SM Energy Company
Q4 2013 Earnings Call Transcript

Published: 19 Feb 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the SM Energy Fourth Quarter and Full Year 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (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.

[David Copeland:]

Thank you, Shannon, and 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, pending 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, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call and the Risk Factors section of our Form 10-K that was filed this morning. We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery, or EUR, on this call. You should read the Cautionary Language page in our slide presentation for 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 I am the Company’s Executive Vice President, General Counsel and Corporate Secretary. I’ll now turn the call over to Tony.

[Tony Best:]

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’ll 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 divestiture of our Anadarko Basin properties at the end of 2013. So, we’re 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. Javan want to spend some time talking more about new venture efforts and plans in 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 are 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 year to-date, we are all around performance. I’m 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 our 2013 with good momentum and performed very well against our guidance. We achieved a new quarterly record per average daily production of 144,000 barrels of oil equivalents per day in the fourth quarter, while managing our cost within guidance. The only notable item related to our guidance that’s ever 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 equivalents. 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 drill bit in a given period. Our drilling F&D for 2013 was $7 and $0.77 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 the 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 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 3-stream basis. Since our inaugural year of 3-stream reporting our liquids volume 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 in reserves and production is a necessity for all E&P companies. But we try 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 it’s a 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.

[Javan Ottoson:]

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 will also provide non-operated inventory information for the Bakken/Three Forks in that package. I will be referencing this data occasionally during our discussions, so you may want to keep it handy. I will 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 periods. Our liquids growth in 2013 resulted in a 50

[Wade Pursell:]

Thanks, Jay. So starting on Slide 44, we show our financial position at 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 in our Anadarko Basin divestiture package at the end of the 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 at the borrowing base was $2.2 billion, and related commitments of $1.3 billion. So we have lots of liquidity to execute our 2014 business plans and beyond. On Slide 45, we 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 the peer group that we track. Our debt to trailing 12 months 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 and return [ph] below the peer average. Again, we have plenty of dry powder to increase activity on new venture plays with success. On Slide 47, we’ve 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 and 2013 was particularly impressive with 44% growth year-over-year. Debt adjusted per share measures are very important to us, and as we’ve shown in the slide this morning we’ve been performing well on those metrics for several years. So with that, I’ll turn the call back to Tony for his closing remarks.

[Tony Best:]

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 laid 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 that 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 program in the 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 with 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 to your questions.

[Operator:]

(Operator Instructions) Our first question is from Michael Scialla of Stifel. You may begin.

[Michael S. Scialla:]

Hi.

[Tony Best:]

Good morning Mike.

[Michael S. Scialla:]

Yeah, it looks like you are not backing away from that area 1 in Northern Briscoe area was like 10% in 2014 wells in the Eagle Ford are going to be in that area. What gives you the confidence that these new techniques are eventually going to improve the results there, and can you talk about the resource potential for that, maybe for the entire Eagle Ford year-end 2013 versus where was it year-end 2012?

[Javan Ottoson:]

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

[Michael S. Scialla:]

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

[Tony Best:]

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 in the area 1 area, it’s a big area and we reduce the type curve by quite a bit. So that’s where most of that resource potential was, and I know everybody risk these numbers anyway, and I’m sure people were risking area 1, but it certainly is a disappoint. We expected to see better results there this year, and it’s a combination of things, we took the better portions of the area and parse them out into their own type curve areas which obviously hurts the average in the remaining area. And then our wells that were in area 1, just didn’t perform as well as we like, when you combine that then with the 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, and we certainly think we can improve on it. Now we’ll go on and improve on it and that something that we have to prove up this year.

[Michael S. Scialla:]

Got it, okay. And switch over to the Permian, the Sweetie Peck area was like your – you are going to develop at least to be horizon – horizontally. Is there anything in your proved reserves for the vertical wells in terms of PUDs there or is that just everything you’re doing there going to be incremental in terms of reserve potential?

[Javan Ottoson:]

This is Javan again. If there is anything left PUD wise on a vertical, this is very small, and I don’t know the exact number, it’s going to be very, very small. Those wells just don’t work as well as the other things we’re doing and typically we won’t keep PUDs on that we don’t think will drill of course in a five year period. Most of the potential is going to be horizontal. The great story though, we drilled these wells for many years, we have 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 there drilling, put the frac into the [indiscernible] stepping between the shales. So, just it keeps on dividing in the Permian.

