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Executives

David Copeland – Senior Vice President, General Counsel and Corporate Secretary

Tony Best – Chief Executive Officer

Javan Ottoson – President and Chief Operating Officer

Wade Pursell – Executive Vice President and Chief Financial Officer

Analysts

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

David R. Tameron – Wells Fargo Securities LLC

Michael Hall – Heikkinen Energy Advisors

Pearce W. Hammond – Simmons & Co. International

Matthew Portillo – Tudor, Pickering, Holt & Co.

Brian Velie – Capital One Securities, Inc.

Welles W. Fitzpatrick – Johnson Rice & Co. LLC

Nicholas P. Pope – Cowen Securities LLC

Mike D. Kelly – Global Hunter Securities, LLC

Joseph Magner – Macquarie Capital, Inc.

Scott Hanold – RBC Capital Markets

John C. Nelson – Citigroup Global Markets Inc.

Rudy A. Hokanson – Barrington Research Associates, Inc.

SM Energy Company (SM) Q4 2013 Earnings Conference Call February 19, 2014 10:00 AM ET

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 50:50 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 programs 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 sub-division of our operated area into tight curve regions. I think this map will be helpful to you as you look at other maps, I will 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 perform. As a result of our review, we have redrawn some type curve regions and parched out several new type curve areas now called areas 4 and 6, which had been the better performing portions of the Northern block of acreage.

We then average 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 poor 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, we 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 three 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 are working on to improve the economics and grow our economic inventory in the field. First during 2014, our plan is to extend lateral lengths on almost all our wells, but particularly in the higher liquids yield areas on the north side of the field. When you look at the economics data in the appendix you will know 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 the 6,500 feet.

In addition to extending laterals, we have been testing modified frac designs with higher sand loading. 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 we’ll be moving in the direction of higher sand concentrations on most of our completions.

Both extending laterals and using more sand will raise our cost, so we will be looking closely at the cost versus benefit of these changes throughout the year. With that said we are optimistic about the potential impact of these changes particularly for the eastern portions of area 1 I just discussed.

Slide 17 shows a map and at 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 a 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 are 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 APCs reported production over any three months period.

From a big picture standpoint our net quarterly production grow from this asset from fourth quarter 2012 to fourth quarter 2013 was 29% higher than our expectations and 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 3-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 count shown on the slide versus last year at this time.

Slide 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 well 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 cost to be low relative to cost per 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 proved 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 poor correlation work suggests that the Bakken is perspective 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 is 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.

Slide 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, so very similar to our 2013 programs.

I’d now like to shift over and talk about new ventures programs. I will 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 eight of them this year. We have updated our unrisked potential location count and potential resource for you on the slide and we are still using the same projected type curve we previously disclosed. By this time next year, we will have tested wells across most of our acreage positions as you can see.

We are 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 will 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’d 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 3133H and the CVX 4134 H. Details on these wells and their completions are shown with rigs on a 2-stream basis on Slide 34 along with an update on our Dorcus 3035 H well that we announced last quarter.

A couple of things seem 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 the per lateral foot basis and 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 at Lower Spraberry shale test as well. Our current unrisked inventory of Wolfcamp B location shown on this page assumes 880 foot wellbore space.

During 2014, we anticipate testing wells at this basin and reaching some conclusion on our testing of various frac proppants. We will also be drilling some longer lateral wells where possible and expect to have results on some of those this year as well.

Next I’d like to discuss our program for testing 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 result of our first Wolfcamp B test in the block. The Tatonka 1-H, a 5,500 and 60 foot effective lateral reentry of an existing vertical well tested at 549 barrels of oil equivalent per day or a seven day average and 376 barrels of oil equivalent per day for a 30 days at 89% oil. Again all these numbers on a 2-stream basis.

We believe that we have several opportunities to improve on this result, including lengthening laterals on subsequent wells. In the meantime, we are moving quickly to test the Wolfcamp B in the area and expect to have a completion there in the second quarter.

Turning to Slide 38, I’d like to end the discussion of our efforts in the Permian Shales with the plot we generated from public data showing the relative performance of our recent Wolfcamp B wells. First is, all of 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 the lateral length.

Our Tatonka reentry 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 are chasing and what we are 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 targeted in 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 Woobine the next slide, Slide 40 shows an illustration or cartoon of what we are chasing in the Woodbine. A number of our competitors had been targeting remaining oil around the edges of conventional Woodbine traps in areas north of our position that is not what we are 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 type unconventional sands along the shelf. This is why our acreage expense along the Edwards Reef Margin. In this area the Woodbine is hydrocarbon charged and significantly over pressured and we believe that a permeability barrier exists between our target and a higher perm West Sandstone to the north of us.

