David W. Copeland - General Counsel ,Senior Vice President and Corporate Secretary Anthony J.

Best - Chief Executive Officer, Director and Member of Executive Committee A. Wade Pursell - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Javan D.

Ottoson - President and Chief Operating Officer

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Welles W.

Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division Stephen P.

Shepherd - Simmons & Company International, Research Division Subash Chandra - Jefferies & Company, Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Joseph Patrick Magner - Macquarie Research Brian T. Velie - Capital One Southcoast, Inc., Research Division Rudolf A.

Hokanson - Barrington Research Associates, Inc., Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division

Thank you, Bonnie. Good morning to all of you 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 Factors section in our Form 10-K filed earlier 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. 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 proved 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 per Mcfe, and we've also increased our R-to-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 million 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 teams 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 Mississippian Lime continues to be encouraging to us, and we're evaluating a number of shale intervals that are on our 120,000 net acres that we believe are prospective for new and significant shale development. Last night, we announced that we have 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 remain focused on growing long-term value for our shareholders.

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

Thanks, 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 mid-point of 625 million 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 right 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.

Lastly, cash G&A was lower than guided due primarily to annual bonus accruals coming in below target, largely due to the proved property impairment we recognized in the fourth quarter. This $170 million noncash 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 discuss 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 1.4x. 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 quarter, we had $340 million drawn against the revolver, with nearly $660 million of undrawn commitments. The borrowing base currently stands at $1.55 billion.

We'll go through our regular redetermination 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 the proved reserves. Our bank commitment amount remains at $1 billion currently, and we'll evaluate whether to increase that in conjunction with the redetermination process.

We have added some more commodity hedges recently. You can see a summary of our most current hedged 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, 3/4 of which related to sales of non-operated properties in our Rocky Mountain region. We had 92 BCFE of negative performance revisions in 2012.

About 1/2 of this related to aged Woodford PUDs in our Mid-Continent region that we no longer plan to drill within the 5-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 geologic 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've 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 1/2 our proved reserve base, 53% to be precise.

Our PUD percentage increased from 33% to 43%. However, we still only have roughly 2 years of drilling booked as PUDs in the operated Eagle Ford and less than that in the 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 5 years.

Drilling F&D, which 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 liquids throughout the year. Our producing liquid percentage is headed in the same direction as our reserve percentage, and we still believe that we'll 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're 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 proved 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 that 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 cubic 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 8 drilling rigs in this 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'll accomplish about the same level of activity that they would've 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 our 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're currently operating 4 rigs in our operated program, and we anticipate swapping 2 of those out for a more efficient walking rig to do pad drilling later this year. On Slide 15, we provide an update of our Tredway Mississippian Lime program in the Permian Basin.

We have roughly 66,000 net acres in the play. The company's currently operating 2 drilling rigs.

Excluding the results from 2 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.

The next 2 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 as several offset operators southeast of our Tredway position who are targeting the Cline Shale. And 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 3 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 billion 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 2 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.

With our strong 2012 performance and an exciting array of significant liquids-focused development projects, along with a growing slate of new venture opportunities, I am very bullish on SM Energy in 2013. With that, I'd like to turn the call over for your questions.

My question really is just around strategy. Over the last few months, you guys 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 compression since 2012, it's been pretty extreme. And so my question kind of 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're allocating capital and stock buyback, which I assume is the -- at the top of your list, and what you're asking about is always in that -- 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 start -- 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're 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 that we've had over the last couple of years.

And with that, I should also note that you would expect to see R-to-P increasing going forward.

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 start trying to pursue sort of alternative mechanisms to create that value.

I'm just wondering, aside from the buybacks, maybe what are some other options that you guys have considered or are considering?

Well, any given time, I mean 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 I mean 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. And I think if we do that, you'll see the other metrics improve over time.

This is Jay, and I'll just add that 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's another thing that's always on the list. It's what's out there that we own that somebody else might think more of than we do 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 more sort of just follow-up cleanup 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 would be -- you might 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 might -- 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. So 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.

The rejected gas, is that coming out maybe as 1,100 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 Bs on the guidance, that's -- I suppose that's a little bit low relative to the 91 million a day that you guys are 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 of the -- 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, okay? There are several different contracts.

We have elections on 2 of the 3. And even the ones that we can reject on, you can't go in and reject all the ethane from that stream.

