SM Energy Co (SM) 2012 Q4 法說會逐字稿

Good morning, my name is Bonnie, and I will be your conference operator today.

At this time, I would like to welcome everyone to the SM Energy fourth-quarter and full-year 2012 earnings conference call.

(Operator Instructions)

Thank you.

I'd now like to turn the conference over to Mr. David Copeland, Senior Vice President and General Counsel.

Please go ahead, sir.

Thank you, Bonnie.

Good morning to all joining us by phone and online for SM Energy's fourth-quarter and year-end 2012 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 that 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 on our website for this call and the Risk Factor section Form10-K filed earlier today.

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

Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in 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 important discussion of these terms, and the special risk and other considerations associated with these non-proved reserve metrics.

Company officials on the call this morning are Tony Best, Chief Executive Officer; Jay Ottoson, 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, the Company's Senior Vice President and General Counsel and Corporate Secretary.

I'll turn the call over to Tony, now.

Thank you, David.

Good morning, everyone, and thank you for joining us for our fourth-quarter and year-end 2012 earnings call.

I will make a few introductory remarks, and then, Wade and Jay will provide their respective financial and operational reviews.

We'll be referring to slides this morning that were posted on our website last evening.

Beginning on slide 3, I'll cover some key messages that I think are important to take away from today's call.

Let me begin by saying that 2012 was a record year for SM Energy.

On the reserve front, we increased proof reserves 40% to nearly 1.8 TCF equivalent, or 300 million barrels of oil equivalent.

Our reserves at the end of 2012 are now 53% liquids.

Our drilling reserve replacement and F&D metrics were some of the best the Company has ever posted.

Drilling reserve replacement was 411%, our drilling F&D was $1.74 for MCFE, and we have also increased our R/P ratio.

It was also a record year for production.

Which was capped off with a quarterly production record, as well.

Annual production grew 29% in 2012 to a new annual record of 219 billion cubic feet equivalent or 36.5 billion barrels of oil equivalent, and we hit a new quarterly production number of 60.7 BCF equivalent in the fourth quarter of 2012.

We executed well on our core development programs in the Eagle Ford and the Bakken/Three Forks in 2012.

Jay will discuss this in more detail shortly.

During 2012, our team's did a good job of advancing new venture programs that we hope will be the next legs of growth for the Company.

In the Permian, the Mississippi lime continues to be encouraging to us, and we are evaluating a number of shale intervals that are on our 120,000 net acres that we believe are prospective or new and significant shale development.

Last night, we announced that we had almost 100,000 net acres in East Texas counties, north of Houston that could be prospective in multiple formations.

Bottom line, 2012 was another year of strong performance with several key records notched for the Company.

And we are remaining focused on growing long term value for our shareholders.

I'll now turn the call over to Wade for his financial update.

Thank you, Tony, good morning.

I'll begin on slide 5 and recap our quarterly performance.

Our adjusted net income for the quarter was $30.4 million, or $0.45 per diluted share, and our quarterly EBITDAX was nearly $300 million, both of which were significantly above consensus for the quarter.

With regard to our performance against guidance, our average daily production of 660 million cubic feet equivalent per day, or 110,000 barrels of oil equivalent per day, was 6% above the midpoint, up 625 to 658 million cubic feet equivalent per day.

The guidance range that we provided.

On the cost side, we came in below the low end of guidance on most metrics, with the remaining items coming in within our guidance range.

LOE was slightly below the low end of the range, and transportation came in the middle of guidance.

With respect to production taxes, we had some severance tax incentive rebates that resulted in us coming in slightly lower than our guidance.

Last week, cash G&A was lower than guided, due primarily to annual bonus accruals coming below target, largely due to the proved property impairment we recognized in the fourth quarter.

This $170 million non-cash impairment of proved properties related to Wolfberry assets in our Permian region due primarily to negative engineering revisions on those assets.

As a reminder, the accounting rules require that assets be written down to the discounted value of its future net cash flows, which explains the size of the write-down.

On to slide 6, I'll quickly discussion our financial position.

Things remain pretty quiet and simple on our capital structure.

There were no new debt issuances or other financings during the quarter.

Our debt to book capitalization rose slightly, ending the quarter at 50%, and our debt to trailing 12-month EBITDAX stands at 1.4 times.

Our long term debt at the end of the quarter stood at about $1.44 billion, $1.1 billion of that balance is termed out with the earliest maturity being in 2019.

Turning to slide 7, I'll discuss our secured credit facility.

At the end of the quarter, we had $340 million drawn against the revolver with nearly $660 million of undrawn commitments.

Borrowing base currently stands at $1.55 billion.

We will go through our regular re-determination with the bank group in March, and I'd be surprised if we didn't see an increase in our borrowing base given the growth in improved reserves.

Our bank commitment amount remains at $1 billion currently, and we will evaluate whether to increase that in conjunction with the re-determination process.

