James Masters - Investor Relations Manager Marvin Chronister - Chief Executive Officer Bill Cassidy - Chief Financial Officer Tony Buchanon - Chief Operating Officer Lynn Boone - Senior Vice President, Reservoir Engineering.

Ryan Oatman – SunTrust Welles Fitzpatrick - Johnson Rice Scott Hanold - RBC Capital Markets Gabriele Sorbara - Topeka Capital Markets Ipsit Mohanty - GMP Securities Brian Corales - Howard Weil David Deckelbaum – KeyBanc Joe Magner with Macquarie Michael Hall - Heikkinen Energy Mike Kelly - Global Hunter Andrew Coleman - Raymond James.

Good day, ladies and gentlemen, and welcome to the Second Quarter 2014 Bonanza Creek Energy Earnings Conference Call. My name is Jackie and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session.

(Operator Instructions) I would now like to turn the conference over to your host for today, Mr. James Masters, Investor Relations Manager. Please proceed..

Thanks, Jackie. Good morning and welcome to Bonanza Creek’s second quarter 2014 earnings conference call and webcast. Yesterday afternoon, we issued our earnings press release and this morning filed our 10-Q with the SEC. You can access both on our website. Today’s prepared remarks will be a bit shorter than usual.

We know you all get bored with the recitation of numbers that we’ve already exposed in the numbers. So we will limit prepared remarks and leave as much time as we can for Q&A. Also our good friends at PDC Energy start their call in an hour and we want to be respectful of their time.

To start, Marvin Chronister will spend a few minutes discussing the corporate strategy post acquisition. Bill Cassidy will provide some color around our financial results and our outlook for the rest of the year and Tony Buchanon will finish with an operational update.

I invite you to access our August investor presentation, which is available on our website. We may make certain references to certain slides during the call. Today’s remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially.

You should read our full disclosures as described in our 10-K and other SEC filings. Also during this call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance.

Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release. With that, I will turn the call over to Marvin..

Thank you James. Good morning everyone. Thank you for taking the time to join us as we discuss our second quarter results. Overall we had a very solid quarter with production right on track to plan.

In our conference call last quarter we suggested that given our relatively linear completion schedule from second quarter through of the end of the year, we expected to add approximately 3000 BOE per day each quarter to arrive at the midpoint of guidance and so far so good.

Our drilling and production folks are some of the best in the industry and I could not be more proud of the job they are doing. As you all know we closed recently on our Wattenberg acquisition adding approximately 34,000 net acres to our position in what was truly a transformative move by the company to support our future growth ambitions.

The results of our preliminary analysis were that we added approximately 700 net locations bringing our total development inventory to 2000 net locations. Importantly we also see a significant opportunity to add to the acreage by increasing working interest and taking on additional leases.

We have a top notch land department that is absolutely eager to add incremental value to this acquisition. Moving on to the CEO selection process, it is still ongoing. Our board has considered a substantial number of very highly qualified individuals and is currently working to short list.

I can assure you they are absolutely determined to get it right. In the meantime the Bonanza Creek team has gone out and executed successfully on our strategic priorities. As we have said about acquisitions, when you see the press release you will say that makes sense and hopefully when you see the CEO announcements you will also feel the same way.

You can expect the person will fit well with the Bonanza Creek culture, bring solid industry experience and be aligned with the corporate strategy that we think has worked pretty well so far.

Finally we received some unexpected news this week that the proposed Ballot initiatives designed to restrict oil and gas development Colorado are being pulled [ph].

While we believe that the potential impact of the proposed measures to Bonanza Creek was immaterial, the harm to the industry at large and the Colorado economy overall would have been significant.

We’re relieved to see the two sides compromise so that we can all stop talking about politics and instead talk about what really drives growth for the state and value for our shareholders.

Because despite some of this year's noise whether it be the transition of the executive team or Ballot initiatives we have remained singularly focused on execution of our business plan. Through the first six months of 2014, we are right on plan operationally and see no impediments to achieving the goals we set for the year.

What’s more -- the catalyst testing program continues to produce tremendous results leading to increased value and expanded opportunities.

Tony and his team have done a fantastic job, and then financially and strategically with the successful high-yield bond offering and the Wattenberg acquisition [indiscernible] in the books, we're facing the future with very high level of confidence. Bill and his team deserve a lot of credit for what they've been able to accomplish.

With that, James has told me to keep it short, so I will turn the call over to Bill..

Thanks, Marvin and good morning everyone. The story of this quarter is pretty simple. We were successful on the things that we could control but there were few things that we couldn't control that impacted headline earnings and cash flow.

The bottom line is we were right on plan for production, number of wells drilled and completed and operating expense, and we're feeling very confident in our annual guidance as we enter into the second half of the year. Per unit LOE costs took a big step down from the First quarter as a result of warmer temperatures and a 16% increase in production.

We expect that it will continue to decline the rest of the year and it will end comfortably within the annual guidance range. Per unit G&A also declined and we expect also to be within our original cash G&A guidance when excluding costs related to executive departures.

Unfortunately severance tax and ad valorem taxes took another big step up this quarter as a result of doing business in Colorado. Colorado has high taxes on oil and gas production and we are no longer receiving the benefit of credits for low rate vertical production and today over 95% of our production is from horizontal wells.

During the second quarter, we received a draft over 2013 Colorado severance tax return from our tax consultants which presented a higher tax rate than anticipated due to a significant increase in new production from horizontal wells during 2013 in the Wattenberg field.

This resulted in a higher than expected leg in the amount of ad valorem tax credit eligible for deduction against severance taxes during the current year. Ad valorem taxes are not eligible for deduction in the year while it’s completed.

Going forward we expect corporate severance and ad valorem taxes to be approximately 10% of hedge – pre-hedged revenue.

The other piece of bad news came a couple of weeks ago in the form of a FERC ruling, which indirectly struck down our agreement with the midstream partner to take firm transportation space on the White Cliffs pipeline because the official open season for the pipeline ended in 2012.