[Michael S. Scialla:]

How about in terms of the Buffalo prospect with the E-zone? Is that look like based on and realize that you only have 30 days worth of production history on one well there. Do you think that looks like a viable target or is it now looking like 15 might be a better target for your play?

[Javan Ottoson:]

Well, we went to the B first, because we had experienced 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 results here by drilling a longer well that is obvious to us. There were some – some of the frac, we pumped – we pumped the best shale we could. We did have some, still little higher than we expected and some go lower based on the microseismic we did. I think we can probably improve our frac design as well, maybe are targeting on the wellbore. So we have some things we can improve on that B efforts. But that said, I think these are very attractive target, if you look at people completing wells just south of us there has been some terrific D wells completed. It’s thicker, that is where we are going to go next.

[Michael S. Scialla:]

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

[Javan Ottoson:]

Good day.

[Operator:]

Thank you. Our next question is from David Tameron of Wells Fargo. You may begin.

[David R. Tameron:]

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

[Javan Ottoson:]

Last year when we did our type curve working, I think that was the first year we’d ever presented type curves for anything. But we averaged a very large area together which included a lot of what we are now calling area 4, area 1, area 6. And, we frankly – we probably should have parse the data more carefully when we average – averages can be very deceiving as you know. And we included some wells on area 6, area 4 which were pretty good wells. And which drove the averages of area 1 up some. If you just took those out, and parse them out and said okay, those were obvious development areas what about this area 1, we would have gotten a lower results last year as well. I didn’t realize as we went through the year, we really thought when we went into third quarter this year and completed a bunch of wells that as were completing along the east side of area 1, that those wells would significantly outperform the remainder of area 1, and they just really happen. And I don’t know all the reasons for that. Some of it maybe infrastructure, but they are shorter, they are 5,000 foot lateral wells. They are completed with fairly conservative frac designs. I think we just need to be more aggressive, and that is what we are going to do this year. So as a result, area 1, after you take out the good areas basically and you average down the poor areas, there was a reduction in EUR. I don’t know the exact number in that particular area, but overall, yes, we had a pretty good 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. So when we took the good parts out and left the other parts the average changed.

[David R. Tameron:]

Okay. That’s helpful. And then, Tony, can you talk about what you’re seeing at Galvan Ranch range, what are you seeing in that area and how that’s stacking up with your expectation?

[Tony Best:]

I think we’d say that although the type curves 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 is some terrific acreage down there and I think the wells have generally outperformed our expectations and of course that’s where a lot of our activity was last year. And I think when you look at the performance of the company overall, it was driven by outstanding well performance in that area and 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.

[David R. Tameron:]

Okay. One more from me. Talking about 2014 CapEx and your plan that’s out there, what are the wildcards in that plan? What do you see now as 12 months down the road? You could say we ran into the year with this plan and based on these results we allocated some capital. What would be the wildcards?

[Javan Ottoson:]

Well, this is Javan again. The new wildcards are the new venture programs and how fast we’d ramp up. I think 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. And then, the Permian really depends a lot on what happens with this B well, we’re going to drill it to 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 the third rig, but that would be late year. So I think what you’ll see and there is some likelihood that when we get to mid-year, if things are going well that we would increase capital at mid-year. I don’t have a number for you on what that could be. It just depends on how many of these programs are working and I will say that anything we do in the second half obviously is not going to have a huge, great impact in 2014. It would have an favorable impact in 2015 of course.

[Tony Best:]

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.

[David R. Tameron:]

Okay. And I’ll let somebody else jump in. Thanks. Thanks for the color.

[Tony Best:]

Thank you. Thanks.

[Operator:]

Thank you. Our next question comes from Michael Hall of Heikkinen Energy Advisors. You may begin.

[Michael Hall:]

Thanks. Good morning.

[Tony Best:]

Good morning, Hall. Good morning.

[Michael Hall:]

I guess 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 that EUR or is it really just the absolute levels of oil yields from the wells early on?

[Javan Ottoson:]

Yes, that’s a great question. This is Javan, and 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 kind of level out. So, you do have to be careful not to over forecast your yields based on real early results.

[Michael Hall:]

Okay. I guess trying to – is that changing yield declining more quickly than you had thought or is this just the absolute level of yield was lower?