We have added some more commodity hedges recently.

You can see a summary of our most current hedge positions included in the Appendix to the slide deck.

And detailed hedging information is included in our Form 10-K, which was filed earlier this morning.

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

Thank you, Wade.

Good morning, everyone from snowy Denver.

I'll start on slide 9. As Tony said, 2012 was a great year from a reserve standpoint.

I'd like to quickly walk through the reserve roll forward for 2012.

We had 900 BCFE of reserve additions in 2012, 85% of which came out of our Eagle Ford Shale Program.

Divestitures for the year were approximately 17 BCFE, three-quarters of which is related to sales of non-operated properties in our Rocky Mountain region.

We had 92 BCFE of negative performance revisions in 2012.

About half of this related to aged Woodford puds in our mid-continent region that we know longer plan to drill within the five-year time frame, as required by the SEC 37 BCFE of performance revisions relate to changes in estimates for Eagle Ford puds.

Due to the fact that we now have significant numbers of producing wells in portions of our operated area, at year-end 2012, we moved to a statistical reserve booking methodology in the operated Eagle Ford.

This methodology in conjunction with data indicating geological continuity across the acreage resulted in higher numbers of puds being booked, but at a reserve level slightly lower than some of our previous individual well bookings, which were made based on the average of direct offsets.

We have accounted for that difference on those individual wells by showing a negative revision because that's how we understand that the disclosure should be made.

If you actually net our Eagle Ford revisions against our Eagle Ford pud adds of 491 BCFE, we actually increased our Eagle Ford pud bookings by 454 BCFE at year end.

We now have 154 puds booked for SEC purposes in the operated Eagle Ford at an average EUR of 4.5 BCFE per well.

In the Permian, as Wade indicated, we took a downward reserve revision on our Wolfberry assets.

Gas/oil ratios and oil declines are proving to be higher than we expected.

We had 73 BCFE of negative price revisions at year end, which related principally to natural gas weighted properties across the Company.

After subtracting 219 BCFE of production, we ended the year at approximately 1.8 TCFE of proved reserves.

This is an increase in proved reserves of 40% year over year, and liquids are now more than half our proved reserve base, 53% to be precise.

Our pud percentage increased from 33% to 43%.

However, we still only have roughly two years of drilling booked as puds in the operated Eagle Ford and less than that in a [non-op], so we have a lot of room remaining to organically grow bookings within our existing portfolio.

Slide 10 shows reserve metrics over the last five years.

Drilling F&D, which is excludes revisions, decreased to $1.74 per MCFE in 2012, and drilling reserve replacement increased to 411%.

These metrics reflect both the maturing of our portfolio that we have been building over the last few years, and improvements in our operations, and I would like to acknowledge the outstanding efforts of our employees during 2012 in this regard.

Moving to slide 11, production for the fourth quarter of 2012 averaged 660 million cubic feet equivalent per day, a 6% increase from the third quarter.

As the graph at the bottom of the chart shows, we steadily increased our percentage weighting of the liquids throughout the year.

Our producing liquid percentage is headed in the same direction as our reserve percentage, and we still believe that we will be producing about 50% liquids by year-end 2013.

Before I get started on slide 12, I want to make sure everyone is aware of all the data we provided last evening in the Appendix of the Investor Relations presentation we posted to our website.

In that Appendix, we updated the resource potential tables that were provided last year for both the operated Eagle Ford and our Bakken/Three Forks programs.

Additionally, this year, we are also providing some more detailed information on expected case type curves, and well economics for wells in areas where most of our drilling will occur in 2013.

I'm not going to cover those slides in detail in my prepared remarks this morning, but I do want to make sure that everyone is aware that that data is out there.

In the operated Eagle Ford, production increased 11% in the fourth quarter from the third quarter, and 50% fourth quarter over fourth quarter.

We made 23 flowing completions during the quarter, 30% of the total of 77 flowing completions we made in the area for the year.

Total crude reserves at year-end 2012 in the operated Eagle Ford increased 127% over year-end 2011.

Our acreage position now stands at approximately 145,000 net acres.

We did decide to let a small amount of acreage expire in the southern drier gas portion of Apache ranch during the fourth quarter rather than drill uneconomic wells to hold the acreage.

One significant change which is reflected in our resource tables is that we are now assuming that a large portion of our Briscoe Ranch acreage will be developed at 52-acre spacing versus 72-acre spacing previously assumed.

This change in assumption is a result of spacing pilots that we completed this last year.

We now believe that we have 5.8 trillion cubic feet equivalent of total resource potential at year end 2012 associated with approximately 1,500 drilling locations on our operated Eagle Ford Shale Program.

This is an increase of approximately 500 billion feet equivalent from last year.

I'm now on slide 13.

In the non-operated Eagle Ford Shale Program, production increased 10% over the third quarter to the fourth quarter.

Proved reserves increased 122%, to 214 billion cubic feet equivalent, or 36 million barrels of oil equivalent.