This ruling was without precedent and stipulates that a new open season be conducted on the uncommitted volumes associated with the pipeline’s expansion. We would continue to pursue opportunities to secure capacity on existing and future pipelines to transport our product to market.

In the meantime crude oil differentials in the DJ basin have leveled out in the $11 to $14 range off of WTI. And we have high confidence that midstream providers will keep pace with production increases in the basin.

We've taken advantage of strong crude oil pricing to add hedges in the form of swaps, collars and three-way dollars in 2014, ’15 and ’16. We've hedged approximately 12,250 barrels per day for the second half of 2014 with an average floor price of $19 per barrel.

Nearly 10,000 barrels per day in 2015 at $88 per barrel and over 5000 barrels per day in 2015 at $85 per barrel. Finally as it relates to our balance sheet and overall financial position, I'm very pleased with the execution of our recent high-yield bond offering. We raised $300 million at 8.5 year note at 5.75%, our best result yet.

We’re lowering our revolving credit facility and we put cash on the balance sheet to prepare for our 2015 capital program. Our net debt to trailing 12 month EBITDAX is still below 2 times and we’re very confident heading into next year that we have the financial strength to execute on what will be our biggest effort yet.

So again from a fundamental perspective it was a great quarter. We're happy with where things are financially and operationally and are really excited about the progress being made on capital projects that have big implications on our ultimate value. I will turn the call over to Tony to share the details of our operations success in Q2..

Thanks Bill and good morning everyone. I will start by saying that in my 30 plus years in the industry I never imagined the IP technology and our collective understanding change so quickly, and it was just three months ago that our conference call was all about the super section.

We’ve learned a lot since then and have moved forward with pretty dramatic improvements to completion design that support our down-spacing assumptions. Today we are more confident than ever that 40 acre spacing in both the Niobrara B and C benches is the standard.

We believe and have strong early data to support that completing a 4000 foot lateral with 28 stages instead of 18 more effectively fractures the reservoir rock near the wellbore while also shortening the reach of the frac. Thus more efficiently accommodating down spacing to 40 acres and increasing the recovery of resource in place.

We are very encouraged by the performance of our four-well Niobrara B bench pads spaced at 40 acres, where the inner two wells were completed using 28 stages.

This pad had a strong average IP 30 of 477 BOE per day but even more exciting is that its average IP 60 rate declined just 3% to 463 BOE per day which is 50% greater than the average IP 60 of previous 40 acre space wells. And all of the wells are currently tracking above our 330 MBOE target type curve.

The $250,000 increase in cost has resulted in a $500,000 increase in revenue over the first two months. This pad supports our first 28 stage well which performs similar to an 18 stage well on the IP 30 but demonstrated a significantly shallower decline profile.

We plan to spud a five well pad this month testing 40 acre space wells in the B-bench staggered with 40 acre space wells in the C-bench, all completed with 28 stages. We've heard a lot recently about the successful application in the DJ basin of plug and perf completion technology.

We have historically used sliding sleeves to complete our wells and have been pleased with the results both from a productivity and cost perspective. However we have never been shy about being fast followers. So we are looking at applying plug and perf completions to wells later this year.

What is encouraging is that whether you are using sliding sleeves or plug and perf the concept of more efficiently fracturing the reservoir closer to the well bore and limiting the radial extension of the frac is a significant evolution in development of the Wattenberg field -- an evolution that may lead to an increase in recoveries and an improvement to already exceptional economics.

One of the other exciting projects that we've been working on is extending the prospectivity of our Codell acreage. As you know the Codell pins [ph] on our property as we move from west to east but we now believe that our old cut off of 8 feet of net pay could be conservative.

During the second quarter we completed a 4000 foot Codell well in just 6 feet of net pay and achieved an IP 30 rate of 426 BOE per day. I think we sometimes forget to recognize what a tremendous technical accomplishment it is to drill 6000 foot vertically and 4000 foot horizontally and stay within a formation that’s only 6 foot thick.

But we can, and the Codell Carlile complex is so prolific that it supports further development down to 6 feet and possibly beyond. We will drill another Codell well targeting 60 of net pay in the fourth quarter. Finally we are becoming increasingly comfortable with extended reach laterals.

During the first quarter we successfully drilled and completed two 9000 foot laterals in the Niobrara B and C benches and a 7500 foot lateral in the Codell. One interesting feature of these long laterals is the production profile, whether they have a higher or lower IP 30 they seem to converge at some point in the ensuing months.

Our extended reach lateral in the C bench for example had the lowest IP 30 of this batch of wells at 600 BOE per day but achieved an IP 60 of 592 BOE per day, a decline of just 1%.

So all of our longer lateral wells this year have produced strong results and we look forward to reporting on more over the course of the year and increasing the number of extended laterals in our 2015 program.

As you know we’ve been cautious about jumping into extended reach lateral drilling but we are quickly gaining confidence and an aptitude for it and have seen that the economic upside over 4000 foot laterals is extremely compelling.

This is especially important considering that a great majority of our acreage is contiguous in nature and lends itself to extended reach drilling. I will stop there and turn the call back over to the operator now for Q&A..

(Operator Instructions) And your first question comes from the line of Ryan Oatman with SunTrust..

What is the timetable for the wells testing 40 acre spacing in both the Niobarra B and C with the new 28 stage frac design?.

Yeah we are planning to drill those this month as matter of fact, we are moving the rig in probably about next week to go ahead and do that.

Again just to clarify it will be three 40 acre space B wells staggered on top of two 40 acre space C wells, which will be very comparable to, if you remember from our super section pad number 2, which we call our 40:20 pad. And we will frac all five of those wells with the 28 stage 4 million pound fracs..

And the fracs probably September-ish maybe first results kind of October-November timetable, is that fair?.

Yes, that’s a fair timetable, you bet..

