SM Energy Co (SM) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the SM Energy fourth-quarter and full-year 2013 earnings conference call.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to David Copeland, Executive Vice President and General Counsel. Sir, you may begin.

Thank you, Shannon. Good morning to all joining us by phone and online for SM Energy's fourth-quarter and year-end 2013 earnings conference call and operations update. Before we start, I'd like to advise you that we'll be making forward-looking statements during this call about our plans, expectations, any divestitures, 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, please refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the risk factors section of our Form 10-K that was filed this morning.

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 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 I am the Company's Executive Vice President, General Counsel, and Corporate Secretary. I'll now turn the call over to Tony.

Thank you, David. Good morning, everyone, and thank you for joining us this morning for SM Energy's fourth-quarter and full-year 2013 earnings call. We will be referencing slides on the call this morning that we posted to our website yesterday afternoon. I will begin on slide 3 with a few key messages as we get started. 2013 was a record year for SM production where we saw annual production growth of 33% and year-over-year quarterly production growth of 31%. We also had an outstanding year from a proved reserves perspective with proved reserves growing approximately 46% from 2012 while our drilling, finding, and development costs decreased 26%. Our strong balance sheet was further enhanced by the divesture of our Anadarko Basin properties at the end of 2013, so we are in great shape financially as we head into 2014.

With the exploration potential that we have ahead of us, the strength of our balance sheet will be important with success in our new play areas. Jay is going to spend some time talking more about our new venture efforts and plans in a few minutes. Lastly 2013, was also a very good year for SM Energy stockholders. Our share price appreciated 59% in 2013 compared to 26% for the EPX. We're obviously very pleased with that performance and believe our stockholders are as well. 2013 is going to go down as one of SM Energy's best years to date for all-around performance.

I am now on slide 4, where I'll review our performance in the fourth quarter. We had another solid quarter from an operational standpoint. We closed out 2013 with good momentum and performed very well against our guidance. We achieved a new quarterly record for average daily production of 144,000 barrels of oil equivalent per day in the fourth quarter while managing our cost within guidance. The only notable item related to our guidance is that we came in high on cash G&A which is due to the fact that we had higher performance-based compensation for the year since we met or exceeded all of our key performance targets for 2013. We had GAAP net income of $7 million or $0.10 per diluted share in the quarter, and adjusted net income per diluted share came in at $1.26. Quarterly EBITDAX was $396 million.

I'm moving to full-year performance now starting on slide 6. Proved reserves grew 46% in 2013, up to 429 million barrels of oil equivalent. This included the impact of the Anadarko Basin divestiture at the end of last year. The percentage of our liquids reserves which include oil and NGLs grew to 54% of our total proved reserves. In fact, our proved reserves of liquids grew almost 50% in 2013.

On slide 7, we present F&D and reserve replacement metrics. We focus on drilling metrics excluding revisions because we think that is the purest measure of performance through the drillbit in a given period. Our drilling F&D for 2013 was $7.77 per BOE which is a 26% decrease from 2012, continuing our trend of substantial decreases in drilling F&D over the last several years. Drilling reserve replacement for 2013 came in at 405% which is a second consecutive year our drilling reserve replacement was in excess of 400%. I think these metrics say a lot about the quality of our assets and our ability to efficiently develop them.

On slide 8, we present our annual production over a five-year period. In 2013, our daily average production grew by approximately 33%. On a three-year compounded basis, our average daily production grew approximately 38%. As you can see in 2011, we began reporting on a three-stream basis. Since our inaugural year of three-stream reporting, our liquids volumes have increased by an impressive 103%.

On slide 9, we show our production and reserve growth on a debt adjusted per share basis. Excellent growth and reserves in production is a necessity for all E&P companies, but we strive to make sure that our growth is also adding value for our stockholders. As you can see from the slide, we have performed very well in growing reserves and production on a debt adjusted basis over the last several years. In 2013, production grew 33%, and reserves grew 47% on a debt adjusted per share basis. We think these are really strong results and believe they differentiate us from many of our competitors. With that, I'll turn the call over to Jay for his operational review.

Thank you, Tony, and good morning, everyone. This morning, I'd like to spend a little more time than usual on my operations update to wrap up 2013 and discuss our plans for building new drilling inventory in 2014. Before starting, I'd like to note that there are additional materials in the appendix of today's presentation giving our current type curves for operated development areas in which we'll be drilling in 2014, and our current unrisked operated development inventory counts. We'll also provide non-operated inventory information for the Bakken/Three Forks in that package. I will be referencing this data occasionally during our discussion so you may want to keep it handy.

I'll start on slide 11. We grew overall production 31% from fourth-quarter 2012 to fourth-quarter 2013, and liquids production 39% over the same time period. Our liquids growth in 2013 resulted in a 50/50 liquids-gas split for both the third- and fourth-quarters of 2013, although our actual oil rate was down slightly quarter-over-quarter, due to the fact that most of our Eagle Ford completions during the fourth quarter were in southern lower oil yield areas than in the third quarter. Our operated Eagle Ford program did generate significant growth and value in 2013.

As shown on slide 12, production for the fourth quarter in our operated program grew by 10% over the third quarter, as a result of the addition of a number of new strong wells and continuing upgrades to our infrastructure. For the year, we completed 95 wells versus our original budget of 75. At year end, we had 246 net wells producing, 199 PUDs, and total net proved reserves booked of approximately 240 million barrels of oil equivalent.

Slide 13 shows our most recent subdivision of our operated area into type curve regions. I think this map will be helpful to you as you look at other maps I'll be showing and the materials in the appendix. Slide 14 shows our completed wells as of the end of 2013. The 2013 wells are shaded in red, so you can see the areas where we were concentrating our activity last year. As I mentioned, we completed 95 wells last year about 75% of which were in the southern areas, and booked a total of about 59 million barrels of oil equivalent of net proved reserves after royalties to those wells.

We have made several changes to the type curve data shown in the appendix this year, after reviewing our results at year-end. The most consequential changes we have made are our estimates for our Northern Briscoe Ranch area acreage. Those of you who follow us closely know that we did not complete many wells in this area until the third-quarter of last year, and so our year-end review was really the first time we could make an assessment of how our new wells in the area performed. As a result of our review, we have redrawn some type curve regions and parsed out several new type curve areas, now called areas 4 and 6 which have been the better performing portions of the northern block of acreage.

We then averaged the new and historical well data in the remaining portion of the northern block, which we call area 1, to generate a new type curve for that area. This new area 1 type curve has a lower reserve level than previously reported and generates poorer economics than we would like. Area 1 is a large area, and this change also impacted our total unrisked resource estimate indicated in the appendix for the field. One of our major focuses for 2014 will be working to understand and improve our results in area 1 through methods I will discuss in just a moment.

Our drilling and completion execution in the field continues to improve. As indicated on slide 15, we reduced our average well cost by 14% from 2012 to 2013. We were drilling and completing much the same well designs over this two-year period, and it's good to see these efficiency gains which we will put to good use as we continue to optimize our program.

Slide 16 then focuses on the two most important things we're working on to improve economics and grow our economic inventory in the field. First, during 2014, our plan is to extend lateral lengths of almost all our wells, but particularly in the higher liquid yield areas on the north side of the field. When you look at the economics data in the appendix, you will note that we are assuming an average 6,500-foot lateral length now on all the wells we'll be drilling in areas 1, 2, and 4, and I expect that a number of the laterals will be significantly longer than 6,500 feet.

