, I think something like an 830-type-foot spacing is probably a more reasonable assumption.

If I was building a model, that is what I would use.

I know there is other people out there talking about tighter spacing, but as an industry, we have a tendency to over-capitalize our successes, and we are not going to do that.

That helps, I appreciate that.

Any detail at all you can provide on the Mitsui deal?

You mentioned you needed to consent -- one of the consents you recently got.

Is that from partners, or can you add any color behind that?

At this point, we basically said what we intend to say as far as the current status.

Obviously, that is work in progress.

It's best if we don't provide any more detail at this time.

Other than to say we fully expect that to close by year-end, and we are working it hard with our soon-to-be partner, Mitsui.

Okay.

Last one for me on your Bakken well costs, which you said are continuing to creep up a little bit in the 8.5 million to 9 million range now in the Raven area.

Can you talk about your latest completion design there?

What the 8.5 to 9 million translates to?

The number of stages?

We are past 20 on mechanical sleeves now.

We are pumping very large volumes of fluid.

You remember the Raven area is pretty deep, so it is probably one of the most expensive areas in the Bakken to drill and complete.

I will say the wells look great.

There have been some really good results.

I don't have a bunch of them to show you today, but there's some really good recent well results in there.

Pressure matters, and certainly those wells are outperforming our forecasts.

They are still economic.

I get concerned about the Bakken because of just the sensitivity of it to price.

But right now these wells are working, and we just are hoping that these costs flatten out a little bit for us.

Some of the cost increase we have seen is due to us pumping more stages and pumping more fluid.

That is built into those cost increases.

You are still using sleeves and sand there?

Yes, we are, but we are -- we have gone to higher stage count, and typically everyone is moving to a higher sleeve number, higher numbers of completion stages even in the sleeves.

We are moving in that direction as well.

We do save probably $1 million a well by pumping with sleeves, and we still believe it is the right answer.

Where do you think the threshold price is for an oil price before you think about slowing down there?

Well, again, it all depends on costs.

It's very difficult to give numbers like that.

If it went to $70, and cost stays where it is, some of the stuff gets really tight.

I don't think that happens.

It goes to $70 and stays there, I think costs come down substantially.

It's a little bit hard to figure.

But right now, we are bullish on the play, and we are going to be adding rig --.

We just committed to a fourth rig their, starting in April, a new build that just got a two-year contract.

So, we are bullish on it, and we think it is great.

We have some great asset there, and we would like to go a little bit faster, and we are going to be picking it up a little bit in 2012.

Very good.

Thank you.

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

Quick question on fourth quarter guidance.

In terms of the non-operated Eagle Ford, is there an expectation of a full quarter of the full interest in the non-operated, or do you all expect -- is it a year-end thing that you are expecting in guidance?

That is the way we built it.

We looked at our total capital spend, and assumed a full quarter in the non-op.

As I said, we are a little bit behind on our spending in other places, and we think basically it is a wash, both from a capital and a production standpoint versus the forecast we gave at the end of the second quarter.

Okay.

That is helpful.

And again, in the non-op, I guess when you look at the NGL volumes that the total Anadarko production is providing, it seems like there's a decent amount of variability in kind of the percentage of NGL of the total.

Does that have something to do with the contracts and the processing during the quarter, or is it because of the fluctuations in the wells and completions during the quarter?

There have been some changes in some of the processing, is my understanding.

However, most of the variation you see between first, second, and third quarter is due to just poor estimating on our part during the second quarter.

We overestimated their NGL and their liquid numbers in the second quarter, and then had to correct them in the third.

I should say, none of these changes are material from an overall company financial standpoint.

It's just that -- we looked a little too much in the second, and had to take it out in the third.

You can see that specifically in those bar charts where you look, the liquid volume, the percentage of liquids in second quarter went way up, and now it has come back down.

Part of that is over-exaggerated due to the fact that we made corrections.

Part of that was second quarter was just too high.

But I think that's part of the learning process, Nick, in terms of watching their program and trying to understand the impact on the offsetting wells and their pace.

We have made those corrections, and I think we are fine going forward.

Again, we are talking about 0.7 B's.

It's not a huge number.

Your point is -- one of the points you made was -- and they're drilling a lot of different kinds of wells across a big area, and there is a lot of variability.

It is a big program, growing really fast with a lot of variability.

They have processing contracts and everything just like we do.