And then on this FERC ruling, certainly a surprise – can you just describe specifically I guess what it was and what steps you are taking to resolve this issue and then what should we expect for company wide differentials moving forward? I know you kind of spoke to what we've got in Colorado but certainly you got that the production over in Arkansas, what’s a good number for us to think about kind of back half of the year and then moving forward into 2015 as you guys take steps to resolve the transport?.

Sure, on the ruling it was really unprecedented, we hadn't seen that happen before. We are clearly going out and continue to look for an option to move our crude. We don't see it as being a problem to move our crude.

We are seeing over the next 6 to 9 months with the White Cliffs expansion 75,000 barrels a day, the Pony Express Pipeline in Q4 which is 230,000 barrels a day and then the DJ lateral on Pony Express in Q1 2015 90,000 barrels a day, there will be a lot of capacity coming into the basin which we think will provide a lot of relief in the basin.

So we’re still guiding at $11 to $14 for the quarter and but we expect -- we don't expect to have any issues again, our crude to the market..

And then one final one for me, this Codell test obviously out east pretty good considering that you guys were able to stay in that amount of pay.

Any feel for how many acres you've derisked with this test and if you were to say take the cut off lower?.

As for derisking with this test, Ryan, I am not going to say we’d derisk it yet, obviously we have our one well with an IP 30 on it. Now I will say I'm very encouraged to see a 426 IP 30 on this well.

If you remember our first Codell well that we drilled out of the box a year or so go back with the IP 30 was 370 BOE a day, so this falls well within the range.

What I have been looking at is if you look at that kind of down of the 6 foot cut off there is the potential, and when I say potential right now probably add another maybe 3 to 5000 net acres of Codell potential but again we’re going to need a couple more tests to kind of validate that of course to move forward and that’s why we are drilling that second well here in the fourth quarter to test that.

Hey Ryan, I just wanted to clarify one other thing too, on the 3 to 5000 I am talking about, that is only including our legacy acreage position.

We’re evaluating on the -- the new acreage that we just picked up from DJ resources, of course we will be evaluating that potential and coming out with kind of that analysis here probably in the next three or four weeks to see how that looks on the Codell from that standpoint..

And your next question comes from the line of Welles Fitzpatrick with Johnson Rice..

On the eastern Codell test you guys have been a little bit more open talking about the Carlyle than other folks in the basin.

Do know if you got any contribution from the Carlyle? Do you know if you dipped into the Carlyle? Is that zone looking like it's any more tempting than it has been in the past?.

Well, no, the reason we talk again about the Carlyle is that we are targeting such a thin Codell zone in the Carlyle six below the Codell and is the source rock for the Codell that we’re more apts to get into when we were drilling at Codell well.

So that’s one of the reasons we talk about it versus kind of other folks in the basin because as you go further to the west, the Codell thickens and to stay in the Codell at that point you’re probably never going to get out of it and get into the Carlyle, so we've had the opportunity just because of the thinness of the Codell.

Now the Carlyle is the oil bearing shale and sources, we do not know right now whether or not we’ve got contribution from the Carlyle into the Codell. We are doing kind of extensive technical studies right now to try to figure that out.

What’s interesting though is if you think about it from an intuitive standpoint, have drilled a six foot Codell well, that IP 30 to 426 BOE a day and kind of comparable to the wells that are further to the west with thicker Codell that -- if you actually look at this well individually, and didn't know it wasn’t a six foot, would just fit in the normal range of the Codell well performance that we've seen so far make towards the lower end but still well within the arrange.

So intuitively I am thinking that we’re probably getting some sort of contribution from the Carlyle but again we’re going to have to do more work on that to kind of finalize like that.

At the end of the day we try to stay in the zone in the Codell, so we’re not trying to target the Carlyle individually we are going to go ahead and drill these next wells and try to stay in the Codell as much as we can because again we still think that that gives us the best chance of success at this point and then we will evaluate that going forward..

And then just one more.

Can we get an update on well costs, specifically on a 28 stage and then maybe what the incremental costs for the plug and perf might be as you move that direction?.

On the 28 stager, what I can tell you is we add about $250,000 to our standard 18 stage completions, so as we talked about our standard 18 stage wells are in that 4.2 million, $4.25 million range, so when you go to the 28 stage we’re going to be approaching around 4.5 million for pumping that type of job with a 4000 foot lateral.

We’re doing some looking right now to plug and perf, depending on how you execute the plug and perf it could be a little more costly from the way we’re looking at it right now, especially if go with the hybrid gel type fracs, because the advantage that the plug and perfs give you is maybe better placement of your fracs but they take a little bit longer to do because you have to go in with the plug-in gun every time and you are somewhat limited on when you pump your fracs of over displacement because if you do have gel you do not want over displace your fracs, so we would expect that cost on our initial estimate to be he higher than that 4.5 and so we’re going to look at that but we’re just going to have to go in a little more detail on that but I am thinking it’s going to be on the more side of that $4.5 million..

And your next question comes from the line of Scott Hanold with RBC Capital Markets..

Just on that White Cliffs pipeline in the open season, do you all think you could be competitive to get some of that capacity then in the next open season or what are your thoughts on that?.

We will clearly enter the open season and obviously there will be bunch of other operators going in there, so yes we believe we will get some work -- not sure we will get the volumes that we had agreed on before our agreement was nullified by FERC. But we will get after that in the open season and then look at some other options as well..

And I would assume that if you did get some of the pricing when – it’s good that you had previously negotiated, is that a fair statement?.

We think it would be pretty much the same pricing as what we saw in our negotiated deal which was about 920 off of WTI..

And with your most recent obviously capital raise and more acreage, what is your big picture thought on accelerating activity within your assets versus consolidating more acreage around the core position?.

We continue add to – and build out our 2015 business plan, but I don't think our 2014 plan is going to change dramatically. And we will give an update on capital probably in the next month or so.

On consolidating and looking at more acreage clearly the DJ Resources acquisition was very attractive for us and we now become the natural consolidator within the acreage position adjacent to our current acreage footprint. And then clearly there is the opportunity to continue to increase working interest in the create that we have acquired already.