In addition to extending laterals, we have been testing modified frac designs with higher sand loadings. Although we don't have enough production yet to show conclusive results from these modified frac tests, and we have not included any of the potential for those fracs to improve our results in our type curves at this point, we are encouraged by early indications and will be moving in the direction of higher sand concentrations on most of our completions. Both extending laterals and using more sand will raise our costs, so we will be looking closely at the cost versus benefit of these changes throughout the year. With that said, we're optimistic about the potential impact of these changes particularly for the eastern portions of area 1 I just discussed.

Slide 17 shows a map then of where we expect our activity to focus during 2014. On this map, the blue shaded sticks are our currently planned 2014 completions. In total, we expect to complete about 100 wells for the year. For some longer-term perspective, we have included a map for the first time of our current plan for field development over the next five years on slide 18. This plan assumes about 100 well drilling program per year, and the drilling areas identified drive our plans for further build out of our field infrastructure.

A summary of our non-operated Eagle Ford results for the fourth quarter is on slide 19. We noted that APC in their recent release stated that they grew production by a larger percentage than we're showing for the fourth quarter. The opposite occurred in the third quarter of 2013. There are a number of reasons why our reported net production may grow at a different rate than APC's reported production over any three-month any period.

From a big picture standpoint, our net quarterly production growth from this asset from fourth-quarter 2012 to fourth-quarter 2013 was 29%, higher than our expectations. We're very pleased with this performance. We have budgeted to see roughly 5% per quarter growth from the APC assets during 2014. As we have noted many times, we expect our drilling carry with Mitsui to end early in 2014, sometime in this first half. The capital program we announced in December assumes we will spend roughly $250 million during 2014 on APC operated activity.

Moving on to the Bakken/Three Forks, I'm now on slide 20. Our production in this play grew 8% from the third to the fourth quarter, as we continue to operate a three-rig program. We sold several non-core mostly non-operated Bakken and Three Forks packages in the last year which is reflected in the slightly reduced acreage counts shown on the slide versus last year at this time. Slides 21 and 22 show our 2013 activity in the McKenzie County area which we call Raven/Bear Den, and our Divide County area which we call Gooseneck.

We completed 30 gross operated and 18 net operated Bakken and Three Forks wells in Raven/Bear Den, and 15 operated gross and 11 operated net Three Forks wells in Gooseneck during 2013. Note that the net reserve figures shown are net of royalty and field fuel strength, average values for which are included in our type curve data in the appendix. Slide 23 shows that we have been making progress in reducing costs in the Bakken/Three Forks play as well. In general, we find our costs to be low relative to cost for wells we participate in with others.

During 2014, we expect to have a number of initiatives going on to increase and improve our inventory in the Bakken/Three Forks play area. As indicated on slide 24, we are experimenting with proppant and fluid volumes in our completions, and we are modifying our Three Forks drilling target window at Gooseneck as a way of improving wells in that area. Slide 25 addresses our efforts in testing well spacing.

Up to this point, we have been assuming for our inventory numbers in the Raven/Bear Den area that we would generally be drilling up to five Bakken wells per spacing unit where possible and four Three Forks wells per spacing unit. That is a spacing of 1,060 feet approximately between wells in the same interval. In 2014, we are going to be testing down to 880 feet between wells in the same interval, which if successful, could add about 110 gross operated additional wells to our inventory.

Slide 26 discusses an exciting opportunity that we have on our Gooseneck acreage to drill a number of Bakken wells in addition to the Three Forks play we have been pursuing there. Recent competitor activity and new log and core correlation work suggests that the Bakken is prospective over a good portion of our acreage. We expect to drill four Bakken wells at Gooseneck in 2014, and could prove up as many as 90 additional gross operated locations.

Lastly as indicated on slide 27, it now appears to us based on competitor results that our acreage just north of the Elm Coulee field in Eastern Montana is a viable economic target for Bakken and Three Forks drilling. We expect to drill a couple of wells in that area during 2014, and with our own success could add up to 80 net wells to our drilling inventory. Slides 28 and 29 show our 2014 drilling plans for both of our Bakken and Three Forks core areas. We expect to drill a total of about 45 gross and 31 net wells in 2014, very similar to our 2013 program.

I'd now like to shift over and talk about our new ventures programs. I'll start with our Powder River Basin program on slide 31. Our primary target here is the Frontier, with secondary opportunities in the Sussex and Shannon. We don't have any new well results to share with you today, but we do have a rig running in the play and a new well preparing for completion as we speak. We will be at two rigs in the field shortly. Our plan is to drill 10 Frontier wells and complete 8 of them this year.

We have updated our unrisked potential location count and potential resource for you on the slide, and we're still using the same projected type curve we've previously disclosed. By this time next year, we'll have tested wells across most of our acreage position as you can see. We're well ahead on our permitting, and assuming continued success with delineation, don't anticipate a problem running a three- to four-rig continuous development program here in 2015. During 2014, we'll also be focusing on optimizing completions and reducing drill times with additional experience.

Next, I'd like to move on and discuss our Permian Shale program starting with slide 32. Our Permian region production was up 7% quarter-over-quarter due to three wells we completed during the quarter. As a reminder, slide 33 shows a locator map of our operated shale assets in the Midland Basin. I would like to start by updating you on our progress at Sweetie Peck.

During the quarter we completed two more Wolfcamp B wells at Sweetie Peck, the Britain 3133 H and the CVX 4134 H. Details on these wells and their completions are shown with rates on a two-stream basis on slide 34, along with an update on our Dorcus 3035 H well that we announced last quarter. A couple of things seemed very clear from this data.

First, the Dorcus is one of the best horizontal Wolfcamp B wells completed to date in the Midland Basin, especially if considered on a per lateral foot basis. Our follow-up wells are very good wells also. Although it is still too early to be sure, it would seem reasonable to forecast that subsequent wells will perform at levels close to the upper end of the potential type curve range we showed last quarter and which is repeated here on this slide in a slightly different format.

Slide 35 discusses our 2014 program for Sweetie Peck. We plan to complete 14 Wolfcamp B wells in 2014 and test the Wolfcamp D zone later in the year. At some point, we expect to try a Lower Spraberry shale test as well. Our current unrisked inventory of Wolfcamp B locations shown on this page assumes 880-foot wellbore spacing. During 2014, we anticipate testing wells at this spacing and reaching some conclusion on our testing of various frac proppants. We'll also be drilling some longer lateral wells where possible and expect to have results on some of those this year as well.

Next, I would like to discuss our program for testing in our northern Midland Basin acreage block which we call Buffalo. Referring back to the locator slide you will notice that we are showing a somewhat lower acreage number for the prospect area than we showed last quarter, as we elected not to close on some acreage at the northern side of the block for geologic reasons. Slide 36 shows a comparison of logs between Sweetie Peck and the Buffalo area. As you can see, the logs are similar in character although the B shale is somewhat thinner in the northern area and the D shale thickens there.

Slide 37 shows the results of our first Wolfcamp B test in the block. The Tatonka 1H, a 5,560-foot effective lateral re-entry of an existing vertical well, tested at 549 barrels of oil equivalent per day for a seven-day average, and 376 barrels of oil equivalent per day for 30 days at 89% oil, again all these numbers on a two-stream basis. We believe that we have several opportunities to improve on this result including lengthening laterals on subsequent wells. In the meantime, we're moving quickly to test the Wolfcamp D in the area and expect to have a completion there in the second quarter.