We expect Anadarko to operate eight drilling rigs in the program in 2013.

Given improved efficiencies, at current levels of activity, we believe that we will be carried on substantially all the drilling and completion activity in the program, and that they will accomplish about the same level of activity that they would have accomplished with 10 rigs just not too long ago.

I'm now on slide 14.

Net production in our Bakken/Three Forks Program in the fourth quarter increased 8% from the third quarter and 40% fourth quarter over fourth quarter.

Proved reserves in the north Rockies subregion, which is largely composed of our Bakken/Three Forks program increased 13% in 2012 to 329 billion cubic feet equivalent.

Our acreage count in our Bakken/Three Forks focus area in North Dakota decreased slightly to 81,000 net acres, as a result of some divestitures of non-operated properties, as I mentioned earlier in the year.

We are currently operating four rigs in our operated program, and we anticipate swapping two of those out for a more-efficient walking rig to do pad drilling later this year.

On slide 15, we provided update of our Treadway Mississippian Lime program in the Permian Basin.

We have roughly 66,000 net acres in the play.

The Company's currently operating two drilling rigs.

Excluding the results from two wells that had drilling or completion problems, the average 30 day rate for wells with sufficient data is 475 barrels of oil equivalent per day.

We are making progress on our drilling costs and drilling some longer lateral wells, which we hope will be even more successful.

Next two slides pertain to the Company's new ventures efforts.

In the Permian Basin, we now have about 120,000 net acres that we think have shale potential.

We're monitoring the activity of several offset operators southeast of our Treadway position who are targeting the Cline Shale.

As previously discussed, we've drilled some tests of the Leonard Shale elsewhere in the Midland Basin.

We do plan to provide an update on those tests a little later this year once we have a bit more well data.

I'm now on slide 17.

Last evening, we announced that we built a roughly 95,000 net-acre position in East Texas counties north of Houston.

There are multiple intervals of interest in that area, and we plan to provide an update on this program later this year, as well, after we've completed the bulk of our testing program.

Slide 18 shows our expected 2013 capital budget, which is unchanged from what we announced in mid-December.

I think it's important to point out that 90% of our capital program is focused on programs in the big three basins of the Eagle Ford, Bakken/Three Forks and Permian.

With economics driven by oil and NGL production.

On slide 19, we show our production outlook through 2015.

I should note that since we issued our production guidance for 2013 in December, we have started rejecting some ethane in our operated Eagle Ford program, and from comments made by APC this week, it appears that they may be making the same election with some of our non-op production.

Rejecting ethane will reduce reported liquid volumes, while increasing gas price realizations.

Our previous guidance did not assume any ethane rejection, but considering our outperformance in the fourth quarter, we are reiterating our 2013 full-year guidance of 255 to 267 billion cubic feet equivalent.

In December, we also indicated that we think we will grow about 15% per year in each of the following two years.

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

Thanks, Jay.

And also special thanks to all SM employees, many of whom are listening to our call this morning.

Their hard work and commitment is responsible for our ongoing success.

Our strong 2012 performance, and an exciting array of significant liquid-focused development projects, along with a growing slate of debenture opportunities, I am very bullish on SM Energy in 2013.

With that, I'd like to turn the call over for your questions.

(Operator Instructions)

Brian Lively, Tudor, Pickering, Holt.

Morning, Brian.

My question really is just around strategy.

Over the last few months, you have provided, I would say, better visibility on the underlying assets in terms of the reserves, the long range guidance, the ops updates, execution, et cetera.

That said, if you look at the multiple compressions since 2012, it's been pretty extreme.

And so my question looking forward is, does there come a point when Management and/or the Board starts contemplating maybe other avenues to close this apparent gap between the equity and the asset value?

Brian, this is Wade.

I'll take a stab at that first, and let the other guys chime in if they want.

We certainly recognize that.

We are focused on execution first and foremost.

I would say we consider a lot of things when we are allocating capital and stock buyback, which, I assume, is at the top of your list of what you are asking about -- is always in those decisions and discussion.

I will tell you right now, we have a multitude of high-return projects that we're looking at.

You can see the results, and we believe that, that's the place to invest the capital right now, to grow long-term shareholder value.

So that's where we are right now.

But it is part of the discussion, and we'll continue to look at all possibilities when we are looking at capital allocation.

Brian, this is Tony.

We obviously focus on our fundamental business and our execution, and we do monitor the multiple, and that's been a bit of a frustration because we believe that we're executing and hitting on all cylinders right now.

But we'll continue to progress with our programs, which are, as you've seen with the latest release, performing very nicely; as well as adding to that with our new ventures program.

So the key to me is execution and continuing to look at replicating the success we've had over the last couple of years.

With that, I should also note that you would expect to see R/P increasing going forward.

Right.

Really appreciate the comments, there.

Just maybe one follow up on that front.