We don't get timely data, as timely a data on non-op stuff as we do on operated, and that is not their fault, that is just the nature of the beast.

When something is growing 20%, 30% a quarter, and your data is two months behind, it is pretty easy to not get your estimates right.

That is not an excuse, but it is what it is.

That is helpful.

Just one more thing on the production breakout.

Mid-Con saw a little bit of a dip I guess second quarter to third quarter, more in line with where the first quarter was.

Do you expect that Mid-Con is something you are going to be able to grow at this point with the number of rigs you have, or is that -- you are expecting that to be stable to slightly declining at this point?

If you think about our Mid-Con assets, there is the Woodford, which we have not been drilling in since year-end last year, and the Granite Wash.

At the first part of the third quarter, we only had one rig in the Wash, and we picked up another -- really even two rigs in the Granite Wash will only drill about 12 wells a year, I think.

If we want to keep that asset flat, given the underlying decline of our vertical Granite Wash wells, our deeper stuff in the middle of Oklahoma, deep Anadarko, and the Woodford decline, if you want to offset all of that, we need a higher capital spend in the Mid-Continent.

We are going to be stepping up some.

Our Granite Wash program next year, hopefully to a three-rig program.

In general, we can't -- we cannot grow every single region given our current capital spend plan.

So, I think what you'll see is that Mid-Con is going to be essentially flat for most of 2012, even though we put a three-rig program in there.

Once we get done drilling the Haynesville, that stuff will start declining as well.

Most of the growth going forward is going to be in the Eagle Ford and the Bakken.

We certainly hope to see some growth in the Permian and Niobrara assets next year as we start to spend more money on those oilier areas.

Mid-Con is going to be flat to slightly down, I think.

Okay.

That's very helpful, guys.

Thanks for the time.

Thanks, Nick.

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

I apologize if I missed this earlier, but can you talk at all about the impact of down spacing on how you all would be booking reserves in the Eagle Ford over the next couple of years, and when that might start to show up in year-end bookings?

Well, there's a number of factors.

When you start looking at booking PUDs -- I'm not sure down spacing is necessarily as big a driver as the five-year rule and the rate at which we convert PUDs will be, for us.

You really have to look at, in a development at this stage, we are not converting PUDs at any high -- at a very high rate.

In fact, almost none.

You need to look at what your PUD conversion rate is, your development plan, and the five-year rule, and ask yourself -- how many PUDs will I really be able to drill in a five-year period.

I'm not really sure that the spacing matters that much with respect to that development plan and PUD conversion rates.

We're not going to book a whole bunch of PUDs and let them sit and have to roll them off at the end of five years because we did not drill them.

I don't know that spacing necessarily -- I'd have to think through it a little more, but I don't think that spacing necessarily drives your PUD bookings as much as your PUD conversion rate at whatever spacing it is, if you understand my meaning.

Yes, I do.

Do you have a feel for any kind of theft when you book spacing or down space wells yet?

In terms of would you book a down space well at some percentage of an existing well?

That we don't know yet.

I think that is part of what we need to figure out, and our spacing task is, what would that -- it's essentially an interference number.

What would we ascribe to a down space well.

Would that interference, at that level of interference, does it make sense to drill the well as opposed to just maintain the current spacing?

That is really what the spacing pilots are all about.

I would say -- we have seen some interference when we have drilled at 625s.

Whether that interference is substantial enough to mean that the incremental capital spend is not worth it or not, I think is what we still have to understand.

I've tried to be conservative, and I think appropriately so, especially in the Galvan area, on this call.

And help people understand that's the area you should be the most concerned about because it has more porosity and a larger drainage radius.

If you're going to see interference, that's probably where you are going to see it.

At this point, I think we need to wait until year end to get a little more data before we are conclusive about what we see there.

Okay, thank you very much.

Your next question comes from the line of Ryan Todd with Deutsche Bank.

Good morning, gentlemen.

A couple of quick questions for you.

One, what is the right way to think -- I know you have, obviously -- the balance sheet is strong.

What is the right way to think about the potential for divestitures going forward, in terms of funding gaps for the next year in 2012?

I would say, Ryan, at this point in time the major transactions and divestitures are behind us or teed up to close.

Having said that, every year we will look at the entire portfolio and identify properties that we think may be timely to take to market.

But right now I would say we've got the major transactions either closing or behind us.

Great.

Then, one more on the realization side on liquids in the Eagle Ford, what are you seeing on realizations?