Turning to slide 38, I'd like to end this discussion of our efforts in the Permian shales with a plot we generated from public data, showing the relative performance of our recent Wolfcamp B wells versus all the Wolfcamp B wells with public data we could find in the Midland Basin. As you can see, our wells in the Sweetie Peck area are top quartile wells for their lateral length. Our Tatonka re-entry well in the Buffalo area looks to be an average barrel of oil equivalent per day rate well for its lateral length at this point, and it is oilier than comparable equivalent rate wells in the southern portion of the basin.

I'm now moving to slide 39 to talk about our East Texas exploration program. Our total net acreage in the area is unchanged at roughly 215,000 acres. On this map, we have provided more granularity on the individual prospect areas we're chasing and what we're testing in each area. Our Independence prospect on the west side of the play area is an extension of the Eagle Ford source rock play. Deep Pines East on the far east side of the play is targeting the Austin Chalk in a quiet area where some of our private competitors have been making good wells. Deep Pines West and Central are largely Woodbine Sandstone prospects with some additional potential in the overlying chalk.

Speaking of the Woodbine, the next slide, slide 40 shows an illustration or cartoon of what we're chasing in the Woodbine. A number of our competitors have been targeting remaining oil, around the edges of conventional Woodbine traps in areas north of our position. That is not what we're doing, and so their relative success or failure in those areas really does not say anything about our acreage. Our play concept is to chase the tight unconventional sands along the shelf. This is why our acreage extends along the Edwards Reef margin. In this area, the Woodbine is hydrocarbon charged and significantly overpressured, and we believe that a permeability barrier exists between our target and the higher perm wet sandstones to the north of us.

Slide 41 summarizes the results of two relevant recent tests in the Deep Pines West, Woodbine, and Independence Eagle Ford areas. We released data on the Horizon 2H Woodbine test and Deep Pines West last year, so that is old news, but certainly lends credence to our expectation that the Woodbine can be productive in the Deep Pines areas. The Brollier 1H was our first attempt at the Eagle Ford in the Independence prospect. We made a very strong wet gas well as you can tell from the high flowing pressures and rate data on the slide. We'll be following up later this year with another well in the area where we expect to see an oilier result. In general, we've been very encouraged by our early results in both of these prospect areas.

Slide 42 shows a list of additional key East Texas wells planned for 2014 with estimated times of completion for each well. Although these eight additional wells will not be sufficient to completely delineate all of this acreage, we should gain a pretty good sense of whether our play concepts are working, and with success be in a position to begin to accelerate activity in late 2014 and 2015. In closing, I should mention that with the closing of our Anadarko Basin sale package at the end of December, since 2008 we have now sold over $2.2 billion worth of assets to fund our development and new venture programs, and we anticipate continuing to hydrate our portfolio in this way. With that, I'm going to turn the call over to Wade so he can elaborate on our strong financial position. Wade?

Thanks, Jay. Starting on slide 44, we show our financial position of the end of the year. I should note that our revolver was undrawn at year-end, compared to $28 million drawn at the end of the third quarter.

We closed on our Anadarko Basin divestiture package of end of year which added significant cash to the balance sheet. Taking into consideration the $280 million of cash on the balance sheet at year-end, our net debt to trailing EBITDAX was 0.9 times, and net debt to book capitalization was 45%. I will remind you our current revolver has a borrowing base of $2.2 billion and related commitments of $1.3 billion, so we have lots of liquidity to execute our 2014 business plan and beyond.

On slide 45, you can see the maturities of our long-term debt. As you can see our revolver does not need to be renegotiated until 2018, and our first tranche of unsecured notes are not due for five years. Moving to slide 46, we show our debt to trailing EBITDAX against a peer group that we track. Our debt to trailing 12-month EBITDAX decreased slightly in the quarter to 1.1 times, or 0.9 times net of cash as I mentioned earlier, and we still remain near the low end of our peer group [while the] return below the peer average. Again, we have plenty of dry powder to increase activity on our new ventures plays with success.

On slide 47, we presented EBITDAX per debt adjusted share for the past five years. As you can see we have grown our EBITDAX per debt adjusted share fairly consistently. Our performance from 2012 to 2013 was particularly impressive with 44% growth year-over-year. Net adjusted per share measures are very important to us, and as we've shown in the slides this morning we've been performing well on those metrics for several years. With that, I'll turn the call back to Tony for his closing remarks.

Thank you, Wade. Before I turn the call over for your questions, I'd like to spend a few moments going through a few key takeaways. First of all, 2013 was an extraordinary year for SM Energy. We executed well on our development programs, and made important groundwork on new venture plays that, with success, could provide significant upside to the SM story going forward.

On an absolute basis, we significantly grew our production, proved reserves, and EBITDAX last year. More importantly, we grew all these metrics on a debt adjusted per share basis. I don't think there are many of our peers growing all three of those key metrics on a debt adjusted basis, and I believe that such stellar performance differentiates us from our competitors.

As we began 2014, we will continue to focus on optimizing our development programs and testing our new venture plays as Jay shared with you earlier. In our development programs, we will conduct various tests on spacing and well completion designs to enhance the economics of our programs in Eagle Ford and Bakken/Three Forks. In our new venture plays, we will continue to test and delineate our positions in the Powder River Basin, the Permian Basin, and East Texas. Each of these new play areas have the scope and scale to significantly grow our Company in the coming years.

In closing, I would like to thank our employees and service providers for their superior efforts in delivering outstanding performance in 2013. I'm excited about where we are today and look forward to continued growth while pursuing the upside potential of our 2014 business plan. With that, we'll turn the call over for your questions.

(Operator Instructions)

Mike Scialla, Stifel.

It looks like you're not backing away from that area 1 the Northern Briscoe area. It looks like 10% of your 2014 wells in the Eagle Ford are going to be in the area. What gives you the confidence of these new techniques are potentially going to improve the results there? Can you talk about the resource potential for that, maybe for the entire Eagle Ford at year end 2013 versus where it was at year end 2012?

This is Jay. Mike, thanks the question. I think we were disappointed by our results in area 1 this year. I'm sure we share that with a lot of you. But we do think the longer laterals are pretty much a slam dunk. We're going to get more from longer lateral wells. We don't think there's much question with that. Our plans for the year and our budgeting for the year was built on the idea that we essentially ratioed up the results. The new frac designs, we've seen some really good indications on some early wells we pumped. It's still too early to build a lot of that into the program, but some really encouraging numbers just going to higher sand concentrations, and we think there's going to be some real positive outcomes from that. Again, our budgeting though is really build just on drilling longer laterals, and these wells are economic on the east. We think they are on that eastern edge where we're going to be doing our development with longer laterals wells.

In terms of the overall resource potential in the play how much have you reduced?