I guess the question then really just becomes, if the market doesn't appreciate the value that's being created by you guys.

We've seen a lot of companies now trying to pursue alternative mechanisms to create that value; and I'm just wondering, aside from the buy backs, what are some other option that you have considered or are considering?

Well, any given time, we take a look at a pretty wide array, variety of options to increase the value of our stock and the value for our shareholders.

But at the end of the day, our intent is to continue to focus on our fundamental business.

But those options we review from time to time; but I think you have to be careful not to take your eye off the ball.

And right now, our key priority is execution in the key plays where we are.

If we do that, you'll see the other metrics improve over time.

I guess -- this is Javan -- I'll just add, obviously we look at each of our assets.

Tony really focuses us every year on looking at the portfolio, and what we can do in terms of optimizing our portfolio to generate more value with that.

And that is another thing that's always on the list, is what is out there that we own that somebody else might thinks more of than me or might be willing to give us more value for and that's certainly something that's in the mix, as well.

But I think in general, we think of it in terms of, what can we do to generate more cash that would help us to invest in the business that we understand, which is the business of oil and gas.

Yes, I appreciate the comments; I was just more asking, assuming you do all that and the market still doesn't value the stock adequately.

But I understand the comments.

Just one follow up, clean up item -- in terms of the ethane rejection, how much of that have you guys now -- of what volumes have you layered into your guidance?

Well, at this point,when you look at our own production in the operated Eagle Ford, there's probably about 2 to 3 Bcf right now at current ethane rejection levels, that you may want to consider to be additive to our guidance, I guess, if you think about it from that standpoint.

We're basically eating that in our current guidance.

It's a little unclear to us exactly now how much we should be assuming for what APC might do, because they talked about this on their call.

And clearly, as we get into the second half of the year, as our volumes continue to grow, that number could get bigger.

So there's quite a bit of uncertainty.

It is a monthly election that we make.

At current pricing, I think we would continue to make that election the way we've been making it, but that could change.

There is a certain amount of uncertainty around these numbers; but at current levels, again, it's probably 2 to 3 Bcfe kind of numbers for the year.

Thanks, Jay.

Welles Fitzpatrick, Johnson Rice.

The rejected gas -- is that coming out maybe at 1100 BTU, and does that present any issues on the midstream side, especially with Anadarko doing the same thing?

Well, I don't know the exact BTU content, but it doesn't present any issue with rejection, no.

And the 2 to 3 [BUs]-- on the guidance -- that's, I suppose that's a little bit low relative to the 91 million a day that you guys were doing in NGLs from the Eagle Ford.

Can you remind me --are you guys about 30%, 40% ethane in that NGL stream?

Yes, each one -- I guess the reason it's low is because we're not rejecting on all of our product, and we can't reject all of it.

There's several different contracts; we have elections on two of the three, and even the ones that we can reject on, you can't go in and reject all the ethane from that stream.

You are always going to retain some ethane as a liquid product.

If you cut too deep, obviously, you'll start rejecting propane and higher value products.

So there's always some ethane that is going to be sold as a liquid.

But it's a small -- I think the total number was about 9% of our total ethane production was rejected here recently in the month of January.

So it's not a huge number relative to the total; but again, as we go through the year, and our volumes grow, that number can get bigger.

So there's a certain amount of uncertainty here, at this point, given that it is a monthly election.

Okay.

Perfect.

And then, two quick questions on the 95,000 acres north of Houston.

Obviously, with permits from Washington up to Freestone and then back down to Jasper, it's a pretty huge area.

Are you guys chasing a multitude of concepts and geographies?

Or is it really focused in on one and two?

And does that 95,000 include any legacy acreage up in the Panola-Shelby-San Augustine area?

No, it does not include legacy acreage.

Yes, there are different intervals.

We're not chasing a whole bunch of different concepts, but there are a number of potential productive intervals in the acreage that we purchased.

And Welles, I would also -- this is Tony.

I would also mention that we are announcing the new acreage position that we've got, but we're still leasing in some cases, so we haven't been completely transparent at this point and wouldn't until we get a few tests under our belt, and we've secured the acreage that we think is available.

Perfect.

Thanks so much, guys -- great quarter.

Thank you, Welles.

Mike Scialla, Stifel.

Appreciate all the information you've provided in the Appendix on the EUR estimates.

Just wanted to clarify -- those EUR estimates I assume include the ethane, assuming that ethane stays in the -- or excuse me, that ethane is extracted?

The basis numbers that are on those sheets, on the economics, assume the level of ethane rejection that we are currently doing, which is that 9% to 10% of ethane.

Those sheets were literally generated this last month; so those, what we call decrements or differentials, were given to us by marketing based on our current numbers.

So it does assume a certain amount of ethane rejection.

Honestly, the economics, Mike, to be fair, doesn't change much, okay?

Whether you are rejecting or not, the revenue stream is about the same anyway.