You're 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's 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.

And that's -- so there's a certain amount of uncertainty here at this point given that it is a monthly election.

Okay, perfect. And then 2 quick questions on the 95,000 acres north of Houston.

Obviously, with permits from Washington and 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 focusing on 1 and 2?

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

No, it does not include legacy acreage. Yes, there are different intervals.

It is not a particularly -- 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'd 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.

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're currently doing, which is that 9% to 10% of ethane. They were -- those sheets were literally generated just last month.

So it's -- those decks that -- 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're rejecting or not, the revenue stream is about the same anyway.

So it's just an issue of where 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, I mean you're talking about pennies here on a gallon of ethane, and processing. Doesn't really change stuff.

Got it. Okay.

I guess a question for Wade. The full year CapEx of $1.5 billion in the cash flow statement, how does that reconcile with the cost incurred on the reserves of almost $1.7 billion?

Sure. Now there are 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.

So it's not a CapEx item, if you will. Also, we make adjustments to our ARO liability, and those are noncash adjustments.

That was a little over $30 million where it essentially grosses up the balance sheet. So it's a noncash CapEx item but it does get reported in cost incurred.

Then there's change in accruals. The CapEx number that you're referring to, the $1.5 billion, that's a pure cash number, so the cost incurred is accrual-based.

And -- so any changes in accruals from beginning of the year to the end of the 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 working capital items, that's around $100 million there.

So I think between those 3 items, that makes up the difference.

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

You said it was partially the GOR was higher than you thought and a 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're surprised on [indiscernible]?

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.

When you do the impairment calculation, what you're looking at is what are the value of your future revenues. So as your -- in general, on these wells, what's happening is the GOR is coming up and the oil rate decline has increased over what we expected.

Part of that is because the GOR is coming up, right? These wells are essentially -- you're 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 expect and of course, gas prices have been very low.

So it's a combination of lower oil and higher -- and relatively higher gas that drives a lower future revenue stream. Then when you look at that future revenue stream and compare it to your book value, that's the test that's made out of PV-0.

You look at a PV-0 test of your future revenues, 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 PV-0 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 changing?

Yes, I think so.

Okay. And then last one, the drilling problems you experienced on those 2 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 lime and drilled into a shale-filled karst. If you're familiar with limestone geology, in a lot of cases, you get a Carlsbad Cavern kind of effect some time along the top of these formations as water moves.

And we drilled into a karst that was full of shale and got stuck and we couldn't get unstuck and we ended up having to terminate the lateral short. The other well looked like we frac-ed our heel stage into some water-bearing interval and the well is making a bunch of water.

We are hoping we can get that shut off. But at this point, we haven't been able to accomplish that.

So a couple of drilling problems. What did we learn from that?

Well, we're drilling deeper in section to get away from the karsts. We've also changed to oil-based drilling fluids, which we think helps keep those shales off us.

But if you look at the last couple of wells we drilled -- I'm knocking on wood here as I say this, we drilled some longer lateral wells very successfully with no problems. And I think we've 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 were some karsts in there.

We hoped -- it's kind of hard to tell on the seismic how bad it is. You can see kind of 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-based, 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 drill -- to oil-based here is going to help us a lot in terms of dealing with the shales that are in those karsts, and I hope we'll be able to develop most of the acreage with that technique.

I was wondering if you could talk a little bit about the condensate market in the Eagle Ford? And I guess 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 -- it's not -- 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 is sufficient takeaway capacity out of the Eagle Ford. About 1/3 of our condensate is currently piped from the field to Gardendale and another 1/3 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, we're about 5,000 barrels a day firm on an 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 for selling in the field. It is true that condensate production is going to be going up.

Right now, what's pushed -- 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 I guess 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 build-out and so on and so forth?

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?

We think about different options for funding our program all the time. And with 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 of 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 pretty much tested our acreage in the Niobrara and have concluded that there's not a lot of potential there.

We're looking at other intervals in our acreage in Wyoming. Granite Wash, right now, we have 2 rigs running.

We're going to be moving down to 1 at the end of the first quarter, and we're really focusing on the oilier Hogshooter intervals there for the remainder of the year.

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

We're pretty well -- Subash, it's Javan. We're pretty well done.

We've concluded that in the northern area 1A that we show in the appendix, that we're going to go down to 52-acre spacing. I think we actually, if you look at that -- or 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 the -- what we think is going to be the development plan for the field at this point.