The total unrisked number I believe went down by 17%. I haven't done the math by region but most of that's going to be an area 1 area. It's a big area, and we reduced the type curve by quite a bit. That's where most of that resource potential was. I know everybody risked these numbers anyway, and I'm sure people we're risking area 1, but it certainly is a disappointment. We expect to see better results there this year. It's a combination of things. We took the better portions of the area and parsed them into their own type curve areas which obviously hurts the average in the remaining area. Then, our wells that were in area 1 just didn't perform as well as we'd like. When you combine that then with averaging those results with a lot of really old wells, which frankly some of which are short lateral not very good completions, your average based on all that history in area 1 doesn't look very good. We certainly think we can improve on it. We're going to improve on it, and that's something we have to prove up this year.

Got it. Switching over to the Permian, the Sweetie Peck area looks like you're going to develop at least the B horizon horizontally. Is there anything in your proved reserves for the vertical wells in terms of PUDs there? Or is everything you're doing there going to be incremental in terms of reserve potential?

Mike, This is Javan again. If there's anything left PUD-wise on the verticals it's very small. I don't know the exact number. It's going to be very, very small. Those wells just don't work as well as what the other things we're doing, and typically we won't keep PUDs on that we don't think we'll drill in a five-year period. Most of the potential is going to be horizontal. Isn't it a great story though? We drilled these wells for many years. We've been involved in this play, and we were completing the wrong part of the reservoir. We should have been drilling horizontal in the shales, and yet we were out their drilling, putting frac, the ratty stuff in between the shales. It's just the gift that keeps on giving in the Permian.

Right. How about in terms of the Buffalo prospect with the B zone? Does that look like, I realize you only have 30 days worth of production history on the one well up there, but do you think that looks like a viable target? Or is it now looking like the D might be a better target for you up there?

We went to the B first because we had experience in the B elsewhere, and I think it's too early to call whether it's going to be successful or not. Clearly we can improve our result by drilling a longer well. That's obvious to us. Some of the frac we pumped, we pumped the best job we could, but we did have some go a little higher than expected and some go lower, based on the microseismic we did. I think we can probably improve our frac design as well, maybe our targeting in the wellbore. We have some things we can improve on that B effort, but that said I think D is a very attractive target. If you look at people completing wells just to the south of us, there have been some terrific D wells completed. It is thicker. That's where we're going to go next.

Great. I'll get back in the queue. Thanks, Jay.

David Tameron, Wells Fargo.

Hi, good morning. Jay, you talked a little bit about it, but the Briscoe Ranch, can you just talk about what you guys were assuming a year ago or whenever? First quarter, last year versus what you're assuming now, what's the change was between? What was the disappointing part of the well performance, I guess is what I'm asking versus your initial expectation?

Last year, when we get our type curve work, and I think I was the first year we'd ever presented type curves for anything, we average a very large area together which included a lot of what we're now calling area 4, area 1, area 6. Frankly, we probably should have parsed the data more carefully when we averaged it. Averages can be very deceiving, as you know. We included some wells in there on area 6, area 4, which were pretty good wells which drove the averages of area 1 up some. If you just took those out and parsed them out, and said okay, those are obvious development areas. What about just area 1? We would've gotten a lower result last year as well. We realize that as we went to the year. We really thought when we went into the third quarter this year and completed a bunch of wells that as we were completing them on the east side of area 1 that those wells would significantly outperform the remainder of area 1. They just really haven't. I don't know all the reasons for that. Some of it may be infrastructure, but they're shorter. They're 5,000-foot lateral wells. They're completed with fairly conservative frac designs. I think we just need to be more aggressive, and that's what we're going to do this year.

As a result, area 1, after you take out the good areas basically and you average down the poorer areas, there was a reduction in EUR. I don't know the exact number in that particular area, but overall it had a pretty big impact on our unrisked resource numbers. There is a difference if you look in the appendix between the area 4, area 6, and area 1, there's a pretty substantial difference in EURs between those areas. When we took the good parts out and left the other parts, the average changed.

Okay. No, that's helpful. Can you talk about what you're seeing at Galvan Ranch? What you're seeing in that area, and how that stacking up with your expectations?

I think we'd say that although the type curve didn't change a lot in terms of EUR, I think our wells in Galvan are performing very, very well. I just don't know how to say that any other way. There's some terrific acreage down there. I think the wells have generally outperformed our expectations. Of course, that's where a lot of our activity was last year, and I think when you look out the performance of the Company overall, it was driven by outstanding well performance in that area. We expect to continue to see that kind of performance as we go into 2014. We have a lot of wells to complete in that area.

Okay. One more from me, if I think about 2014 CapEx in your plan that's out there, what are the wild cards in that plan? What do you see now as 12 months down the road, you could say we went into the year with this plan, and based on these results, we allocated capital. What would be the wild cards?

This is Javan again. The wild cards are the new venture programs and how fast we ramp up. With early success we would expect to start spending significant amounts of money in East Texas potentially in the second half. I think our Powder River Basin program is pretty well baked in, but we could potentially accelerate there, maybe in the fourth quarter. The Permian really depends a lot on what happens with this D well we're going to drill at Tatonka. We're going to run a two-rig program in the Permian, and if we get some more success there, we might pick up a third rig but that would be late year. I think what you'll see, and there is some likelihood that when we get to midyear if things are going well that we would increase capital at midyear. I don't have a number for you on what that could be. It just depends on how many of these programs are working. I will say that anything we do in the second half obviously is not going to have a huge rate impact in 2014. It would have an impact, favorable impact, in 2015 of course.

David, this is Tony. If we saw any increase in our CapEx as Jay said it's obviously going to be based on success that we're having in those new venture areas.

Okay. I'll let somebody else jump in thanks. Thanks for the color.

Michael Hall, Heikkinen Energy Advisors.

Thanks, good morning.

Good morning.

Let's see, a little bit more on the Eagle Ford. Sorry to beat a dead horse. But on that area 1, is there any variation in EUR over time that's driving that reduced oil mix in the EUR? Or is it really just the absolute levels of oil yields from the wells early on?

That's a great question. This is Jay. We do see in most of these northern areas, including the non-operated areas in our northern portions, we do see declining yields. They typically come on higher and then decline to a level at which they level out, so you do have to be careful not to over-forecast your yields based on real early results.

Okay. I guess what I was trying to get at is, is that change in yield declining more quickly than you had thought, or is it just the absolute level of yield was lower?

I would say when we first looked at the wells a couple of years ago, we probably did not have as good an understanding of that declining yield, the way that would happen. We were probably a little too optimistic. We have quite a bit more data now, and we're not particularly optimistic. We typically forecast declining yields and that certainly has had an impact on our EUR estimates for that area.

Okay. That's helpful. Then bigger picture on the Eagle Ford, with this kind of changing view around the inventory, does this make you want to press even harder on the new ventures program? How does it change how you think about the Eagle Ford in terms of the broader portfolio, if at all?

This is Javan again. I think you've got to put this into context. We have a real strong four- or five-year drilling program here in Eagle Ford. It has very good economic. As we improve our drilling cost, our technology, our lateral lengths, we think we'll prove up even more of that. That's a huge focus for us, to continue to develop additional inventory in Eagle Ford.

With that said, I think it's interesting you ask that because people have asked us in the past why we even have a new venture program. We have a new venture program because we've always known that we needed to grow this Company. We're certainly pursuing it at a pace that we think is rational, given the risks associated with it, and there's a big prize out there. East Texas could be very significant to this Company. Permian could be significant to this Company. These are all Company mover type opportunities that we're working on, but we're going to pursue them at a pace where we prove things up before we spend too much money, and we have the opportunity to do that because we have these other great assets that we can work on in the meantime.