It's just an issue of whether the liquids get reported as volume or they get reported as increased realization on your gas.

So, it's pretty much an equal trade-off?

Yes, you're talking about pennies here on a gallon of ethane [processed].

Because the processing doesn't really change stuff.

Got it.

Okay.

A question for Wade -- your CapEx of $1.5 billion in the cash flow statement -- how does that reconcile with the costs incurred on the reserves of almost $1.7 billion?

Sure.

There's several differences in those numbers.

A couple of the large ones -- there's like nearly $70 million is G&G costs, which flows through the income statement through expense; but that is something that is required to be in cost incurred, but it's not a CapEx item, if you would.

Also, we make adjustments to our ARO liability, and those are non-cash adjustments.

That was a little over $30 million, where it essentially grosses up the balance sheet.

So, it's a non-cash CapEx item, but it does get reported in cost incurred.

Then there's change in accruals.

The CapEx number that you are referring to, the $1.5 billion, that's a pure cash number, so the cost incurred is accrual-based.

So any changes in accruals from beginning of the year to end of year go in there, and that was a pretty large number this year.

If you just look at accruals and prepaids, all the balance sheet work in capital items, that's around $100 million there.

So I think between those three items, that makes up the difference.

Appreciate that.

Sorry to jump around, but also I wanted to see if you could give more color on the write-down for the Wolfberry wells.

You said it was partially the GOR was higher than you thought, and the steeper decline.

Was that steeper decline, did that have anything to do with the spacing?

Did you start to see interference?

Or was it just, you were surprised on the (inaudible)

Well, I think it does have something to do with the fact that we drilled 20s in some of these wells.

When you do the -- I should probably let Wade do this explanation -- but when you do the impairment calculation, what you are looking at is what are the value of your future revenues.

In general, on these wells, what's happening is the GOR is coming up, and the oil rate decline is increased over what we expected.

Part of that is because the GOR is coming up, right?

And these wells are essentially shifting the reservoir quality around such that the gas is more mobile than the oil.

It's a relative permeability effect, we think.

So what happens is your future production looks lower and gassier than you expected, and of course, gas prices have been very low.

So, it's a combination of lower oil and relatively higher gas that drives a lower future revenue stream.

Then when you'd look at that future revenue extreme and compare to it to your book value, that's the test that is made at a pv0.

You look at a pv0 test of your future revenue, so the sum of your future cash flows against your book value.

If it fails that test, then you have to write it down to the discounted value, which is a much lower value than the pv0 number, and that's why you end up with a big number when you do the write-down.

Okay.

I guess, bottom line, you do think that the 20-acre spacing did have some impact though, as well as the GOR changes?

Yes, I think so.

Okay, thanks.

And then, last one -- the drilling problems you experienced on those two Mississippi Lime wells, could you discuss those a little bit more?

Yes, one of them we actually ran into a karst.

We were drilling along the top of the top of the lime and drilled into a shale-filled karst.

If you are familiar with limestone geology, in a lot of cases, you get that Carlsbad Cavern kind of effect sometime along the top of these formations, as water moves; and we drilled into a karst that was full of shale and we got stuck.

And we couldn't get unstuck, and we ended up have to terminate the lateral short.

The other well looked like we fracked our heel stage into some water-bearing interval, and the well is making a bunch of water.

We hope we can get that shut off, but at this point, we haven't been able to accomplish that.

So a couple drilling problems.

What did we lean from that?

Well, we're drilling deeper in section to get away from the karst.

We've also changed to oil-based drilling fluids, which we think helps keeps those shales off of us.

But if you look at the last couple wells we drilled -- and I am knocking on wood as I say this -- we drilled some longer lateral wells very successfully, with no problems.

And I think we have learned a lot from our experience, and we continue to get better.

I guess a follow up to it.

Does seismic help you with the karsts at all in terms of identifying where those are?

Well, it does.

And we knew when we drilled that well that there was some karsting there.

It's hard to tell on a seismic how bad it is.

You can see some wiggles there, and think -- well, okay, I'm not sure exactly what that is, but it could be a karst.

We really thought we could drill through it, and we need to be able to drill through some of these.

And that's why we went to oil base, to develop all the acreage, so we had to drill through one at some point to see how it went.

We really think moving to oil base here is going to help us a lot in terms of dealing with the shales that are in those karsts, and I hope we will be able to develop most of the acreage with that technique.

Great, thanks -- nice quarter.

Thank you.

Stephen Shepherd, Simmons.

I was wondering if you could talk a little bit about the condensate market in the Eagle Ford, and more specifically, how much of your Eagle Ford liquids production would be considered condensate?

And then, how those barrels price relative to black oil in the play?

I anticipated this question, because there's been a lot of talk about condensate.

I will tell you that we have not experienced -- let me start by saying, I would characterize almost all the oil that we produce in the Eagle Ford as condensate.

It's a lighter product than, say, 40-degree or 42-degree oil.