[Javan Ottoson:]

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

[Michael Hall:]

Okay, helpful. And then, bigger picture on the Eagle Ford. With this kind of changing view around the inventory, I guess does this make you want to press even harder on the new ventures program, and how does it change how you think about the Eagle Ford in terms of the broader portfolio, if at all?

[Javan Ottoson:]

This is Javan again. I think you’ve got to put this into context. And we have a real strong four, five year drilling program here in the Eagle Ford, has very good economics. As we improve our drilling costs, our technology, our lateral lengths we think we’ll improve up even more that. That’s a huge focus for us is to continue develop additional inventory in the Eagle Ford. With that said, I think it’s interesting you asked 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 it to grow this company, and we’re certainly pursuing it at a pace that we think is rationale given the risks associated with it, and there is a big price 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 we’re working on, but we’re going to pursue at a pace where we prove things up before we spend too much, and we have to look at the opportunity to do that because we have these other grade assets that we can work on in the meantime.

[Tony Best:]

Michael, this is Tony. I also want to point out that if you go back to Slide 12 that we provided in the presentation, I think we have to keep this in context. I mean 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 0.25 billion barrels equivalent in that play, and that’s important. Jay has 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. And I think if you refer back to those reserve numbers, I think you can see why that has remained as strategic asset for us and we’ll continue to offer gain in the Eagle Ford.

[Michael Hall:]

That’s helpful commentary. I appreciate it guys. And then, I guess real quickly in the Permian, I just noticed on the Sweetie Peck wells, you had used three different types of proppant on those. Any read there yet or game plan going forward of which might be better, looks like the white sand was maybe performing better. I don’t know if that’s just rock or any view on the profit there.

[Javan Ottoson:]

Well, this is Javan again. Yes, thank you for that question. We are testing white, sand resin coated, the premium type 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 and so whenever you do three wells and beyond they work out a little differently. You can ask yourself well 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 and we have not seen that. So 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 wells, keep that around wellbore stuff open and frankly save the money versus this. I know people will argue, well, you don’t see the benefit of ceramics to way down the road. The problem with that is way down the road is not worth very much from the PV standpoint. So the cost difference is substantial. I think generally our conclusion at this point is that you didn’t see a big benefit on the initial rates. You probably can’t afford to do it. We’ve looked again on a bunch of testing we’ve done what we call B fit testing prior to fracs and look at what the closure stresses would be on this rock and we think white sand will cover it. I think we’ll probably feel safe on that again and use a little premium resin coat on the tails just to be sure, but I think we’re moving towards sand.

[Michael Hall:]

Okay. That’s helpful. And then, also just how many wells do you test plan in Buffalo in 2014?

[Javan Ottoson:]

Well, really the program is an exploration program. We planned to drill to Tatonka and we planned to drill this B well and then we’re going to look at our results. We don’t have any other wells budgeted at this point.

[Michael Hall:]

Great. Thanks, guys.

[Tony Best:]

Thanks.

[Operator:]

Thank you. Our next question is from Pearce Hammond of Simmons & Company. You may begin.

[Pearce W. Hammond:]

Good morning.

[Tony Best:]

Good morning, Pearce.

[Pearce W. Hammond:]

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?

[Javan Ottoson:]

Generally you should see it go up. Pearce, most of what we sold in the package was gassy. So I believe it shouldn’t. 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 produce quite a bit of gas. Generally it’s going to move oilier as we go forward particularly because of the asset sale, but it won’t be dramatic.

[Pearce W. Hammond:]

All right. Thank you for that, Jay. And then, on a leading edge basis, kind of where do you see Eagle Ford oil differentials right now and as you look out in 2014?

[Javan Ottoson:]

Well, this is Javan again. Our contracts basically give us a $17 deduct to LLS and I should note just for everybody’s comfort that those contracts are pretty well tied in. There are really very little variation based on condensate gravity and very little wiggle room on condensate gravity in those contracts. One of them is actually, it’s actually fixed. The other one floats, but only a little bit. So I think what you can 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. So when you look at the WTI spread we’re now going to be looking at numbers well below our normal expectations, probably at $14 kind of discount to WTI, which is higher than we probably would have forecasted well back, but WTI has come up relative to LLS. But I think the best way to think about our stuff in the Eagle Ford is take LLS less $17 and that’s the number we’re going to get.

[Pearce W. Hammond:]

Okay. Thank you, Jay. And then one last one for me. Across your East Texas areas Independence, Deep Pines West, Deep Pines Central, Deep Pines East, can you give kind of a targeted well cost range that you’re looking at in development mode in those areas?