So we got – as Marvin said earlier in his comments, had a very good land team and they are keen to get after what we have acquired and contiguous acreage to that, so we’re pretty excited about where we stand from that position..

So it sounds like it’s appetite for potentially both. And just one final question, kind of another follow-up on the Carlyle, I mean that Codell test was pretty pretty interesting and potentially exciting.

But can you give us a sense why industry hasn’t looked at maybe drilling some more Carlyle wells at this point in time? Is there something geologically different about that shale where it hasn’t or is it just the Niobrara and the Codells so far are so good that operators have been kind of deep down there yet..

I think you’ve answered -- the question right there is obviously when we stepped into the basin it was Niobrara first right – and actually it was the Niobrara B bench first and then we went to the C bench, and now we are testing the A bench.

The Cornell was next right and so the Codell was the following test and again most of the reasons people haven’t targeted the Carlyle is because where most of the Codell drilling has been done is because the Codell has been thicker in those areas and they never ventured into the Carlyle.

And again the Carlyle is the source rock for the Codell, so you felt that if you got into the Codell you were draining Carlyle oil, now where you’re getting total recovery through the entire Carlyle shale section I don't think anybody really concern themselves with that.

Again with where our acreage is we’re testing the fringes of the Codell, so that's why it becomes more us talking about the Carlyle because we do get into the Carlyle as we try to target the thinner and thinner Codell zones and it is -- the technological challenge to continue to stay in zone at the -- with that thin of a target and so I think that's been it -- as just kind of we move to the east Codell is thinner and we’re starting to see Carlyle will probably be -- I'm sure will probably be a leader on that but right now just because of the location of our acreage so we will continue to evaluate that and go from there..

How thick is the Carlyle, is it pretty good thickness across the acreage, do you have sense of what that is?.

Yeah it is. We’re talking somewhere between 30 to 35 thick feet -- across our acreage position and again it kind of sits just at the base of the Codell, it is the source rock for the Codell, so it’s the shale..

And your next question comes from the line of Gabriele Sorbara with Topeka Capital Markets..

You sounded pretty confident in increasing recoveries on the 40 acre spacing pads with the 28 frac stages, just wondering what you're seeing there and in terms of increasing recovery there’s maybe accelerating recoveries and then I guess what do you need to see in order to revisit your EUR curve?.

Yeah, you bet. We are very encouraged with the results that we’re seeing from the 28 stage. Our initial assessment – of course the data is early is that do not believe this is acceleration.

We think that we’re actually stimulating more reservoir rock near the horizontal well and therefore by stimulating that reservoir rock we’re actually recovering reserves that we would not have captured previously, that is one big piece of that. So I don't think it’s acceleration based on what we are looking at right now.

As for revisiting our target type curves, again looking at where these wells are landing we’re very encouraged that they are tracking above our target type curve but it is a limited data set, and it is early data.

So we will be looking at that as we go through the year, when we go through our reserves process here to end of the year kind of revisit it at that time and kind of re-evaluate whether or not we need to make any movements or not on our target type curves but I do want to go back to that we are very very encouraged with that results we’re seeing so far.

There's no doubt about that and that that stimulation of the rock, cracking up the Niobrara rock near the wellbore and reducing the extension of those fracs enables us to lay these things in there 40 acre spacing and that we would not be accelerating the reserves out of the ground and that we'd actually be capturing more of the resource that’s in between the wells..

And then just thinking about -- you have a several medium and long lateral wells timed for the second half of the year, just thinking -- are you experimenting with tighter frac spacing there?.

No, not yet but we will. That’s the next step on the long laterals, we wanted to perfect the technique obviously on the 4000 foot laterals first but we are looking at now -- looking at our long laterals and going ahead and experimenting with the denser spacing or the denser tighter spacing if you will on the frac stages on a long lateral.

The intent would be as obviously we drill long laterals at this type of spacing we would be doing something comparable to the 28 stage fracs. That would probably be around the range of 56 to 60 stages if you're looking at 9000 foot lateral and we do have the technology available to do that..

And I assume that technology transfers over to Codell as well?.

Yes, now we have not tried those fracs on the Codell yet but it is an intriguing question obviously our first test in the Codell, at this thinner Codell that sits on top of the Carlyle, that IP at 426 was completed with our conventional 18 stage 4 million pound frac and again we did that so the we can compare and contrast results to the other Codell wells that were completed similarly.

One of the things that the teams are looking at now is -- is there some alteration we need to make at those fracs to possibly as we get into this thinner Codell to make those even more economically attractive..

And then just final one from me just kind of housekeeping question. DD&A was a lot higher during the quarter.

Any sort of guidance you can give in terms of a run rate maybe?.

Well I guess we’re kind of victim of our own success, our production volumes grew 69% when compared to quarter two 2013 and then our PDP reserve growth was about 50% growth quarter over quarter.

So already we went I guess up 8% versus Q2 2013, I think we are probably – I guess it’s a tough one to comment on whether we’re going to -- whether it's going to continue to increase, it all depends on as we continue to add the horizontal flush production and we will have a better sense maybe later in the year on the reserve growth and how that ends up affecting the overall rate.

So it’s hard to predict what the rate – to where it’s going to be but needless to say I think our production is definitely better – Lynn, do you want to make anymore comments on that?.

Yes, obviously the really strong production rate is going to come before an increase in reserves because we have to have a significant amount of history in order to increase our reserve bookings. So I think part of what you're seeing is the leg that takes place between the very strong production performance and ability to book reserves off of it..

And your next question comes from the line of Ipsit Mohanty with GMP Securities..

A quick question on the newly acquired acreage on DJ, when are you going to see some reservoirs [ph] production from that area, and then the new exit exactly mirrors the kind of plan you have for your legacy in terms of down spacing – extended lateral test – so where I am going with this is you have a big of contiguous acreage with your fixed – are they sort of transferring best practices from your legacy acreage?.