Slide 41, summarizes the result 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 in Deep Pines West last year, so that is old news. But certainly lands 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 the 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 a 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 high grade 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?

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.

Question-and-Answer Session

Operator

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

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Hi.

Tony Best

Good morning Mike.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

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 – Stifel, Nicolaus & Co., Inc.

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 – Stifel, Nicolaus & Co., Inc.

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 – Stifel, Nicolaus & Co., Inc.

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 – Stifel, Nicolaus & Co., Inc.

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 – Wells Fargo Securities LLC

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 – Wells Fargo Securities LLC

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 – Wells Fargo Securities LLC

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 – Wells Fargo Securities LLC

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 – Heikkinen Energy Advisors

Thanks. Good morning.

Tony Best

Good morning, Hall. Good morning.

Michael Hall – Heikkinen Energy Advisors

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 – Heikkinen Energy Advisors

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 – Heikkinen Energy Advisors

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 – Heikkinen Energy Advisors

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 – Heikkinen Energy Advisors

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 – Heikkinen Energy Advisors

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 – Simmons & Co. International

Good morning.

Tony Best

Good morning, Pearce.

Pearce W. Hammond – Simmons & Co. International

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 – Simmons & Co. International

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 – Simmons & Co. International

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 – Simmons & Co. International

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 – Tudor, Pickering, Holt & Co.

Good morning, guys.

Tony Best

Good morning, Matt.

Matthew Portillo – Tudor, Pickering, Holt & Co.

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 – Tudor, Pickering, Holt & Co.

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 – Tudor, Pickering, Holt & Co.

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 – Tudor, Pickering, Holt & Co.

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 – Tudor, Pickering, Holt & Co.

Thank you very much.

Operator

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

Brian Velie – Capital One Securities, Inc.

Good morning, guys.

Tony Best

Good morning, Brian.

Brian Velie – Capital One Securities, Inc.

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 – Capital One Securities, Inc.

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 – Capital One Securities, Inc.

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 – Capital One Securities, Inc.

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 – Capital One Securities, Inc.

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 – Johnson Rice & Co. LLC

Hey guys, thanks for taking the question.

Tony Best

You bet.

Welles W. Fitzpatrick – Johnson Rice & Co. LLC

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 – Johnson Rice & Co. LLC

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 – Johnson Rice & Co. LLC

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 – Johnson Rice & Co. LLC

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 – Cowen Securities LLC

Hey, good morning guys.

Tony Best

Good morning, Nick.

Javan Ottoson

Good morning, Nick.

Nicholas P. Pope – Cowen Securities LLC

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 – Cowen Securities LLC

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 – Cowen Securities LLC

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 – Cowen Securities LLC

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 – Global Hunter Securities, LLC

Hi, guys good morning.

Tony Best

Good morning, Mike.

Mike D. Kelly – Global Hunter Securities, LLC

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 – Global Hunter Securities, LLC

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 – Global Hunter Securities, LLC

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 – Global Hunter Securities, LLC

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 – Global Hunter Securities, LLC

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 – Global Hunter Securities, LLC

Okay, thank you guys.

Javan Ottoson

Thanks.

Operator

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

Joseph Magner – Macquarie Capital, Inc.

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 – Macquarie Capital, Inc.

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 – Macquarie Capital, Inc.

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 – Macquarie Capital, Inc.

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 – Macquarie Capital, Inc.

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 – Macquarie Capital, Inc.

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 – RBC Capital Markets

Yes, thanks. Good morning, guys.

Tony Best

Good morning, Scott.

Scott Hanold – RBC Capital Markets

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 – RBC Capital Markets

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

Javan Ottoson

Not at this point.

Scott Hanold – RBC Capital Markets

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 – RBC Capital Markets

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 – RBC Capital Markets

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 – RBC Capital Markets

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 – RBC Capital Markets

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 – Citigroup Global Markets Inc.

Good morning.

Tony Best

Good morning, John.

John C. Nelson – Citigroup Global Markets Inc.

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 – Citigroup Global Markets Inc.

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 – Citigroup Global Markets Inc.

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 – Citigroup Global Markets Inc.

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 – Citigroup Global Markets Inc.

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 – Citigroup Global Markets Inc.

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 – Barrington Research Associates, Inc.

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 – Barrington Research Associates, Inc.

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 – Barrington Research Associates, Inc.

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.

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