[Javan Ottoson:]

Sure. if you look at, say, Independence at 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 costs are probably going to be $13 million, $13.5 million. That’s probably not a bad place to be. I think we can get it down to $11.5 million, maybe $11.5 million to $13.5 million over time. Deep Pines Central are little shallower, probably more in the $11.5 million – maybe $9.5 million to $11.5 million kind of range. And 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. So not cheap, not for the faint heart, but a lot of overpressure. We really like that. We really like overpressure.

[Pearce W. Hammond:]

All right. Thank you for that color.

[Operator:]

Thank you. Our next question comes from Matt Portillo of Tudor Pickering Holt. You may begin.

[Matthew Portillo:]

Good morning, guys.

[Tony Best:]

Good morning, Matt.

[Matthew Portillo:]

Just a quick follow-up question on the Eagle Ford. You guys did mention some of the new completion techniques you’re testing in area 1 although I see 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. And a second follow-up question, just in regards to downspacing around area 3. Is there any potential upside to increased inventory depths through downspacing as you guys progress in the program?

[Javan Ottoson:]

This is Javan again, 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 and we’re doing that wherever we can with the leases the way they’re configured. We can’t 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. So 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 a – I’ll call it a back frac here today. One of the things we’re hoping for with that 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 and that would have two potential positive impacts. One is you 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 SIM Ops related downtime. But it could also allow you to space these wells closer together and 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 and that’s part of the experiment we’re doing.

[Matthew Portillo:]

Great. And then, in terms of the cost there, any color you could provide on kind of incremental cost associated with the sand contend.

[Javan Ottoson:]

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

[Matthew Portillo:]

Great. And then, just my last question on the Bakken. You guys talked about some of the downspacing opportunity. Wanted to get a little bit more context in terms of how you think about the drilling program there. Over time you’ve talked about a few of the other plays in terms of acceleration. So, wanted to see if there was potential for Bakken acceleration with downspacing success. And then, you mentioned a few other kind of emerging Bakken opportunities within the basin. Could you put those in the context as you’ve kind of 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?

[Javan Ottoson:]

This is Javan again. Certainly the downspacing portions would stack up very, very well with their great incremental opportunities, with very similar reserve levels or pretty similar reserve levels we won’t do them, and that’s a great opportunity. Some of the more extensional stuff, the Bakken and Gooseneck, they work in say, 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 with these rig count in Montana has been pretty flat. There’s still a lot of gas being flared up there. I think the oil industry is looking real hard at, how much activity, increase could you live with. I tend to look at these inventories 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.

[Matthew Portillo:]

Great. And then my last question 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 then kind of the Sweetie Peck drilling program.

[Javan Ottoson:]

Well, I think the Sweetie Peck, you’re going to eventually see these wells in the $7 million to $8 million kind of range once, and as I said, as we go to white sand and a little bit of maybe premium proppant. That’s really the biggest cost driver there and then getting to pad drilling. So, I think $7.5 million to $8.5 million for, we’re pumping large frac jobs here, so and they are very large and they are 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 had an add one for a few months. Now, 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. And on the East Texas again, right now we’re really drilling parallel horizontal lease 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 the success leg, Tony talked about that we can drive our cost. We know we can drill wells and people asked me about, well, these wells in the East Texas look like expensive Galvan wells. Well, no our Galvan well was pretty expensive too and now we’re drilling them in 10 days. So, I think there is a huge opportunity in that play and we’re very excited about it.

[Matthew Portillo:]

Thank you very much.

[Operator:]

Thank you. Our next question is from Brian Velie of Capital One. You may begin.

[Brian Velie:]

Good morning, guys.

[Tony Best:]

Good morning, Brian.

[Brian Velie:]

Quick questions here, just the first one here on the extended lateral length 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 is new lateral length assumption?

[Javan Ottoson:]

All the work in the appendix, assume 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.

[Brian Velie:]

Okay. And then another question on the Buffalo area wells, you mentioned that there is still a little bit of work to be done, and it seem to be it’s something that you want to go after versus the B, what kind of EUR range do you think makes that interesting to you or what’s going after in the future?

[Javan Ottoson:]

I think really to make the B work at our cost you need about 400,000 barrel well.

[Brian Velie:]

Okay.