We have not experienced increased basis differentials or had any problems selling condensate out of our Eagle Ford production.

We have a firm transport purchase price contract in place that covers about 50% of our current production, which is tied to the LLS market.

The remaining condensate is sold monthly to several different purchasers with no difficulty.

And at this point, there's sufficient takeaway capacity out of the Eagle Ford.

About a third of our condensate is currently piped from the field to Gardendale; and another third will be connected by about April 1.

Currently, Plains, which is our pipeline that we deliver to, is not delivering directly into a downstream pipeline, but we anticipate that starting in March of 2013.

We do have a contract, as I said, where about 5,000 barrels a day firm on LLS pricing basis.

Right now, most of that oil is being trucked out of Gardendale and the field until that downstream pipeline is connected.

A number of the purchasers are moving condensate in other ways -- long haul to Corpus rail, injected in neighboring pipelines, whatever.

In general, when we sell at Gardendale, we net back about $2 to $3 more than we do if we're selling in the field.

It is true that condensate production is going to be going up.

Right now, that production is essentially pushing out waterborne imports.

And at some point in the future there may be some downward pressure on pricing.

We haven't seen it to this date.

Okay.

That's great.

And given that your oil realizations came in stronger this quarter, is it fair to assume that your expectation is that, that level would persist into the future, given midstream buildout and so on and so forth?

You know, we have always advised people to use a small discount to WTI when calculating our realizations in South Texas.

We are benefiting from the higher LLS pricing right now, but if you're building a long-term model, I would still probably use something like a $5 discount to WTI.

Okay.

That's good.

And one more if I may.

Would you all ever think about doing a JV in the Permian?

You know, we think about different options for funding our program all the time; and those kinds of considerations, as we mentioned earlier, we have options for selling assets, we have options for doing JVs, we look at all the options for doing this.

You have to make judgments about when have you proved up enough to realize the maximum value from a joint venture.

That's a critical aspect of when you do the timing of that; but certainly, we did a big JV in our Eagle Ford a couple years ago.

I think it added a tremendous amount of value to the Company, and we would look at doing it again.

Okay, and one more if I may.

In the Granite Wash and Niobrara in 2013, what are your plans for those areas?

We really don't have any Niobrara drilling in the program this next year.

We've pretty much tested our acreage in the Niobrara, and have concluded that there's not a lot of potential there.

We are at looking at other intervals in our acreage in Wyoming.

Granite Wash, right now, we have two rigs running.

We are going to be moving down to one at the end of the first quarter, and we are really focusing on the oilier Hogshooter intervals there, for the remainder of the year.

Okay.

That's all I have.

Thanks so much.

Thank you.

Subash Chandra, Jefferies.

Hey, good morning.

Could you review the current status of infill pilots you might have ongoing by area?

Subash, this is Javan.

We're pretty well done.

We've concluded that in that northern Area 1A that we show in the Appendix, that we're going to go down to 52-acre spacing.

If you look at that -- maybe I should just refer you, frankly, to the Appendix; it lays out spacing for every one of those areas.

Essentially, our spacing pilots are concluded.

Those are what we think is going to be the development plan for the field at this point.

Yes, and the Miss Lime, if you had to project -- I know it's early -- but if you have to project IRRs there, how do you think they would compare with Eagle Ford or Bakken?

Well, I think it's pretty clear we intentionally did not make projections of IRRs in the Appendix, for the reason that it's still too early to do it.

I will tell you we're not going to drill anything that's not competitive in our portfolio over a period of time.

It's still real early in the program.

Right now, I would say it's not competitive with the Eagle Ford, the best parts of the Eagle Ford; but I hope it will be as we get on with longer laterals and improvements in our drilling costs.

Right.

Because, obviously, the Eagle Ford and tight curves there has a beginning starting point of 40% IRR.

It's pretty compelling stuff, so I was curious, if that becomes sort of your threshold requirement, or you, as an organization, you would be willing to pursue something with for far more return than that.

Our return hurdle is a 1.2 discounted present worth to investment ratio, which is about a 25% forward-looking rate of return, so we expect everything in our development portfolio to make better than 25% numbers -- around mid-20%s, okay, for long-life projects.

The Eagle Ford is a great asset, and a lot of those wells are great, but it's not going to last forever, either.

In this business, you are what you started drilling three or four years ago, and we can't close our eyes to the fact that three or four years from now we need more inventory.

We got to grow the Company, and, certainly, if we can find projects that will exceed our hurdles, we would love to figure out ways to keep those in the portfolio.

We may not go whole hog drilling in the Mississippi, and we are not going to throw five rigs in there, but that doesn't mean we're going to let all the acreage expire, and then, have nothing in the pot when the Eagle Ford ends up -- once we're done drilling Eagle Ford, either.

You have to maintain the program over the long haul, but certainly, we are looking for projects that will fit in our portfolio rates of return over the long term.