Let me just kind of back up and kind of talk about the plans that we have for the new acreage acquisition, how it fits into our legacy acreage position.

So our plans are for this year in the fourth quarter to move in and start drilling on the new acreage in the fourth quarter, so we’re very very excited about the acreage, we like what we are seeing of course, so we will have a rig – we’re probably going to drill somewhere around 5 to 6 wells in the fourth quarter, part of that is to get ahead of about some lease expiries that that we needed to take care of.

We are not in a bind on those expiries but we are encouraged with what we are seeing and we want to go ahead and get started, so that’s going to be part of it.

Our technical teams are assessing the acreage, we have the 700 net locations that we've identified, -- and that’s first pass was the 80 acre spacing on the B, the 80 acre spacing on C and 160 acre spacing on the Codell.

Our technical teams right now are doing it kind of an update 3P analysis if you will to take the key learnings, the understandings that we have from our legacy acreage and applying that now to the new acreage that we have with the more geological look.

Again I would suspect that some of that acreage obviously the 23,000 kind of we talked about we have about 23,000, we call high-value acreage, is probably going to look a lot more like our legacy acreage and I would suspect that down spacing is going to be probably more applicable there as you go to the North and into East.

We’re just going to have to continue to look at that, we have fewer data points to the north and the east and it's a little more speculative if you will but the good news is that’s where the lower working interest part of that acreage exists.

So our plans are for next year to move in with a couple of rigs on that new acreage position and start drilling at that, coupled with our legacy acreage position that should put us about six rigs starting around beginning in January, so we are planning to run six rigs next year and obviously the drilling, when you look at that I suspect our 15 inventories are going to have more extended reach laterals in it.

So I don't really want to give you a well count because I will give you a well count right now beyond, based on our 4000 foot lateral look.

But we’re going to probably be leveraging more long reach laterals into that, in the acreage both our legacy acreage and the new acreage being as contiguous as it is really lands to the application of extended reach lateral drilling and of course our biggest thing this year was – we know extended reach laterals delivered a superior performance to 4000 foot lateral from a rate of return standpoint.

The big thing was can you execute those guys and we have really felt -- we feel that we have moved down the road on the execution piece of extended reach laterals that they are going to be a much bigger part of that.

So you will see us applying that on the new acreage too and then coupling that with a spacing learnings that we have going on right now with the 28 stage fracs and all that, I think you will see us applying that in the new acreage as we go forward also.

So Ipsit, I am not sure if that answered your question but that’s kind of a scope of what we’re looking at.

Second one is – Tony, if you can give some color on more on the geological side – the same declining frac on the 60 day rate from 48, is there anything distinct that you saw and then also some of the data – that are not so impressive, I mean I understand it’s not so impressive 600 out of the 9000 lateral in the Niobrara C, what did you see in both?.

If I understand the tail end of your question was a comparison of the 9000 C bench lateral is that correct, compared to – yes, I will tell you what. We look at that 9000 foot C bench lateral we feel very confident that spitting right within our normal long reach lateral performance.

When you look at this 9000 foot laterals they are out – when you think about the lateral length being almost 2 miles and basically we complete these things with 36 to 40 stages, if you look at that lateral with 40 stages that's like having 40 individual wells if you will in that long reach lateral and how those wells flow back that – we’re pretty good at what we do but understanding perfectly how each one of those stages on load that’s almost like having 40 individual vertical wells and load at the same time.

If 40 of those things unload at the same time you’re probably going to have a little bit higher IP rate, if they kind gradually and stagger if you will, you’re going to have a lower IP rate at much flatter decline rate which is what we’re seeing on that C bench wells.

So right now six long reach lateral data points to look at, so it’s kind of tough for us to make some really dramatic conclusions but when you lump them altogether we like what we are seeing and that’s kind of the explanation that we’re looking at right now is that there are flow dynamics that these things unload in different ways depending on -- you frac these wells, you put fluids wells, how they clean up every one of them is going to act a little bit differently but when we pull them altogether and we think they’re all performing well within our range of expectations long reach laterals and we think obviously that they deliver – When you talk about performance we are looking at 15 to 20% improvement in rates of return over 4000 foot laterals and I think that might be a little bit conservative, so I don't really see much difference on that, so I think that hopefully try to explain why you might see some difference in IP rates and things going that line..

And then I heard comment about trying to test plug and perf, and you also mentioned about delay in completions, is that going to alter your plan as regards to at least 2014, your completion schedule – will that have any impact on that?.

No, there should be no change to our completion schedule, from a timing standpoint the only thing that would change would be the type of he completion that we would deploy but I don’t see any significant changes..

And then one last, which is I see a little bit of relative under performance right now, and just to be sure the White Cliffs pipeline open season that affects all operators around equally?.

Yeah, any operator can elect to participate in the open season, so anyone that had committed volumes per similar to ourselves and gotten all the fight with FERC ruling, so it’s open season to everyone going forward. That’s just the expansion..

And your next question comes from the line of Brian Corales with Howard Weil..

Two quick questions – one, are all the wells going forward -- using the 28 stage frac?.

Brian, no, not yet but we’re moving a lot more toward those. Obviously any wells that are tighter space will have 28 stage fracs, we still probably have – if we have some one offs that are out there we will consider that but we’re looking at moving towards more and more 28 stage fracs and obviously we like what we’re seeing there..

I think you mentioned this last quarter I just can't remember -- what is the additional costs for the 28 stage frac versus the standard 18?.

It’s about $250,000..

And then finally the extended lateral – I mean you’re all pretty excited about it – what is the big impediment I guess of doing much more your program with extended laterals – I mean is it just cost, is it risk, is it – what’s thought there?.

Yeah Brian if you’d asked me that question at the end of 2013, it was risk of execution.