[Javan Ottoson:]

That’s the kind of numbers you need to be at sort of what we had estimated for our low-end range for Sweetie Peck. There is a lot of differences in the rock as we have learned more and more about it. The rock at the Tatonka, the B section is clearly more permeable. You saw a lot more pressure bleed off in there. I’d think the type curve shape is going to be substantially different. One of the reasons it’s so hard to know when we make these conclusions is that, we got to see what type curve really looks like out overtime. We didn’t see the real high pressures early on that we typically see at Sweetie Peck. So it’s a very different shape type curve there, and you have seen that and offset operator results as well the IPs of that areas just not that been as high. So we will just have to see how that works.

[Brian Velie:]

All right, great. And then last one real quickly; in the East Texas acreage, there is different areas you have there, you broke down cost expectations, is there any way to really breakdown kind of oil cost expectations for those areas?

[Javan Ottoson:]

We have been testing intentionally kind of testing the down to limits. So a lot of the early wells, you are going to see if that is going to be fairly low yield, and that’s just the way it is. We are trying to figure out how much our acreage is perspective, certainly that was what we did on the Eagle Ford test you saw, that was probably the lowest yield well we drilled there, and you are going to see some great wells I think in the Woodbine we come up, but some of those will be sort of on the low-end as well, we are testing at certain limits. We are going to aim for things that are higher oil test and most of our Galvan acreage, I will say it that way because the cost is little higher, but your pressure is higher too, so I think there is a lot of opportunity there.

[Brian Velie:]

Okay, that’s very helpful. Thanks a lot.

[Tony Best:]

Thank you.

[Operator:]

Thank you. Our next question comes from Welles Fitzpatrick from Johnson Rice. You may begin.

[Welles W. Fitzpatrick:]

Hey guys, thanks for taking the question.

[Tony Best:]

You bet.

[Welles W. Fitzpatrick:]

In the PRB, when you are looking to complete those eight Frontier wells. Are they going to be, I think you start off in the northern near that local or are you going to start down or just scattered.

[Tony Best:]

The first well we are going to complete is on the southern end, and then we have a – right now we are drilling a well up on the north end, right in the local again, which actually 640 well, not 1280, the rest of the wells are kind of scattered across the next well down I think is dynamite location which is right smack that in the middle of the block with just 1280 location and then rest of the wells will be scattered around the block. So by the time you get to the end of this year, you will have wells pretty much through the whole block and that’s really kind of what we are waiting for before we put pilot development, put everything in the back in the appendix in the last half that we do with the development play.

[Welles W. Fitzpatrick:]

Okay, great. And then just one other one; it looked like Bakken EURs might have creeped up, is that correct or is there any potential…

[Tony Best:]

Yeah, that’s right.

[Welles W. Fitzpatrick:]

Or is that just based on recent results or?

[Tony Best:]

I think one of the great things we have seen increases in our Bakken EURs pretty much every year. Some of that is due to just seeing some more, having more experience and maybe being a little more optimistic on our B and factors in D ends [ph], terminal declines as we looked at them, but we have seen improved performance in our Bakken wells pretty much every year as we have gone out. So we were apparently fairly conservative in the way we looked them originally.

[Welles W. Fitzpatrick:]

Okay, grateful. Thanks guys.

[Javan Ottoson:]

Thanks.

[Operator:]

Thank you. Our next question is from Nicolas Pope, Cowen and Company. You may begin.

[Nicholas P. Pope:]

Hey, good morning guys.

[Tony Best:]

Good morning, Nick.

[Javan Ottoson:]

Good morning, Nick.

[Nicholas P. Pope:]

Hey, trying to understand a little bit with the divestiture activity you had – kind of where you talked about Anadarko sales were I guess 340, I’m looking at the 10-K, you kind of talking about 370, we all showed $400 million of divestitures in the fourth quarter. Now I was just trying to reconcile those numbers and where there additional sales or is there something with worth of [indiscernible].

[Javan Ottoson:]

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 the – in far east North East Texas, non-operated asset there. And we also sold little bit acreage in the Permian, the Bison acreage we sold those. So, when you add those all together…

[Wade Pursell:]

And non-op Rocky.

[Javan Ottoson:]

Yes, little non-op Rocky back we sold as well. So it will turn into. What was the total number?

[Wade Pursell:]

404.

[Javan Ottoson:]

404 when you add it all together.

[Nicholas P. Pope:]

And was there any production associated with that? Or is that later in the quarter, not an effect on the production numbers?