Michael, this is Tony. I also wanted to point out if you go back to slide 12 that we provided the presentation, I think we have to keep this in context. We are very focused and pleased with the majority of our performance in the Eagle Ford, and in fact, if you just take a look at our year-end reserve numbers it's still almost a quarter billion barrels equivalent in that play. That's important. Jay's already focused on how we intend to improve and see if we can provide better results in area 1, but the overall asset is performing very well. If you refer back to those reserve numbers, I think you can see why that has remained a strategic asset for us. We will continue to up our game in the Eagle Ford.

That's helpful. I appreciate it, guys. On my end on the Permian, I just noticed on the Sweetie Peck wells, you had to use three different types of proppant on those. Any read there yet or game plan going forward of which might be better? It looks like the white sand was performing better. I don't know if that's just rock. Any view on the proppant there?

This is Javan again. Thank you for that question. We are testing white sand, resin-coated premium cut proppant, and a light ceramic material. We pump ceramic in fact on the Tatonka well, as well. It's a tough call here. There are geologic differences. Whenever you do three wells and they work out a little differently, you can ask yourself how much of that is the proppant, and how much of that is just natural variation in the rock or whatever? I think you would have to see a significant early benefit from ceramics to justify the cost. We have not seen that. I think our general direction here right now is to move back toward white sand with probably a little resin coat tail just around the well to keep that wellbore stuff open, and frankly save the money versus this.

I know people will argue, you don't see the benefit of ceramic until way down the road. The problem with that is way down the road, it's not worth very much from [BD] standpoint. The cost difference is substantial. I think generally our conclusion at this point is that if you didn't see a big benefit on the initial rate, you probably can't afford to do it. We looked again on a bunch of testing we've done, what we call [D-fit] testing, prior to fracs and looked at what the enclosure stresses would be on this rock. We think white sand will cover it. I think we'll probably be a little safe on that again and use a little premium resin coat on the tails just to be sure. I think we're moving toward sand.

Okay, that's helpful. Also, how many wells do you test to plan in Buffalo in 2014?

Really, the program is an expiration program. We plan to drill Tatonka, and we plan to drill this D well and then we're going to look at our results. We don't have any other wells budgeted at this point.

Great. Thanks, guys.

Pearce Hammond, Simmons and Company.

Good morning. When we look at Q1 oil mix, I know Q4 was impacted by more Galvan Ranch completions which is a little bit gassier. How should we think about the oil mix in Q1?

Generally, you should see it go up, Pearce. Most of what we sold in the package was gassy. It's not going to move. We can never move these numbers that much because we produce a lot of gas in almost all our plays, other than perhaps the Permian and the Bakken, but the Eagle Ford and the Anadarko Basin package we sold both produced quite a bit of gas. Generally, it's going to move oilier as we go forward, particularly because of asset sale. But it won't be dramatic.

Thank you for that, Jay. On a leading edge basis where do you see Eagle Ford oil differentials right now, and as you look out in 2014?

This is Javan again. Our contracts basically give us a $17 deduct to LLS. I should note just for everybody's comfort that those contracts are pretty well tied in. There is really very little variation based on [constant gravity] and very little wiggle room on [constant gravity] in those contracts. One of them, it's actually fixed, and the other floats, but only on a little bit. I think what you could assume for us is you're going to see $17, LLS less $17. What you've seen of course over the last six months is that the LLS-WTI spread has narrowed substantially. When you look at the WTI spread, we're now going to be looking at numbers well below our normal expectation, probably at $14 discount to WTI, which is higher than we'd probably would've forecast a little back, but WTI's come up relative to LLS. I think the best way to think about our stuff in Eagle Ford is you take LLS less $17, and that's the number we're going to get.

Thank you, Jay. One last one for me, across your East Texas areas, Independence, Deep Pines West, Deep Pines Central, Deep Pines East, can you give a targeted well cost range that you're looking at in development [mode] in those areas?

Sure. If you look at, say, Independence, those wells are probably going to vary between $8 million and $11 million of development cost. It does vary a little bit in depth. On Deep Pines West, those are deeper wells. They're more expensive. Our initial drilling cost are probably going to be in $13 million, $13.5 million. That's probably not a bad place to be. I think we can get them down to $11.5 million, maybe $11.5 million to $13.5 million over time. Deep Pine Central is a little shallower. It's probably more in than $11.5 million, maybe $9.5 million to $11.5 million kind of range. Then again, Deep Pines East, we haven't drilled a well over there yet, but I'm guessing those wells are going to be in the $10 million, $11 million kind of range. It's not cheap, not for the faint of heart, but a lot of overpressure. We really like overpressure.

All right. Thank you for the color.

Matt Portillo, Tudor Pickering Holt.

Good morning, guys. Just a quick follow-up question on the Eagle Ford, you guys did mention some of the new completion techniques your testing in area 1, although I assume that's not just for area 1. I was wondering if you could provide some context around how you think about lateral length in area 3, and maybe some of the completions that you will also be testing there? Then a second follow-up question, just in regards to downspacing around area 3, is there any potential upside to increased inventory depth through downspacing as you guys progress in the program?

This is Jay. Good question. Your interpretation is correct. We're not just focusing our longer laterals on area 1. We're going to drill all our wells as long as we can get them. We're doing that wherever we can, with the leases the way they're configured. We can do it everywhere, but we're going to do it where we can, and that includes area 3. We are also testing higher sand concentration fracs across the board. In general, we think that's probably where we're going to end up. We haven't proved that 100% to ourselves yet, but that's certainly our assumption that that's where that's going. I think you should see some benefits associated with that.

One of the things that we're hoping for in that, we'll call it, I'll call it a fat frac here today, one of the things we're hoping for with that frac, higher sand loading frac, is that as those fracs, because of the way we're pumping them, we're also pumping at slower rates would allow us to keep the frac closer to the wellbore. That would have two potential positive impacts. One is you'd have less impact on wells nearby when you're pumping which could simplify damage to other wells due to fracking into them, as well as simplify potentially some of your SIMOPS related downtime. But it can also allow you to space these wells closer together. We have not projected any benefit from that yet, but it's certainly something we're looking at, is could we push some of these wells closer together, if we can keep these fracs closer to the wellbore. That's part of the experiment we're doing.

Great. In terms of the cost there, any color you could provide on incremental costs associated with the sand content?

I think the cost numbers we put in the appendix are pretty well what we're assuming, based on the larger fracs. They're a little higher than our costs have been recently. It's not huge, but it does cost more. The longer laterals plus the sand fracs, I think those are pretty well baked into the numbers we have in the appendix.

Great. My last question on the Bakken, you guys talked about some of the downspacing opportunity. I wanted to get a little bit more context in terms of how you think about the drilling program there over time. You talked about a few the other plays in terms of acceleration. I wanted to see if there was potential for Bakken acceleration with downspacing success? Then you mentioned a few other emerging Bakken opportunities within the basin. Could you put those into context, as you've seen the offset operator well results? How does it stack up on a return basis versus your existing assets, or how you guys think about that within the total context of your portfolio?