And as you look forward over the next three, six, 12 months as infrastructure improves, what trend do you expect, particularly in crude pricing in the basin?

I don't know that we have a great number for you.

I think we have said repeatedly that we think people need to be careful about ascribing a large value to the current gap between Gulf Coast and Cushing pricing.

Because we think that's going to converge over time.

If you believe WTI is going to stay low and Gulf comes toward it, then that would be a decrease in your margins.

I think that, but I do think those numbers are likely to come together over time.

Other than that, the Bellevue pricing for NGLs is much better than Conway right now.

I think ethane prices are good.

I don't think we see any big changes out there.

I think our marketing guy tells us that right now in south Texas if you are comparing to NYMEX oil, you can think in terms of about $11.

That includes quality, that includes transportation.

And that is improving, as Jay just said.

Okay, so it is improving relative to WTI, but you expect the gap to close going forward, at some point anyway?

We have never believed that that big gap between Louisiana pricing and Cushing is sustainable over time.

People will figure out a way to make that go away.

We don't sit around thinking that we are going to get a big premium for this oil for the long haul.

But if it did stay wider, assuming the gap stayed wider, would you expect to start pricing closer to -- an LLS adjusted for transport or -- ?

I think, yes, if it stays wide, we would probably get some benefit from that, and Wade just gave you the numbers about where we are at right now and potentially that could stay there.

Again, I'm not suggesting -- I don't know which way those gaps close.

Does WTI move up or does the other move down?

But I don't think it's reasonable for people to assume that an arbitrage, a potential like that can last for years and years and years.

Right.

Okay.

I appreciate the help, gentlemen.

Thanks.

Your next question comes from the line of Gil Yang with Bank of America.

In answer to a previous question, you talked about the Granite Wash.

You would like to grow, but you probably wouldn't really grow, and you talked about growth in the Eagle Ford and Bakken.

Does that reflect your relative views on what the returns are in the areas or are there operational lease-holding issues that drive those differential growth rates?

Our Granite Wash position is entirely held by production.

We can do pretty much what -- nothing or anything that we like.

In fact, the returns on the Granite Wash are very competitive.

We would love to spend -- we would like to spend more money.

As we move toward 2013 and we get toward our cash flow, which our goal has been, repeatedly we have said that we wanted to get to double-digit growth within our cash flow in 2013.

Certainly as we get to that point, our anticipation is that we will start ramping our Granite Wash program, our Permian Mississippian programs, other programs, oily programs at that point, where we have a little more discretion.

Right now we have to drill what we have pretty much have in the budget.

And that just means we can't throw an enormous rig program into the Granite Wash.

I would also say the Granite Wash is different.

We say this all the time.

It is not one big thing that you can just go drill a zillion wells in that are all the same.

We are probably operating in at least six different washes that are stacked on top of each other, each one of which has individual risks, and we need to understand that.

In fact, going slowly and playing off other people's successes, and doing some experimentation and exploration ourselves, really gets us set up for a larger rig program going forward.

I don't think we are giving up a lot of value by going a little slowly.

I think we are actually derisking the play for ourselves.

And it certainly puts us in a position that when we have additional cash flow, we have someplace to go with it that is low risk and very high returns, which I think is a good story.

Okay, great.

In terms of the Bakken, you talked about cost inflation a little bit.

Can you maybe comment on -- and maybe the answer is what you are completing and what you are doing in completions, but why is the inflation seemingly higher in Raven than in Gooseneck?

Gooseneck is much shallower.

I'm not going to get the depths exactly right here, but it is a significantly shallower play.

And well costs are much lower, several, $2 million or $3 million lower.

We are actually pumping a pretty large frac jobs at Gooseneck as well.

Not as large, probably, as at Raven, but we have been stepping up our frac count and volumes in the Gooseneck area up there as we have gotten less worried about water production.

But it is really just the shallow depths at Gooseneck that allow you to drill at lower costs.

I'm not saying why it is lower cost.

I'm asking that the pick-up in well costs, second quarter to third quarter, seemed to be higher in Raven than in Gooseneck.

I think we have upped our frac count in fluid volumes in Raven more so than we have in Gooseneck, and that is the difference in cost increase, if you would like.

It is also higher pressure, so you get higher pumping pressures.

The costs of the jobs are higher.

Okay, and so proportionately, the well cost in Raven is borne by more on the completion side than in Gooseneck?

That is probably true, although you have -- again, you are drilling to deeper depths.