[Tony Best:]

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

[Nicholas P. Pope:]

And is that impactful going forward in 2014? At the volumes impacted other non Anadarko stuff?

[Tony Best:]

Well, it’s rolled into our guidance, actually. We factored [indiscernible] yes, our guidance isn’t changing.

[Nicholas P. Pope:]

Got it. Okay. That is all I have. Thanks guys.

[Tony Best:]

Thanks Nick.

[Operator:]

Thank you. Our next question is from Mike Kelly of Global Hunter Securities. You may begin.

[Mike D. Kelly:]

Hi, guys good morning.

[Tony Best:]

Good morning, Mike.

[Mike D. Kelly:]

Looking at Slide 18, this is a five year development plan in the Eagle Ford. I know historically you had a fairly high threshold – IR threshold for you actually put capital to work. And now, we are seeing IRs potentially at 15%, 20% in area 1 versus now 50% previously, just curious if that’s really acceptable to you. And we could see capital allocated in the way laid out here or is that potential for really just core up the Eagle Ford and just concentrate on area 3 going forward here.

[Javan Ottoson:]

Yes, Mike, this is Javan again. When we look at the – if you can see the map of the geology of this, and look at where the porosity is better or worse. What would you see is that the eastern portion of area 1 is substantially better than the western portion. That is 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. And we focus more on the eastern edge. We don’t believe there is any reason why the eastern portions of area 1 shouldn’t work. And should work at decent returns if we just get our completions right in our lateral lengths where they ought to be. And we are very much 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 well that doesn’t make a 25% rate return which is really kind of our drilling hurdle. And so, how are you so optimistic you can do that. Our answer is we think that the combination along the laterals, better fracs, lower costs that we can get there with these wells. And so we’ve programmed our stuff into the areas that have the best, essentially the best porosity in that portion of the field. Overtime we expect that the eastern portion of area 1 will prove to be the best portion of area 1 and that it will have better 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 reduce our costs, continue to lengthen our laterals, continuing work on our fracs that we can prove that even more of this acreage. So you will have an development plan that goes well beyond 2018 into other portions of area 1 in that area have more portions of area 2. We deal with gas price release [ph], big portions are already five, but those are things that we are working on doing as go forward, but right now I think we are fairly confident that those portions of area 1 when we get to them and after we have this success we expect for this year that we’ll prove that up.

[Mike D. Kelly:]

Okay, so area 1 you got it right now, and your charges are 35,000 acres how much of that would you count according this kind of higher the better quality acreage in the eastern portion. If you wanted to risk it how much is?

[Tony Best:]

If I was, if I look at my five year development plan I would say, how much of that five year development plan in area 1 and that’s what I would say is the part that I would call economic at this point.

[Mike D. Kelly:]

Help me out on that what is, what’s that number during the five year?

[Tony Best:]

I actually don’t haven’t [indiscernible] that, but you can get pretty close just by measuring the areas there.

[Mike D. Kelly:]

Okay, and would you expect that eastern area is that with the 475 type curve is that of that eastern area economics or is that the average for the whole area 1?

[Tony Best:]

That is average for all of area 1, that’s all the historical wells in area 1. You can see it in that type curve if you look at it, its goes right down through the middle of all the data, right the 5,000 foot lateral type curve that goes right through the middle of all the data. That’s all the historical data in area 1 and what we have done then as we just put an uplift on the longer lateral just ratio to that. So I think those lateral could perform better than that we probably drilling longer than that and then we are frac them different and we’ve been fracking, so again we think the better area rock on the east side should perform.

[Mike D. Kelly:]

Okay, I appreciate that color. And just one for us as we try to model that out in 2014, any help you can provide on oil growth throughout the year would be helpful for us to knowing that most of the frac will be allocated really gas area of the Eagle Ford so companywide oil guidance if you had it?

[Javan Ottoson:]

I would just have to say look it’s not going to move a lot from our current percentages and a lot of well we complete in the Eagle Ford is still pretty gassy, our new venture programs which would be probably oilier or pretty early here, so most of our growth is going to look like a lot like our growth last year. It should tick up in the first quarter just due to the divestiture of some gassy materials, gassy stuff, but I wouldn’t expect that it moves a lot pass that in a dramatic for the year.

[Mike D. Kelly:]

Okay, thank you guys.

[Javan Ottoson:]

Thanks.