This is Javan again. Certainly the downspacing portions would stack up very, very well. They're great incremental opportunities with very similar reserve levels. If they're not pretty similar reserve levels, we won't do them. That's a great opportunity. Some of the more extensional stuff, the Bakken, the Gooseneck, the work in Eastern Montana, we're not 100% sure what the economics look like there yet, but I think there's good potential. In terms of pace of activity, industry activity at least rig count in Montana has been pretty flat. There's still a lot of gas being flared up there. I think we're looking. I think the whole industry is looking real hard at how much activity increase could you live with. I tend to look at these inventory adds as just extending our drillable inventory, not necessarily leading to an increase in rig count for us, as we manage our way through some of these infrastructure issues up there.

Great. My last question is just on the well cost. You guys gave some great color on East Texas. I was wondering if we could get, and there may be no change, but an update to your expectations around both the PRB and the Sweetie Peck drilling program?

I think at Sweetie Peck, you're going to eventually see these wells in the $7 million to $8 million range. Once, again as I said, we go to white sand in a little bit of maybe premium proppant, that's really the biggest cost driver there, and then getting to pad drilling. I think that $7.5 million to $8.5 million. We're pumping larger frac jobs here. They're very large, and they're expensive, but great well results there. I think so that $7.5 million to $8.5 million number is not bad for Sweetie Peck. When you look at the Powder, I still think we can drill these wells under $15 million, $14 million, $13.5 million, $14.5 million. We just need to have more rig time. We didn't have a rig running for a while last year, and we just have had one for a few months. You really need to have a continuous rig program with a couple of rigs running to make a lot of progress. But I think we can get there on those. We've made some progress but no promises yet, but I think we can get our cost lower there.

In East Texas again, right now we're drilling pilot holes on all these wells, doing a lot of science, a lot of testing. It's just too early to see a lot of cost decreases but I'm confident that with success, we get on a success leg that Tony talked about, that we can drive our costs. We know we can drill wells. People ask me about these wells in East Texas look like expense of Galvan wells. Our first Galvan well was pretty expensive too, and now we drill them in 10 days. I think there's a huge opportunity in that play, and we're very excited about it.

Thank you very much.

Brian Velie, Capital One.

Good morning, guys. A couple of quick questions, just the first one here, on the extended lateral lengths that you mentioned for areas 1, 2, and 4, they're factored into the type curve info on the appendix now, were those longer laterals the basis for your previous EUR expectations in those areas? Or is this new EURs and new lateral length assumptions?

All the work in the appendix assumes we drilled a 6,500-foot lateral length. The work we did last year was based on historical wells, and they were of course shorter than that.

Okay. Then another question on the Buffalo well, Buffalo area well, you mentioned there's still a bit of work to be done to see if the B is something that we'll want to go after versus the D. What kind of EUR range do you think makes that interesting to you, or worth going after in the future?

I think really to make the B work at our costs, you need about a 400,000-barrel well. That's the kind of numbers you need to be at, what we had estimated for our low-end range for Sweetie Peck. There's a lot of differences in the rock as we've learned more and more about it. The rock up at Tatonka, the B section, is clearly more permeable. You saw a lot more pressure bleed-off in there. I think the type curve shape is going to be substantially different. One of the reasons it's so hard to know, reach conclusions, is that we've got to see what the type curve really looks like out over time. We didn't see the real high pressures early on that we typically see at Sweetie Peck, so it's a very different shaped type curve there. You've see that in offset operator results as well. The IPs up in that area have not been as high, so we'll just have to see how that works.

All right. Great. Last one real quickly, in the East Texas acreage, the different areas that you have there, you broke down cost expectations. Is there any way or is it too early to break down oil cost expectations for those areas?

We've been intentionally testing the down [dip] limits. A lot of the early wells you're going to see are probably going to be fairly low yield. That's just the way it is. We're trying to figure out how much of our acreage is prospective. Certainly that was what we did on the Eagle Ford test you saw. That will probably be the lowest-yield well we drill there. You're going to see some great wells I think in the Woodbine as we come up, but some of those will be on the low-end as well. We're testing that southern limit. We're going to aim for things that are higher oil cuts than most of our Galvan acreage. I'll say it that way because the costs are a little higher but your pressures are higher, too. I think there's a lot of opportunity there.

Okay, that's very helpful thanks a lot.

Bertand Donnes, Johnson Rice.

Hi, guys. Thanks for taking the question. In the PRB, when you're looking to complete those eight Frontier wells, are they going to start off in the northern, near that Loco, or are you going to start down, or is it just scattered?

The first well we're going to complete is on the southern end. Then we have, right now we're drilling a well up on the northern end, right near Loco again. It's actually a 640 well, not a 1280. The rest of the wells are scattered across. The next well down, I think is that dynamite location, which is right smack dab in the middle of the block. It's a 1280 location. Then we'll be drilling the rest of the wells will be scattered around the block. By the time you get to the end of this year, you'll have wells pretty much through the whole block. That's really what we're waiting for before we put development and put everything in the back in the appendix and all that stuff that we do with the development play.

Okay, great. Then just one other one, it looked like Bakken EURs might have creeped up. Is that correct?

Yes, that's right.

Based on recent results?

I think one of the great things is that we've seen increases in our Bakken EURs pretty much every year. Some of that is due to seeing some more, being more experienced, and maybe being a little more optimistic on our B and factors in D, terminal declines, as we've looked at them. We have seen improved performance in our Bakken wells pretty much every year as we've gone out. We were apparently fairly conservative in the way we booked them original.

Okay, great. Thanks, guys.

Nicolas Pope, Cowen and Company.

Good morning, guys.

Good morning, Nick.

I'm trying to understand a little bit with the divestiture activity you had, where you talked about Anadarko sales were at $340 million. I'm looking at the 10-K, talking about $370 million, but you all showed $400 million of divestitures in the fourth quarter. I was trying to reconcile those numbers. Were there additional sales, or is there something with the spend?

This is Javan again. Yes, we had several additional sales. We sold the Anadarko Basin package, as you mentioned for $340 million, round number. We sold some non-operated assets over in Terryville, which is in far east Northeast Texas, non-operated asset there. We also sold a little bit of acreage in the Permian, the Bison acreage. We sold those. When you add those altogether --

Non-op Rockies.

Yes, we had a little non-op Rockies package we sold as well. What was the total number?

$404 million.

$404 million, when you added it all together.

Was there any production associated with that? Or was that later in the quarter and not an effect on the production numbers?

There was some production. It was all pretty late quarter, not huge production numbers. Not near as big as the Anadarko Basin, but there was some production impact, yes.

Is that impactful going forward in 2014? Do you know what the volumes impact are of the non-Anadarko stuff?

It's rolled into our guidance. We factored again.

We factored it in. We're not changing our guidance.

Yes, our guidance isn't changing.

Got it. Okay, that's all I had. Thanks, guys.

Thanks, Nick.

Mike Kelly, Global Hunter Securities.

Hi, guys. Good morning. Looking at slide 18, this is a five-year development plan in the Eagle Ford. I know historically you've had a fairly high threshold, IRR threshold, before you'll actually put capital to work. Now, we're seeing IRRs potentially at 15%, 20% in the area 1, versus 50% previously. I'm just curious if that's really acceptable to you, we could see capital allocated laid out here, or is it potential to really just core up the Eagle Ford and just concentrate on area 3 going forward here?