Subash, that's also why we maintain and pursue a very active exploration program.

These new play areas, like the Permian, and now East Texas -- those are the ways that we're going to grow this Company longer term, with success.

Right.

Okay.

And final for me -- can you explain as simply as you can, how does ethane rejection effect field-level economics, say, with or without rejection?

The simplest way to explain it is it really doesn't impact it at all.

It's just revenue, it shows up as revenue as NGLs or revenue as higher gas realizations.

What does impact field economics is what is the relative price of ethane relative to the price of crude oil?

As it drops, obviously, that impacts economics.

But whether it's being rejected or whether it's being sold as NGLs, that difference is negligible in terms of the impact on economics.

Okay.

Or put another way -- so if you -- the premium on the gas versus the loss of the ethane revenue would almost be a complete wash?

You're making it too obvious.

The reason you reject is because you think it's a marginally better economic outcome.

You are going to pay your processing fee one way or the other, generally.

So, we reject because we think we're going to net a little more for the product as gas than we would as ethane.

So it is an economic decision; but honestly, we're talking about things that are literally month to month marketing decisions.

This isn't a big economic impact on the program.

The absolute value of ethane is important, obviously.

Whether it's being rejected or not, we're talking about pennies of difference here in terms of how much you realize.

Okay.

Thank you.

Helpful.

Thank you.

Thanks.

Mike Kelly, Global Hunter Securities.

Was hoping you could give us an update on the timing and really just the comfort level on the coming midstream takeaway capacity additions in the Eagle Ford?

I think the next big slug is an 83 million a day addition from am ETC pipeline in July 1. Just wondering if that's still on track?

Yes, Mike.

In fact, ETC's downstream pipe is already in place; and really, we're just pick up our capacity on that this summer.

Okay, so in terms of foreseeing bottlenecks on the midstream side in 2013 -- they had some issues in 2012.

What's just overall thought there?

Let me make a distinction.

You asked about ETC.

ETC is the downstream pipe, okay?

What you're talking about is really the gathering system, which is constructed for and operated for us by Regency; which, oddly enough, also is owned by ETC, but it is a separate entity.

We are very active in building out our gathering system, and we're adding a bunch of compression; we have new facilities coming in summer.

So far, everything looks to be on schedule.

We clearly are going to be working toward our limit, our downstream limits, as we go forward.

And we're drilling wells and hooking them up and pushing them through there.

There's always risks associated with these major projects, but in general, I think things are going well.

Okay.

Thanks.

And then flipping over to -- well, I guess staying in the Eagle Ford.

If I look at that updated map, in the Appendix section of your presentation, the thing that jumped out to me was the 50,000 acres you have -- approximate 50,000 acres -- in Area A in the Eagle Ford.

It looks like the oil cut jumped up to a pretty high degree -- 38% total production in reserves versus 25% previously.

I was hoping you could talk about that, and then define how many of your rigs are working that Area A acreage?

Yes.

You are talking about the northern portion of Briscoe, and I think last year, we didn't divide those two out.

So, you didn't see the distinction between a northern area and southern area, so that's why it looks different than it did last year.

In general, our rigs are operating mostly in Areas 1A, 1B and Area 3 this year; and those are the economics we actually show in the Appendix.

Okay.

Thanks, guys.

Joe Magner, Macquarie Capital.

I'm just curious if you'd be willing to lay out the budget expectations you all envision to accomplish your 15% growth objectives for 2014 and 2015?

I think the most I could say there would be, it would be a similar program from a budget standpoint, as we are looking at this year, 2013.

The big change, Joe -- and I think we indicated it here -- is that we expect to carry on our [matu] to carry to run out at the end of '14; so '15, CapEx, ideally, would go up.

Everything equal, we don't that bad.

Everything equal, we would have more CapEx in '15.

And then in the Bakken, there's been an ongoing discussion about multiple benches in the Three Forks.

Where do you all stand in terms of assessing the prospectivity of that on your acreage?

We haven't tested any lower benches at this point.

We do have some.

We're a little bit skeptical about whether all those benches, whether you can frac a lower bench and not frac the upper bench, and how much of this is really communicating.

At this point, we're pretty busy with the program we have.

I still consider that to be upside on some of our acreage, and obviously, we are very interested in it.

There are times -- we have cored some of this, and it looked wet to us, but there are some of these intervals that can look wet and end up being productive.

I don't want to discount it too much.

I would say, in a general sense, that we don't have as much acreage in our portfolio that probably has multiple lower benches as maybe some other people do.

So, It's maybe a little less of an issue for us.

Okay, that's all I've got.

Thank you.

Thanks, Joe.

Brian Velie, Capital One Southcoast.

A quick question in the Bakken, just to follow up there.

The last quarter you mentioned that you had seen some pricing improvement by maybe a 5% on it -- I think it was the $8.5 million number per well at that time.

Is that holding true?