We knew that the economics of the extended reach laterals were superior but it was executing those basically over and over again like we do our 4000 foot laterals, having a failure on a 9000 foot lateral you have a $7.5 million investment -- if you have a failure all those benefits you get on rates of return and all that go away quickly if you can’t execute the wells.

And so our job this year was -- can we now improve our execution of drilling long reach laterals to where we can get them to be bread-and-butter type wells like our 4000 foot laterals and we’re moving that direction very quickly, our first three wells out-of-the-box this year we drilled those and completed those with minimal issues at all, that was very pleasing to me from an execution standpoint.

We’re going to drill 11 or so this year now and I would absolutely expect our 2015 program to have much more of greater portion if you will of long reach laterals as we look at that next year.

I'm sorry – yeah the only other thing that drives a little bit Brian -- we are still -- your acreage position still drives a little bit of that, obviously you'd love to go with long reach laterals but obviously it can only fit a 4000 foot lateral in and drill that with a hundred percent or something along that line.

You'll still have some 4000 foot laterals obviously the mix even if you do go forward with the extended reach lateral, there’s just going to be some – putting the puzzle together if you will..

Are any of these extended laterals for the remainder of the year going to use that -- I think you said 56 or 60 stage frac technique –.

Brian, not currently planned but the teams are looking at that if we need to make an alteration on that. But right now they are in the plan as going with the conventional but again as these results are coming in it’s changing -- it's so dynamic the situation that we live in right now, we’re looking at that right now..

And your next question comes from line of David Deckelbaum with KeyBanc..

Wanted to just follow up a little bit more on the extended reach laterals -- you talked about making these wells as bread-and-butter and where is the is thought process now between - differences in operational risk between 9,000 footers and 7500 footers?.

Well, again we drilled one 7500 footer and will obviously be successfully completed it, 9000 footers we successfully completed this year, I think inherently the 7500 footers are going to have inherently less risk than 9000 footer, it’s a little shorter to deal with, a little easier to run your liners, it’s a few less stages that you have to frac, so there is an improved risk profile when you go to 7500 footers.

What we are trying to figure out though is right now if you asked me on the three wells this year I did two 9000 footers and one 7500 quarter without any issues at all, so there was zero difference on risk, they’re both executable.

We are going to probably continue to pursue -- I think we'd like to go with the longer laterals if possible but the 7500 footers are going to have their place in this too, again because as you look at acreage there's going to be a puzzle you need to put together. In some places 7500 footers are going to work better.

Now the other thing to look at is as we look at long reach laterals as we get to tighter and tighter spacing the 7500 footers may be a little bit more applicable because again as you drill these long laterals when you start and go out 9000 feet the toll of the well can start to waver if you will as you drill it.

We’re pretty good at what we do but it can waver and when you get down to tighter and tighter spacing you don't want the tolls of the wells to get too close to each other if you can. So that’s something we’re going to have to look at and maybe to 7500 footers are that perfect mix to where you can do that when you get to tighter spacing.

But again we may be able to execute the 9000 footers and continue to do that and kind of plough ahead with those in the tighter spacing. So that’s where we are in the risk on that. I hope that answered your question..

I am also trying to get a sense of perhaps -- can you give us any color on the drilling times for this recent bath of extended laterals and are you seeing a significant difference between at least drilling efficiency for the 7500 footers versus the 9000 footers, just considering the depths of the Niobrara?.

If we had one 7500 foot well and I don't – sure if we had our best rig on it but I think we might have -- things just went great but the 7500 foot well didn’t take much longer than 4000 foot well.

And now that was one data point on one well .At the end of the day the long reach laterals they take us about three to four days longer to drill when you go the 9000 footers, and we’re still looking at those costs being in that 7.5 million range when we doing that with our conventional 36 to 40 stage fracs at 9000 feet.

The 7500 footers are kind of in that $6.3 million range, so that’s where we are right now, David. I’d like to get a few more data points on that but like I said we plough ahead on that 7500 foot well, really well got in zone and – it’s also a Codell well, so it’s been obviously a really good performer for us..

Just one more I might on, on acquire DJ acreage on the southern portion how is the progress going, I guess with negotiations with mineral owners down there and – do you expect that to be an ongoing process or should we hear some are resolution by the end of the year of the potential increase I guess of your working interest in some of the areas there with some swaps?.

Yeah, I am going to say – well one -- that work is ongoing as Marvin had mentioned, part of where our land team is focused is specifically on that acreage to kind of on checkerboard if you will, so we are looking at that right now but that is a gradual process. So I don't want to promise anything by the end of the year.

I would suspect that our 2015 program on our newly acquired acreages is going to be focused on the North side, we will probably have a little bit drilling on that south side but I would expected that it’s going to be well into 2015 before we can probably come to you on that with some sort of resolution on what that’s going to look like..

And your next question comes from the line of Joe Magner with Macquarie..

On I guess changes to some of the frac designs, one of the reasons why the cost isn’t going up so much on the 28 versus 18, as you are using the same amount of proppant I believe between those two designs, is there any thought about maybe increase in the proppant loading on the 28 stage to test whether that will be more effective?.

Joe, just to confirm, yeah, the reason the cost did not go up is again we are using the same amount of proppant, same amount of fluid just distributing it over 28 stages instead of 18, so really the cost is more driven by the actual liner and the time to pump the fracs.

Our teams are as for or improving the frac techniques and increasing proppant size. Our teams are looking at that right now. Everything is in the hop right now, plug and perf even maybe possibly some tighter spacing on stages and increasing proppant size, is what is the optimal proppant size that’s something we’re still looking at.

So we will be looking at those kind of tests as we can go here in the second half of the year..

On the severance tax situation I appreciate the vertical component has now dropped and those credits are gone, there was a comment in the release I think about the ability to perhaps apply for credits on horizontal or unconventional wells the year after wells completed – I just want to see – clear on that and is there any opportunity to see perhaps some relief in the future as the timing of those completions and applications level out?.

The ad valorem taxes are not eligible for deduction in year the wells completed so there is a lag in here.