Mike, This is Javan again. If you could see the map of the geology of this, and look at where the porosity is better or worse, what you would see is that the eastern portion of area 1 is substantially better than the western portion. That's why if you look at the maps that have all the sticks on them, we haven't drilled very many wells on the western edge of area 1. We focused more on the eastern edge. We don't believe there's any reason why the eastern portions of area 1 shouldn't work, and shouldn't work at decent returns, if we just get our completions right and our lateral length where they ought to be. We are very confident that over time we can make those things make our hurdles.

I recognize that if you go back and look at that type curve today, and you say that doesn't make a 25% rate of return, which is really our drilling hurdle, and so how are you so optimistic you can do that? Our answer is we think that the combination of longer laterals, better fracs, lower cost that we can get there with these wells. We have programmed our stuff into the areas that have essentially the best porosity in that portion of the field. Over time we expect that that eastern portion of area 1 will prove to be the best portion of area 1, and that it will have good enough economics to stack up. What we hope is that as we do all these things, and as we continue to improve our operations, continue to raise our cost, continue to lengthen our laterals, continue to work on our fracs that we can prove up even more of this acreage. You'll have a development plan that goes well beyond 2018, into other portions of areas 1, into more portions of area 2. You get a little gas price relief, big portions of area 5. But those are things that we're working on doing, as we go forward. But right now, I think we're fairly confident that those portions of area 1, when we get to them, and after we have this success we expect of this year, that we'll prove that up.

Okay, so area 1, you've got right now in your chart, 35,000 acres. How much of that would you put in this higher, better quality acreage as the eastern portion? If we wanted to risk, how much is eastern?

If I was doing it, I would look at my five-year development plan, and I would say how much of that five-year development plan is an area 1? That's what I'd say is the part that I would call economic at this point.

And help me out on that, what's that number, the five-year?

I actually don't have (inaudible). You can get pretty close just by measuring the areas there.

Okay. Would you expect that eastern area, is that the 475 type curve, is that an eastern area economics? Or is that the average for the whole area 1?

That is the average for all of area 1. That's all the historical levels in area 1. You can see it in the type curve. If you look at it, it goes right down through the middle of all the data. The 5,000-foot lateral type curve goes right to the middle of all the data. That's all the historical data in area 1. What we've done then is we just put an uplift on the longer laterals, just they showed it up. I think those laterals could perform better than that. We'll probably drill them longer than that, and then we're going to frac them different than we've been fracking them. Again, we think the better area rock on the east side should perform.

Okay. I appreciate that color. As we try to model you guys out in 2014, any help you can provide on oil growth throughout the year would be helpful for us too, knowing that most of the capital will be allocated in this area 3, the gassier area in the Eagle Ford, company-wide or guidance if you had it?

I'd just have to say, look, it's not going to move a lot from our current percentages. A lot of what we complete in Eagle Ford is still pretty gassy. Our new venture programs which probably would be oilier are pretty early here. Most of our growth is going to look a lot like our growth last year. It should tick up in the first quarter just due to the divestiture of some gassy materials, the gassy stuff, but I wouldn't expect that it moves a lot past that in a dramatic way through the year.

Okay. Thank you, guys.

Joe Magner, Macquarie.

Thanks, good morning. Some clarification questions here, just to make sure I've got this straight. You haven't drilled any long laterals while you're just making a calculation on what those results might look like, based on drilling them longer than the 5,500-foot that you've drilled historically. Is that correct?

Joe, Jay again. We have wells of various lateral lengths. We have some sense of what that proportioning ought to look like, but yes, you're right. We haven't drilled a bunch of 6,500-foot wells and proven that that type curve is the right type curve yet. We really took the 5,000-foot curve that goes right through the middle of all the data, and we ratcheted it up to account for the longer laterals.

Okay. And the 2014 wells, they will be drilled, I guess, at least in area 1, will all be 6,500-footers?

Not all of them. There are a few that because of lease limitations, we can't quite get to 6,500 feet. The average well is going to be 6,500 feet, and there will be some longer than that.

Okay. Just to back up, how do you construct your EURs? Is this based on all of your actual wells, or is it based on an assessment of other wells that are drilled in area? Just kind of walk through the calculations, if you could?

Sure. First of all, in the Eagle Ford all these wells are based on a gas type curve. It's a gas type curve and then a yield is applied to it. When you look at these wells, we show these type curve in BOEs per day, but what we actually do is we look at gas production performance, and we'll take all the wells in an area, and we'll lay a line through the middle of that type curve. Through the middle of that is an average, and that's the type curve for the area. Then, we apply a yield to that. Unfortunately, it's a fairly complicated asset. There's a number of different areas of different gas performance, and there's also a lot of different yields as you move around the field. This is why averaging can be problematic.

That's how we build them. We don't include in these type curves offset operator data. One of the reasons I've always been more optimistic about area 1, especially the eastern portion, is there is some great wells not that far east of us up there. It seems like to us that our wells should be performing better than they are. We don't average those into our own internal type curves. We have so much acreage of our own that mixing in other people's stuff is just confusing, I think.

Okay. Back to the questions about the prospectivity of area 1, or I guess all of your Eagle Ford, for that matter, how much do you think at this point has been delineated?

The best way to look at that is look at where the sticks are, Joe. Where we drilled wells, we have a fairly good idea what we have, although I will say a lot of those wells that were drilled pre-2013 in some of those remote areas were old wells that weren't completed very well. We have a pretty good sense of what the geology looks like now. Our development plan clearly focuses on the portions that we think are right around our infrastructure, and are driving the best economics based on the geology. As we move away from those areas, we're getting more extensional and we need lower cost and better completions.

Okay. One last one, if CapEx were to go up later in year, based on success in some of the new ventures area, how would you look to cover any additional shortfalls? There was a mention of continuing to sell off non-core assets. What would fall into that bucket these days?

This is Javan again. We do have an asset right now we're marketing up in Montana, very northeastern Montana, some operated production we're going to be selling here shortly. That would raise some of the money for this, not enough. The rest is really going to come out of our revolver. We've got an undrawn revolver at this point.

And cash. We're starting the year with cash on the balance sheet of $280 million and then a fully undrawn revolver with $2.2 billion revolver base.

Okay. I'll leave it there. Thanks for the answers.

Scott Hanold, RBC.

Yes, thanks. Good morning, guys. Hopefully, just a couple of really quick clarifications first, when you reduced your well inventory, can you clarify? Is that just related to the fact that you're assuming longer laterals so there are less wells, and that your wellbore spacing isn't any different? Or was there also spacing between wellbores that changed?

The math should just be associated with longer laterals. We didn't change spacing at all. You're talking about the Eagle Ford now. This is Jay. We've only changed the lateral length.

Okay. With your spacing so far, you don't see any reason to change that assumption at this point?

Not at this point.

Okay, understood. Then, also in your new assessment, you've integrated the longer lateral. Did you also integrate the assumption bigger fracs and more (inaudible)? Or is that the opposite side your new assessment?

Great question. We did integrate the longer laterals. We did not integrate any benefit associated with bigger fracs, or alternate frac designs, and as we see that, we'll add that. Everything you see in the back, all those economics, assume that we're doing the same old fracs that we've always done.

Okay. Then stepping back and looking at your acreage, it looks like as you've moved to the Mexican border the performance of the wells so far haven't been as good as expected. Just at a high-level, do you all have a sense of what that might be? Is it just a depth issue? Is it oil maturity? Is there some other geological reason that causes that acreage not to perform as good as some of the more eastern stuff?