Okay. Yes, and the Miss Lime, if you had to sort of project, I know it's early, but if you had 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 that we're not going to drill anything that's not competitive on our portfolio over the long -- over a period of time.

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

Right, right. Because obviously, the Eagle Ford and -- type curve there has a beginning -- starting point of 40% IRR, so it's pretty compelling stuff.

So just curious if that becomes sort of your threshold requirement or you, as an organization, you would be willing to pursue something with a far lower return than that?

Well, our return hurdle is a 1.2 discounted present work 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-20s, 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.

And we can't -- in this business, you are what you started drilling 3 or 4 years ago. And we can't close our eyes to the fact that 3, 4 years from now, we need more inventory.

We've 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 Mississippian, we're not going to throw 5 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 the Eagle Ford either.

So you have to maintain the program over the long haul and -- 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. And 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 then final one for me, could you I guess explain as simply as you can, how does ethane rejection affect field level economics, say, with or without rejection?

The simplest way to explain is it really doesn't impact it at all. It's just revenue.

It shows up as revenue in just 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?

Well, you're making it. So obviously, the reason you reject is because you think there's a marginally better -- it's a marginally better economic outcome.

You're going to pay your processing fee one way or the other, okay, 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, I mean, we're talking about things that are literally month-to-month kind of marketing decisions.

This isn't a big, 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.

I 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 an ETC pipeline in July 1, just wondering if that's still on track.

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

Okay. So in terms of foreseeing bottlenecks in the midstream side in 2013, I know you had some issues in 2012.

What's just kind of overall thought there?

Let me make a distinction. You asked about ETC.

ETC is not -- 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's 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 this summer, and 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, and there's always risk associated with these wet [ph] major projects.

But in general, I think things are going well.

Okay. And then flipping over to -- well, I guess staying in the Eagle Ford, and if I look at that updated map in the appendix section of your presentation here, the thing that really jumped out to me was the 50,000 acres you have, approximately 50,000 acres in area A in the Eagle Ford, it looks like the oil cut jumped up a pretty high degree, 38% total production of 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.

Well, yes. You're talking about the northern portion of Briscoe.

And I think last year, we didn't divide those 2 out, so you didn't see the distinction between the northern area and the 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.

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 that it would be a similar program from a budget standpoint as we're looking at this year, 2013.

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

Everything equal, we have more CapEx...

Everything equal, we have more CapEx in '15.

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

Where do you all stand in terms of I guess 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, I guess, 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're very interested in it. There are times we have cored some of this and it kind of looked wet to us.

But there are some of these intervals that can look wet and end up being productive. So 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.

Quick question in the Bakken, just kind of a follow-up there. Last quarter, you mentioned that you'd seen some pricing improvement by maybe 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 were 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're spending a little more, putting more stages into our completions. So I think if you look back there, there is 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. All right.

And the next one that I had, in the -- with the new Mississippian results, do you think that those results, coupled with maybe 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 percent, the 21% NGL?

If you'd asked me that in December, I would've said yes. At this point, given that we're rejecting some ethane, it's a little hard to say exactly where our liquid percentages are going.

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

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 sort of has room for -- it looks like it has room for a repeat event, 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 go 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 and if -- 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're 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 this year than we booked in prior years, and that has a big impact on your overall, all-in F&D. I would say our drilling PD F&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 benefits you're seeing is really a result of the maturation of our portfolio. We've been promising this for a number of years is that when we got to a 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 2 years' worth of our drilling program booked as PUDs at this point and less than that in a non-op. So there's still a lot of opportunity to organically grow our reserve -- our proved reserve bookings within our existing portfolio.

But again, we do not guide reserves from 1 year to the next.

Rudy, what I'd point you to is the Slide #10, and I'm sure you've seen that in the deck. I think what we focus on is kind of the ongoing direction of F&D.

If you look at that, it has continued to improve as Jay mentioned over the last 5 years or so. And 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.

A few questions for you. First, on the cash flow CapEx situation.

When do you think you'll be cash flow CapEx neutral? Are you still looking at towards the end of this year?

Yes, we -- I mean, 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 have been pulled in the past year or so.

Any plans to put those back on the table this year or kind of 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 from me for Wade, do you have a PV -- pretax 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.

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.