Again as we move further to more and more horizontal wells -- all horizontals wells and higher returning horizontal wells and taken off the vertical wells, we will continue to see higher production and in the guidance -- our guidance will move to 10% I guess in the first quarter, we ended up with 8.4% and then we’re guiding for 10% going forward, just because of the lag in the ad valorem tax and its deductibility..

Could there be an opportunity as time goes on to reapply for credits on the new wells or is that just not something that applies to the horizontals?.

It’s not really something that you reapply for..

Just to chime in, quickly the ad valorem taxes for a year are paid two years in arrears, so from a cash perspective you're always going to have a lag between the year wells completed and when my ad valorem taxes with the completed – during the year completion are actually paid..

And then just on the White Cliffs opportunities, is there a timeframe for when that might take place?.

We’re expecting given the expansion is into the first quarter or Q3 2014, so August September we’re expecting that to hopefully start pretty soon as – I am sure they want to fill up that pipeline, as soon as possible – for that to happen. So as soon as we hear I am sure you will get out to the market pretty easily..

And your next question comes from the line of Michael Hall with Heikkinen Energy..

First on, just following up a little on the extended reach laterals, can you talk about a little bit how you’re managing production in the early flow back on those wells relative to how you manage it on the 4000 foot wells and is there any potential to close the gap between those two if you are choking back the longer wells – more than a shorter?.

On our flowbacks basically we do flow them back a little bit differently but it's kind of proportional if you will, we realize that we’re trying to load a 7500 foot or, 9000 foot lateral so directionally, when you look at that we are -- on a 4000 foot lateral we’re going to be flowing back in that 700 to 800 barrel a day range if you will, the extended reach laterals will be at a little higher rate on that somewhere in the 12 to 1500 barrel a day type range on pulling those back, this is in a proportion with the lateral length that we’re trying to unload, so really we’re not different, it just looks like it's more rate coming back just based on the lateral length.

As for changing that up to be honest with you, we’re really satisfied with type curves, the one thing that I've always mentioned to folks is where you can do the most damage to a well initially is in its initial flowback and by pulling the well to hard, by collapsing fracs by pulling proppant in, you can damage the stimulated rock that you just spent all that money to go frac and it’s unrecoverable.

If you flow the wells back not hard, or too soft if you will, there is no reservoir damage, it may delay the production coming out of the ground but there's no reservoir damage, so you’re not doing anything irreparable.

We’re always going to error to the cautious side of not pulling the wells too hard, and go from there until the flatter declines that we’re seeing on the long reach laterals are -- it's very satisfying from an operational standpoint when you bring wells on and you see this slight decline rate and you can kind of count being there for a while, so that’s very satisfying too from a production prediction standpoint..

And is there kind of a point at which time – as you have seen so far comparing the legacy extended reach lateral – to the base design – is there a point at which the curve [indiscernible] to other shapes more closely and when that might be?.

Yeah I am following you – I see what you are saying. I can't say I can’t answer that right now, again we’ve got – I’ve got six extended he reach lateral data points right now.

I've got one of those in the Codell, one in the C bench, and four in the B bench, and it’s hard with small data set to have kind of an indication of how they are going to kind of tail off or how they will track on 4000 foot laterals, we will have some more data.

What I can say is that when we look at the other extended reach lateral data that we’re seeing like from Noble [ph] where they actually have more data points we sure feel like our wells are acting a lot like theirs.

So our really data points are kind of tracking in that and again I know they have short time data too but they sure o have a lot more data points that we do.

So we kind of leverage that a little bit, so I don't think I directly answer your question right now other than saying like the flatter decline rates, they fit into what Noble has put out there too from their extended reach lateral data and again the reason I reference that is they have a whole lot more data points to look at..

I know you have kept the proppant for the entire well -- flatter unchanged on the 28 versus 18, like you said, how much total sand are you putting in a well, what’s your base design?.

Yeah, our base design is about a thousand put -- thousand pounds of pound per lateral foot of horizontal, so on your 4000 foot lateral you will be looking at 4 million pounds of sand. Obviously if you go to 7500 feet it makes the math pretty –.

On the work that you are doing on the new assets in terms of kind of redressing inventory post deal, when might you communicate that with the street?.

Yeah, you bet, our technical teams are looking at that right now. We expect to probably look at that here in the next 3 to 4 weeks, I would expect that we will have another assessment of what we feel that the acreage looks like.

What I can say is that we’re very very encouraged with what we are seeing and I think obviously that initial assessment of 700 net wells we like that assessment, maybe on the conservative side as we look at this but give us a little bit more time as we continue to have our technical teams – there is a lot of things that they are now digesting with the data that we now have are actual hands-on and of course with a lot of the additional information that we gathered from our legacy acreage – with the test of the six foot Codell with the 28 stage fracs, down spacing and all that to apply that across other acreage, so it’s taken us little bit of time to do that.

but give us three or four weeks or so and I think we will be coming out with something..

I guess the last one – just timing on the A bench testing – remind me on where that’s happen –.

You bet, that’s a great question because we're actually drilling that well right now, we're getting ready to land the curve. So that's where we are on that..

And your next question comes from the line of Mike Kelly with Global Hunter..

A lot of my questions have been asked. Just two quick ones here.

One, the rates you gave at 30 day rates and the 60 day rates obviously encouraging, was wondering if you had an average 30 day rate for all wells you put online, have that much history during the second quarter?.

Mike, are you asking for an average 30 day rate for I guess ---.

Yeah, obviously we get to look at it on an apples to apples basis, maybe we can look at all the 4000 foot Niobrara wells – I was just trying to assess if you could just say – you don’t have it in front of me but everything is at the type curve or better, is that really the takeaway I think that we should be having here I guess is my question..

Mike, I don’t have all that data in front of me, so let us get back to you, what I can tell you is – if you look and I am guessing that you are referring obviously the 28 stage fracs, the IPs that we put there, and how they compare to the other wells that we drilled during the quarter.

is that correct?.