This is Javan again. You see the same trend up on the JV acreage. As you go get to the Northwest, you see this stuff. It gets shallower. It's oilier, but it's more of a dead oil system.

Less pressure.

Less pressure, and the porosity goes down. It's thick, and there's a lot of oil in the system, but it's just hard to get out of there. I think when you look at that as an engineer, you say there's a big target there. We ought to be able to make something out of this. I think in the long run it's an interesting resource, and we'll keep working on trying to make it work. Right today, we would have to say the eastern portions of our acreage look better to us. They're more economic for drilling right now.

Okay. What does this say about some of the JV acreage? Is your JV partner doing anything different on that asset that's getting them better performance? Or is that one thing we need to think about in terms of the JV acreage, as well as some of that stuff? It may look a lot like your western area 1?

This is Javan again. I will tell you, APC has been drilling longer lateral wells with some success, and that's one of the reasons we're so confident that this can work for us. They've been doing work with that. I think we have always viewed the far western acreage in the Anadarko JV as having not much value. They've done some testing out there, and if you look at where they've been drilling, it's real obvious where they see the value in the play. They haven't been doing a lot of drilling on the far western area of their acreage.

Okay. Geologically, from what you know where Anadarko's drilling longer laterals, is that somewhat similar to some of the stuff in area 1 that really isn't being targeted right now?

It's certainly very similar to the eastern portions of area 1. I'm not sure if it's as similar. There are some areas due north of our area 1 acreage where they've drilled some long lateral wells with some success. Again, I'm not pessimistic. I think long term, a lot of this area 1 stuff has real potential. We just need to keep working at it. Our focus right now, one of the advantages, let me back up a little bit, one of the advantages of our acreage position is that we can hold a lot of it without having to drill wells on all of it. When we look at what's the right way to play this out, for us we should drill wells in things we know our economic. We can hold all the rest of it. We don't have to go out and drill a whole bunch of wells that could potentially be subeconomic at this time in order to hold acreage. The right answer is you drill the stuff you know is going to work, and you hold that other stuff for the future, and then as you go toward the future, you experiment with that and try to make it work.

That's the advantage of the Eagle Ford in the way our leases are constructed. We're drilling the stuff that we think with today's technology, today's cost, has the best economics today. I still think, and I really believe this, that both Anadarko and ourselves will find ways to make some of this acreage that we right now would consider to be marginal, but will be economic in the future as we reduce cost, as we improve our techniques, and our artificial lift mechanisms, all those things, and our infrastructure. I think it's a significant resource potential, but as you can see from our five-year drilling plan, we know where we're going for the next five years. That's really we're focusing on the economics of the play.

Okay. That's very helpful, Jay. Thanks.

John Nelson, Citi Group.

Good morning. Just curious, what was average lateral length in the Eagle Ford of the 2012 drilling program, and what's budgeted for 2013?

John, this is Javan. I haven't calculated the average. It would be about 5,000 feet. The last couple wells we've been drilling, most of our wells, are at about a 5,000-foot lateral length. There have been some shorter ones in specific locations for leasehold type reasons, but generally it's a 5,000-foot lateral. What we're assuming here is we're going to move most of those wells to 6,500 feet.

Ballpark on those, 60%? Does that sound reasonable, or can you help us?

Probably higher than that, actually. There are some wells, again, for leasehold reasons where we can't extend laterals or we'll maybe be drilling shorter than 5,000 feet in a couple of cases, just to not leave corners. But generally, the program's going to be 6,500 feet. I would say probably, looking at the list, 90% of the wells are going to be longer than 5,000 feet this year.

That's very helpful. Then just staying in the Eagle Ford, you talked about well costs year-on-year being down 13%. Obviously, you're changing the well design a little bit, but I'm just curious, sequentially 4Q versus 3Q, are you guys still seeing efficiency gains on an apples-to-apples basis? Can you comment at all on that?

Yes, we are. We saw 14% reduction in costs from 2012 to 2013. I've got to give a lot of credit to people in South Texas and our drilling department and the completions group. They've done a tremendous job. We do a very extensive amount of work. We have a lean Sigma program there where we look at variance between wells on a per foot basis. We've made a lot of progress in eliminating what I'm going to call train wreck wells, but it's really wells that are outside of a significant variance on a cost per foot basis. That's what really drive performance improvement. We're drilling wells in a much narrower band of variance, and that band is generally moving down and to the right on cost per foot. Our completion costs, our completions, our system vendors and our sales are efficiencies a much higher. Our pumping efficiencies in terms of being ready to pump we need to pump have been moving up, big improvements on that. We're going to take those efficiencies that we're generating, that we continue to generate, and we're going to apply them to the longer lateral, larger frac wells. That will again improve our economics. This is where you've got a big asset with a ton of resource out there. This is the nature of the game. We're going to keep working our cost, our efficiencies, and the technology to drive continuous improvements and additions to our inventory over time. We're very confident that that's how these assets get played out.

Understood. I guess if we could just maybe try and quantify that, is that on an apples-to-apples basis, still maybe low-single digit savings, that you're seeing on a go-forward basis?

The savings are slowing down. We probably reduced costs 20% the year before last and 14% last year. Yes, if you're thinking how much better can we get on a 5,000-foot lateral with our old frac? If you're thinking in single digits this year, that's probably reasonable. As we change designs and move things around a little bit, there will be a bit of a learning curve on that as well. We still think there's room. The guys are still making progress. We haven't drilled a perfect well yet, but we have made substantial progress.

I'll leave it there. I'll just highlight that I think if you split the east area 1 and west area 1 slides out, that might be helpful in the market, giving you guys better value. Thanks, guys.

Yes, let me comment on that. The problem with it is, we don't have data right now that supports it. If you look at the data right now, the way our results worked in the third quarter, you don't see a significant distinction. Geologically, there is a distinction, and we're confident that over time, that will play out.

Fair enough.

Rudy Hokanson, Barrington Research.

Thank you very much. I know it's getting long. I just want to make sure I understand between looking at the ongoing progress of current programs, and also the new ventures, as we look at the modeling for the year. Should we presume that the production is probably going to be steady improvement quarter to quarter? I think what you said earlier is that anything from the new ventures shouldn't be anticipated as contributing until 2015?

This is Javan again. Yes, I think that's a reasonable assumption.

Okay. Also, in your guidance the costs aside from the cash G&A are relatively flat between the first quarter and for the entire year. Is that just to be conservative right now, or could we anticipate added costs coming in with some of the programs in case you do find something you want to build on that would come into the LOE, or any kind of improvements in terms of costs that all of that washes out as you're giving guidance right now when you look at the whole year relative to first quarter?

Yes, I would say that washes out, and we are just simply being conservative in assuming that costs remain relatively flat between the first quarter and the rest of the year. (inaudible)

Okay, thank you very much. Those are my two questions. I appreciate it.

Thank you. I'm showing no further questions at this time. I'd like to turn the conference back over to Tony Best, Chief Executive Officer, for closing remarks.

Thank you for your ongoing interest in SM Energy. We hope to see many of you at the Howard Weil Conference coming up, and we'll talk to you again next quarter. Thanks so much for dialing in.

Ladies and gentlemen, this concludes today's conference. Thanks for your participation. Have a wonderful day.