Or do you see any additional opportunities there?

Can you repeat the question, Brian?

I'm sorry, I couldn't tell which wells you were talking about.

In the Bakken.

Last quarter there was some cost savings you expected.

I wondered if that was still holding true and if we should be modeling around $8 million per well going forward?

Well, if you go back to the Appendix, we've given you the numbers on what we actually expect; and typically, those numbers are pretty flat year over year.

What's happened is we are spending a little more, putting more stages into our completions.

So I think if you look back there, there's some pretty specific guidance.

We're showing $6.9 million a well for the Gooseneck area, and about $9 million for the Raven, Bear Den, Bakken, Three Forks stuff.

Okay, I see that.

The next one that I had -- with the new Mississippian results, do you think that those results, coupled with some of the drilling focus in the Eagle Ford on that oilier portion, than I guess the whole -- do you expect the production mix will change any versus the guidance that you gave around year end for 2013?

The 21% NGL?

If you'd asked me that in December, I would have said yes.

At this point, given they we are rejecting some ethane, it's a little hard to say exactly where our liquid percentages are going.

I still feel pretty comfortable that we're going to get to that 50% number by year end, but there is some uncertainty just because of the ethane issue.

Okay.

The rest of my questions have been answered.

Thank you very much.

Thanks.

Rudy Hokanson, Barrington Research.

Good morning.

My question is perhaps too simplistic, but you had great success on your F&D costs in this quarter.

And your guidance on expenses going forward has room for -- it looks like it has room for a repeat of it.

But it's still, not assuming that, that would be something that would be ongoing.

And I'm just wondering if the fourth quarter's F&D costs should be viewed as a matter of where you were drilling in your portfolio at the time; if it was something that is more corporate-wide in terms of execution; or if there's something going forward that would imply that costs are necessarily going to up -- all those types of ways of looking at this?

Because I don't want to take away from what you did in the fourth quarter, and I'm just wondering if it's repeatable, or if you're just being conservative in your guidance, which might be the bottom line?

Well, we don't guide reserve additions, number one.

Number two, the fourth quarter is really not the measure of F&D.

It's a full year issue.

When we talk about F&D, we are talking about the full year of 2012 and what our year-end result looked like relative to the amount of money we spent.

And we only report that once a year.

And we only report it once a year.

So we don't report mid-year reserves.

Some companies do, I think, but we don't do that.

In terms of cost, I think we did -- what you're seeing in our results this year, clearly -- to be fair to everybody, we booked more puds than we booked in prior years; and that has a big impact on your overall all-in F&D.

I would say our drilling PDF&D, which is the numbers we really care about internally in terms of developing reserves, did improve this year pretty significantly; and that's a result of drilling higher EUR wells at lower cost, and we're very proud of that.

But most of the benefit you're seeing is a result of the maturation of our portfolio; we've been promising this for a number of years, is when we got to certain point in the Eagle Ford, we would be able to book on a broader basis, book more puds.

As I mentioned in my earlier discussion, we still only have about two years worth of our drilling program booked as puds at this point, and less than that in the non-op.

So there's still a lot of opportunity to organically grow our proved reserve bookings within our existing portfolio.

But again, we do not guide reserves from one year to the next.

Rudy, what I would point you to is the slide number 10, and I'm sure you've seen that in the deck.

I think what we focus on is the ongoing direction of F&D.

And if you look at that, it has continue to improve, as Jay mentioned, over the last five years or so.

I think that points to the improving quality of the portfolio and inventory.

And now I think you're starting to see the impact of that with our latest F&D report.

Okay.

Thank you very much.

Thanks, Rudy.

Jeb Bachmann, Howard Weil.

I had a few questions for you.

First, on the cash flow CapEx situation -- when do you think you'll be cash flow-CapEx neutral?

You still looking at towards the end of this year?

Yes.

We guided that we would be looking at EBITDAX being more than our CapEx by the end of this year, and that's still the case, into 2013.

Okay.

And then looking at some of the non-core assets, I know some of those sales had been pulled in the past year or so.

Any plans to put those back on the table this year?

Or what are you thinking there?

At this point, we don't have any large asset sales planned, Jeb, for the year.

Okay.

And then, last one for me, for Wade -- do you have a pre-tax PV-10 based on year-end '12 pricing versus the average year pricing?

We don't have that, Jeb.

We can look into it, but we don't have that available.

Okay.

Thanks, guys.

Thanks.

David Tameron, Wells Fargo.

Morning, everybody.

All my questions have been asked -- so, nice quarter.

Thanks.

All right, thanks, David.

At this time, there are no further questions.

I will now turn the conference back over to Management.

Thanks for your interest in SM Energy, and for joining our call this morning.

As I mentioned earlier, I'm very bullish on SM Energy in 2013.

So stay tuned, and we'll talk to you again next quarter.

Thank you.

This concludes today's conference call.

You may now disconnect.