Really almost a blend, you could break it out on 28 versus the 18 but just trying to get – we’ve some great wells out there that you get selected -- as a whole the 18 or 28, how they fare in versus type curve?.

You bet, Mike, here is how I will answer that, one when you look at our wells that we drilled in the quarter I've gotten some data now in front of me, real quick, yeah, when you look at the been wells we drilled in the quarter they're all basically falling within our normal B bench range, so I think you can look at the average of those wells targeting right around what our type curve average is.

So if you want to compare and contrast what the 28 stage fracs have done they are performing right now what we think are above that type curve.

So again it’s short time data but I would say that the 28 stage pattern is performing above average when you look at what all the other wells have done in the quarter because all the other wells are kind of trending right into that normal range that you would expect for a normal drilling program that we have around our type curve..

You mentioned a couple times in the call that three to four weeks timeframe we could expect an update from you, can you give a little bit more clarity on that what should we expect to come with the release?.

Yeah on the capital piece, right now we’re still guiding to the 575 to 625 range on the capital. We are looking at that, obviously we have some additional testing we’re going to do with 28 stage fracs, we think right now with the way the programs laying out that we can fit that within that guidance range.

But of course as things – it’s a dynamic situation that we live into and so we will continue to look at that and get back to you here, it will be shortly if we do decide to make any changes..

Is there inventory update that’s going to come with too -- production guidance ramifications what all is encompassed in it?.

I think I was referencing the inventory update probably little early, we’re probably three or four weeks out on that inventory update, so give us some time on that and obviously that inventory update will be tied to the new acreage on the DJ resources.

For a guidance range change I suspect that nothing is going to change on it, we made a minimal adjustment based on the obviously the acquisition that we just had with the proved production that came with.

Work that will be done any additional – if we do have additional capital spend that’s going to be done in the fourth quarter and obviously as you know fourth quarter drilling, fourth quarter work really is not going to affect 2014 production performance, so we probably wouldn't have any adjustments I would suspect based on any kind of change in capital if we were to do that..

And your next question comes from the lien of Jeff Grampp with Northland Capital Markets..

Just kind of a clarification where I think I might have missed it earlier on the long lateral well-cost I think I might've missed that there, and then just kind of building up of that, what you guys maybe think early stages, what the incremental costs may be with the added frac stages you guys are looking at?.

Sure on the long lateral our standard long lateral directionally is about – on a 9000 footer we are looking at about $7.5 million and that would be completed with about 36 to 40 stages.

A 4000 foot lateral, when we go to the 28 stage frac at about $250,000, so our long laterals is going to be probably just a little bit more than that, we’re going to be going to probably 60 stages or so, so we will probably be looking at another half a million to $650,000, so that the long reach lateral maybe with 60 stages probably puts you in that directionally around that 8.2 million, $8.3 million range is what I would guess right now.

But we will have to get finalize those costs as much as we go forward..

And most of my other questions have been asked but only other one for me on this – Codell step out that you guys had, are there any early indications or just your general thoughts on how decline rates may change given the thinness of the Codell or how you guys think about the Carlyle contributing to decline rates longer-term on that?.

Yeah, we’ve got an IP 30 right now so we’re looking at the decline rates and we will keep an eye on that, obviously that’s going to be a big thing for us. I think you can infer that if obviously the decline rates are flatter that we’re probably getting more contribution from the Carlyle.

And if they're not and then we’re probably getting so much, so we just have to kind of take a look at that but I don’t have anymore data than what I have got right now on that IP 30 but those are some of the things we will be looking at..

And your next question comes from the line of David Beard with IBERIA..

Maybe you can just comment a little bit on service costs in the basin and would you be able to put some color on the levers for 2015 CapEx or higher lower or give us some outlook there?.

Yeah I will go ahead on the service costs. We are seeing a little bit of pressure, nothing significant yet but frac costs, I think there is some labor pressures there that are causing us a little bit of increase in the frac costs but nothing of major consequence yet and so we will keep an eye on it, we are keeping our eye on it.

Drilling costs, our contracts, where we have had our rigs locked up for the year, so we haven’t seen any significant pressures there, but we are going to be looking at contracts for 2015 as we do our budget process and so we will have better read on that but we are not seeing again anything of consequence that – it’s going to be significant jump or a significant drop.

So there is other arrow bars if you will on estimating costs and all that, so I think we are absorbing most of these – if anything goes up in costs, we seem to be kind of finding other ways or other things cost a little bit less. But at the end of the day nothing of consequence but we are seeing a little bit on the frac side..

And just on the capital for ’15, we are really starting of the budgeting process at the moment, so we should have better visibility on that at latter part of the year or so it’s pretty early to talk about that, so we will come back to you on it..

And your next question comes from the line of Andrew Coleman with Raymond James. And your next question comes from the line of Richard Dearney [ph] with Longport Partners..

Slide 9 has the Greenhorn permanently drilled underneath the other horizons, and you mentioned on your last call that you were sort of watching any new progress there and then on Slide 28, does the Greenhorn extend from wells range around the whole over your acreage?.

Yes, to answer your first question on the Greenhorn, we continue to watch. So I don’t have any update on any performance of any Greenhorn work that has been done since kind of the last call.

We are keeping an eye on it and again we will be fast follower on the Greenhorn, again because we have so much other stuff to work to be perfectly honest with you. Is the Greenhorn present on our acreage, it is. It’s present pretty much.

The Greenhorn – let me talk about our legacy acreage but it is present across our legacy acreage, our technical teams right now are kind of looking at the DJ acreage that we just acquired, I suspect that Greenhorn is going to be present across most of that but honestly I don’t have that full assessment yet but we know that it’s there, and we will keep our eyes on anybody having any kind of success and I think you won’t see us doing anything on our acreage probably in ’15 going forward, it’s probably like a 16 event for us, to be testing the Greenhorn..

At this time we have no further questions. And with that ladies and gentlemen, I would thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day..