[Operator:]

Thank you. Our next question is from Joe Magner of Macquarie. You may begin.

[Joseph Magner:]

Thanks. Good morning. And just some quick clarification questions here just to make sure I got this straight. You haven’t drilled any long laterals well you are just sort of making a calculation on what those results might look like based on joining longer than the 5,500 what you have drilled historically is that correct?

[Javan Ottoson:]

Well Joe, Javan again. We have wells of brisk lateral lengths. So we have some sense of what that proportion kind of look like, but yeah, you are right. We haven’t drilled a bunch of 6,500 foot wells and proven 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 that data and we’ve ratcheted it up to account for the longer laterals.

[Joseph Magner:]

Okay. And then the 2014 wells they won’t be drilled I guess eastern area 1 will all be 6,500 flourishes up?

[Javan Ottoson:]

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

[Joseph Magner:]

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

[Javan Ottoson:]

Sure, well first of all in Eagle Ford all these wells are based on a gas type curve. Okay, so it’s a gas type curve and then a yield is applied to it. So, when you look at these wells we show these type curves and BOEs per day, what we actually do is we look at gas performance, gas production performance. And we’ll talk all the wells in the area and will align through the middle of that type curve, through the middle of that as an average and that’s the type curve for the area. And then we apply a yield to that and unfortunately it’s fairly complicated asset. There is a number of different areas, there is different gas performance and then there is also a lot of different yields as you move around the field. So, this is why averaging can be problematic. But that’s how we build then, we don’t include in these type curves offset operator data. One of the reasons I have always been more optimistic about area 1 especially the eastern portion there are some great wells, not that far east of us up there, and it seems like to us that our well should be performing better than they are. So, but we don’t average those into our own internal type curves.

[Tony Best:]

We have so much acreage of our own that mixing and other people stuff is just confusing so.

[Joseph Magner:]

Okay and I guess back to the question about prospect to the area 1, I guess all of your Eagle Ford for that matter, how much do you think at this point has been delineated?

[Javan Ottoson:]

Well, the best way to look at that is look at where the sticks are, Joe I mean 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 where old wells that weren’t completed very well. But 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 that are driving the best economics based on the geology and as we move away from those areas we are getting more extensional and we need lower costs and better completions.

[Joseph Magner:]

Okay. And then just last one. If CapEx were to grow up later in the year based on success on some of the new ventures area, how would you look to cover any additional shortfall or is there a mention of continuing to sell off non-core assets. What I guess, what would fall into that bucket these days?

[Javan Ottoson:]

Well it’s Javan again. We do have an asset right now. We are marketing up in Montana Northern – very Northeastern Montana. Some operated production we are going to be selling here shortly. That won’t raise enough money – that would raise some of the money for this not enough. And the rest is really going to come out of our revolver. We’ve got an undrawn revolver at this point.

[Wade Pursell:]

And cash, and we are starting to do with cash on the balance sheet of $280 million and then fully undrawn revolver of $2.2 billion borrowing base.

[Joseph Magner:]

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

[Tony Best:]

Thanks, Joe.

[Operator:]

Thank you. Our next question is from Scott Hanold with RBC. You may begin.

[Scott Hanold:]

Yes, thanks. Good morning, guys.

[Tony Best:]

Good morning, Scott.

[Scott Hanold:]

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 to their less wells and that your wellbore spacing is any different or was there also spacing between wellbores that changed?

[Javan Ottoson:]

The math should just be associated with longer laterals. We didn’t change spacing at all. You’re talking about the Eagle Ford now, and this is Javan. So we’ve only changed the lateral length.

[Scott Hanold:]

Okay. So with your spacing so far, do you have any reason to change that assumption?

[Javan Ottoson:]

Not at this point.

[Scott Hanold:]

Okay, understood. And then, also in your new assessment, so you’ve integrated the longer lateral. Did you also integrate the assumption of bigger fracs than more proppants or is that sort of off the tied to your new assessment?

[Javan Ottoson:]

Great question. No we did not integrate. We did integrate the longer laterals. We did not integrate any benefit associated with bigger fracs or change frac – alternate frac designs and as we see that we will add that. So everything you see in the back, all those economics assume that we’re doing same old fracs that we’ve always done.

[Scott Hanold:]

Okay. And then, stepping back and looking at your acreage and it certainly looks like as you move to Mexican border, the performance of the wells so far hasn’t been as good as expected in just at a high level, I mean do you 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 in the mortgage brings [ph]?