Drilling is the relatively inexpensive part of these wells anymore.

Completions is the big ticket.

When completion costs go up, that obviously drives the numbers more.

How much of your program of the inflation that you are seeing do you think is because a lack of -- relative lack of scale in the play?

Do you think you need to be bigger to get more cost efficiencies or to be more immunized against the inflation?

Or are you large enough to see those efficiencies?

I really don't believe that -- I think the operation we are running with about a three-rig program, we have fracs lined up for all of that, we have a frac contractor that pumps all of our jobs for us, very efficient operation.

I really don't think that doubling that would change our well cost substantially.

I think there is a number out there that I think you need to get to.

If you were running one rig and you only had a frac crew every couple of months, I think that is one thing.

We have a pretty consistent program at the size we are at.

I don't think there are huge cost savings associated with scale beyond where we are right now.

I may be wrong a little bit on that, but I don't think you would see big cost increases -- decreases if we were bigger.

Okay.

Fine, thanks a lot.

I'll comment -- we drill with a lot of non-ops up there who are a lot bigger than us, and their costs are higher than ours, so I don't see us drilling more expensive wells than our peers.

Okay, great, thanks.

Our final question will come from the line of Andrew Coleman with Raymond James.

I have a question for you on the -- looking at the different well sizes there that the acreage spacings in Galvan Ranch -- so I guess looking at 150 acres and 120 acres roughly.

What do you think -- what do you risk the acreage at for your forecast?

Are you asking how much of the acreage we think we will drill out in Galvan?

Is that what you are asking?

Yes.

I think 100% of the acreage in Galvan we will drill out.

Now, the southern end of it is dry gas and it won't drill out today.

But I think in terms of productivity of the acreage, I think it is all going to drill out.

Okay, and across the rest of the play, do you think it is also similarly high kind of chance of success that you will drill it out?

I think as you get up into the northwest, you have to start to maybe think -- maybe some of all of that won't.

It just depends.

We haven't drilled a lot of wells over on the very far west end yet.

I'm not sure I would use 100%.

That is the number for all-at.

But I think a lot of it is going to drill out, and we've said that repeatedly.

We haven't drilled a dry hole in the well -- in the play yet.

We drilled some wells we weren't 100% proud of, but I think over time a lot of this acreage is going to drill out.

Okay.

Then coming back to the reserves question, I think was asked earlier.

Do you think or have you given much thought to what the numbers might look like?

Should we think about F&D costs declining this year, or being on par with what they were last year?

We don't really guide on F&D.

F&D is almost completely a function of how many PUDs you book, and I just don't know that yet.

That is dependent on so many things that I don't think we will try to guess at that.

Okay.

Andrew, we will be kicking off our reserve process here shortly.

We typically work that through December, and then have the numbers ready for public consumption early next year.

Okay, that sounds fine.

I will probably use a rough assumption of kind of similar to last year, and we'll get in there and count the wells at a later date than probably closer when you guys do it.

And then, as you look at your drilling up there in the Bakken, other operators have talked about some of the multiple zones of the Three Forks.

Do you have any plans at this point to test those?

And do you have those on your acreage?

I haven't had a conversation with our folks recently about multiple Three Forks zones.

I think it's pretty well known that we are drilling or about to drill a Three Forks well down in Stark County.

We have permits out there for that.

But in terms of multiple zones in like the Raven area, I haven't had a discussion with the folks about that.

I want to go back on the reserves question just a bit, just to make sure it's clear.

The reason the banks raised our borrowing base after mid-year at a point with lower pricing than we had before, was because our reserves are going up.

I do not want people to think that we don't know what our reserves are.

But we just don't guide on that because there's just too much PUD risk in doing that at this point in the year.

Right, and typically in the revolver's what -- are you capped at something like 10% of PUDs can be used for the revolver?

So, essentially you are looking at a PDP kind of case for RBL's?

There is no cap.

As is the case with everyone's borrowing base, the PUDs are not given much value at all in determining the borrowing base.

Okay, thank you very much.

Thanks.

I'll now turn the call back over to our speakers.

Do you have any closing remarks?

Yes, this is Tony.

First of all, thank you all for joining the SM Energy call this morning.

We do appreciate your interest in our Company.

We're excited about where we are, and the plans we have set about that we have in front of us.

And we look forward to our next update with you in February.

Thank you for calling in.

Thank you for participating in today's conference call.

You may disconnect at this time.