[Javan Ottoson:]

This is Javan again. We see the same trend up on the JV acreage. As you go to the northwest, you see this stuff. It gets shallower, it gets oiler, but it’s more of a dead oil system, less pressure and the proxy goes down. It’s thick and there is lot of oil in the system. So it’s just hard to get out there. And so, I think when you look at that as an engineer you say, look here is a big target there, we all will be able to make something out of this. And so 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.

[Scott Hanold:]

Okay. So what does this say about some of the JV acreage, I mean, 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 may look a lot like your western area 1?

[Javan Ottoson:]

Well, this is Javan again, and I would say 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. So they’ve been doing work with that. I think we have always reviewed the far western acreage in the Anadarko JV as having not much value and 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 and they haven’t been doing a lot of drilling on the far western area of their acreage.

[Scott Hanold:]

Okay, okay. So geologic, from what you know where Anadarko is drilling longer lateral, is that somewhat similar to some of the stuff in area 1 that really hasn’t been targeted right now.

[Javan Ottoson:]

Well, it certainly is very similar to the eastern portions of area 1. I’m not sure if it’s a similar – there are some areas due north of our area 1 acreage where they drill some long lateral wells with some success. So I think I’m not pessimistic. I think long-term a lot of this area 1 has real potential and we just need to keep working at it. Our focus right now is that one of the advantages – when we back up 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. So when we look at, okay, what’s the right way to play this out? For us, we should drill wells in things we know we’re economic and we can hold all the rest of it. So we don’t have to go out and drill a whole bunch of wells that could potentially be said economic at this time in order to hold all the acreage. So the right answer is you drill the stuff, you know it’s going 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 at Eagle Ford in the way our leases are constructed. So 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 and as we improve our techniques and our artificial lift mechanisms, all those things, and our infrastructures. So 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 and that’s really we’re focusing on the economics of the play.

[Scott Hanold:]

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

[Operator:]

Thank you. Our next question comes from John Nelson of Citigroup. You may begin.

[John C. Nelson:]

Good morning.

[Tony Best:]

Good morning, John.

[John C. Nelson:]

Good morning. What was the average lateral length in the Eagle Ford of the 2012 drilling program and what’s budget for 2013?

[Javan Ottoson:]

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

[John C. Nelson:]

So ballpark on those 60% does sound reasonable or are those…?

[Javan Ottoson:]

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

[John C. Nelson:]

That’s very helpful. And then just staying in the Eagle Ford, you talked about well costs year-on-year being down 13% and obviously you’re changing the well design a little bit, but I’m just curious sort of sequentially 4Q versus 3Q. Are you guys still seeing efficiency gains like kind of an apples-to-apples basis or comment on that?

[Javan Ottoson:]

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

[John C. Nelson:]

Understood. I guess if we just maybe try and quantifying that, is that on an apples-to-apples basis, still maybe low single-digit savings here that you are kind of seeing on a go-forward basis?

[Tony Best:]

Well, the savings are slowing down. We probably reduced cost 20% year before last and 14% last year and yes, if you are thinking how much better can we get on a 5,000 foot lateral with our old frac, if you are 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, but we still think there is room. The guys are still making progress. We haven’t drilled the perfect well yet, but we have made substantial progress.

[John C. Nelson:]

I will leave it there. I will just highlight, 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.

[Tony Best:]

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

[John C. Nelson:]

Fair enough.

[Tony Best:]

Thanks Scott.

[Operator:]

Thank you. Our next question is from Rudy Hokanson of Barrington Research. You may begin.

[Rudy A. Hokanson:]

Thank you very much. I know it’s getting long. I just wanted to make sure, I understand between looking at the ongoing progress of the 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, and I think what you said earlier is that anything from the new ventures, it shouldn’t be anticipated as contributing until 2015?

[Javan Ottoson:]

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

[Rudy A. Hokanson:]

Okay. And then also in our 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 cost 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 kind of washes out as you are giving guidance right now when we look at the whole year relative to first quarter?

[Wade Pursell:]

Yes, I would say that washes out and we are just simply being conservative and assuming that cost coming relatively flat between the first quarter and the rest of the year, we’ll update in every quarter though.

[Rudy A. Hokanson:]

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

[Tony Best:]

All right. Thank you, Rudy.

[Operator:]

Thank you. I am 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.

[Tony Best:]

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.

[Operator:]

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