Civitas Resources Inc (CIVI) 2014 Q2 法說會逐字稿

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. And later we will conduct a question-and-answer session.

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

Thanks, Jackie. Good morning, everyone, 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 already disclosed in the press release 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 corporate strategy post acquisition. Bill Cassidy will provide some color around our financial results and our outlook for the rest of year and Tony Buchanan will finish with an operational update.

I invite you to access our August investor presentation, which is available on our website. We may make reference 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'll 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 with plan. In our conference call last quarter, we suggested that, given our relatively linear completion schedule from second quarter through the end of the year, we expected to add approximately 3,000 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're 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 and ambitions.

The results of our preliminary analysis were that we added approximately 700 net locations, bringing our total development inventory to 2,000 net locations. Importantly, we also see a significant opportunity to add to the acreage by increasing working interests and tacking 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 with a 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 announcement you'll 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 in Colorado are being pulled. 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 compromised so that we can all stop talking about politics and instead talk about what really drives the growth for the state and value to 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 in the books, we are placing the future with a very high level of competence. 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 this quarter is pretty simple. We were successful on the things we could control, but there were a 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 are feeling very confident in our annual guidance as we enter into the second half of the year.

Per unit LOE cost 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, as today over 95% of our production is from horizontal wells.

During the second quarter we received a draft of our 2013 Colorado severance tax return from our tax consultant, 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 lag in the amount of ad valorem tax credits eligible for deduction against severance taxes during the current year. Ad valorem taxes are not eligible for deduction in the year a well is completed. Going forward we expect corporate severance and ad valorem taxes to be approximately 10% of hedge -- of pre-hedge 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 a 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 will 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 DJ basin have leveled out in the $11 to $14 range off of WTI. And we have high confidence that the 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 collars in 2014, 2015 and 2016. We have 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 5,000 barrels per day in 2016 at $85 per barrel.

Finally as it relates to our balance sheet and overall financial position, I am very pleased with the execution of our recent high-yield bond offering. We raised $300 million of 8 1/2 year notes at 5.75% our best result yet, reloading our revolving credit facility and we put cash on the balance sheet to prepare for 2015 capital program.

Our net debt to trailing 12 month EBITDAX is still below two times and we are 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 are happy with where things are financially and operationally and are really excited about the progress being made on catalyst projects that have big implications on our ultimate value.

I'll turn the call over to Tony to share the details of our operation success in Q2.

Thanks, Bill, and good morning, everyone.

I'll start by saying that in my 30-plus years in the industry I never imagined I'd see technology and our collective understanding change so quickly. It was just three months ago that our conference call was all about the super section. And we have learned a lot since then and have moved forward with pretty dramatic improvement to completion designs 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 4,000-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 downspacing 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 pad 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 it's average IP-60 rate declined just 3% to 463 Boe per day which is 50% greater than the average IP-60 of the previous 40-acre spaced wells. And all of the wells are currently tracking above our 313 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 spaced wells in the B-bench staggered with 40-acre spaced 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 wellbore 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 or the other exciting projects that we have been working on is extending the prospectivity of our Codell acreage. As you know, the Codell [spins on] our properties removed 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 4,000-foot Codell well in just 6 feet of net pay and achieved an IP30 rate of 426 Boe per day. I think we sometimes forget to recognize what a tremendous technical accomplishment it is to drill 6,000 foot vertically and 4,000 foot horizontally and stay within a formation that's only 6 foot thick.

But we can. And the Codell Carlyle complex is so prolific that it supports further development down to 6 feet and possibly beyond. We will drill another Codell well targeting 6 feet 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 9,000 foot laterals in the Niobrara B and C benches and a 7,500 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 the 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're quickly gaining confidence and an aptitude for it and have seen that the economic upside over 4,000 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)

Your first question comes from the line of Ryan Oatman with SunTrust. Please proceed.

Hi, good morning

Good morning

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

Hey, Ryan we are planning to drill those of this month as a matter of fact. We are moving the rig in, probably about next week, to go ahead and do that. And again just to clarify, it will be three 40-acre spaced B wells staggered on top of two 40-acre spaced C wells. Which will be very comparable if you remember from our Super-Section Pad 2, which we called our 40/20 pad and then we will frac all five of those wells with the 28-stage of 4 million pound fracs.

Great, great. 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.

Okay very good 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 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 continuing to look for options to move our crude. We don't see it as being a problem to move our crude. We're seeing over the next six to nine months with the White Cliff 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, 19,000 barrels a day. There'll 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 getting our crude to the market.

Very good. 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'm not going to say we've derisked 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 year or so go back, with the IP-30 was 370 Boe a day. So this falls well within the range. What I've been looking at is, if you look at that kind of down to the six-foot cutoff, there's a potential -- and I'm going to say potential right now, to probably add another maybe 3,000 net acres to 5,000 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're drilling that second well here in the fourth quarter to test that.

Great. I'll hop back in the queue. Thank you

Hey, Ryan, I just want to clarify one other thing. On that 3,000 net acres to 5,000 net acres I'm talking about that is only including our legacy acreage position. We're evaluating on the new acreage that we just picked up from the DJ Resources. Of course we'll be evaluating that potential and coming out with kind of that analysis here probably in the next three of four weeks to see how that looks on the Codell from that standpoint.

Your next question comes the line of Welles Fitzpatrick with Johnson Rice. Please proceed

Good morning.

Morning, Welles.

Excuse me. 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 though the reason we talk again about the Carlyle is that we are targeting such as thin Codell zone and the Carlyle sits below the Codell. And is the source rock for the Codell that we're more apt to get into it when we're drilling a 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 probably never going to get out of it and getting into the Carlyle. So we've had the opportunity just because of the thinness of the Codell.

Now the Carlyle is an oil bearing shale in its sources. We do not know right now whether or not we got contribution from the Carlyle into the Codell. We're 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, I've just drilled a six-foot Codell well that IP-30 to 426 Boe a day. And it compares with, 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 was in a six-foot it would just fit in the normal range of the Codell well performance that we've seen so far, maybe toward the lower end, but still well within the range.

So intuitively, I'm 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 kind of finalize 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.

Perfect thanks. And then just one more. Can we get an update on well cost, specifically on a 28-stager and then maybe what the incremental cost for the plug-and-perf might be if you move that direction?

On the 28-stager what I can tell you is we add about $250,000 to our standard 18-stage completion. So as we've 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 4,000-foot lateral.

We're doing some looking right now at the 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 right now especially if you 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-and-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 to over displace your fracs. So we would expect that cost on our initial estimates to be higher than that $4.5 million and so we're going to look at that.

But we're just going to have to go into a little more detail on that, but I'm thinking it's going to be on the north side of the $4.5 million.

Okay perfect. Thanks so much.

Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Yes thanks. Hey, for my first question just on that White Cliff Pipeline in the open season, do you all think you could be competitive to get some of that capacity then in this next open season or what are your thoughts on that? And then -- (multiple speakers)

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

Okay and I would assume that if you did get some of the pricing, wouldn't be as good as you had previously negotiated? Is that a fair statement?

We think it would be probably pretty much the same pricing as what we saw in our negotiated deal, which was about -- I think was $9.20 off of WTI.

Okay understood. With your most recent obviously capital raise and more acreage, what is your big picture thoughts on accelerating activity within your assets in -- versus say consolidating more acreage around the core position?

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

And 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's the opportunity to continue to increase working interest in the acreage that we've acquired already. So we've got, as Marvin said earlier in his comments, a very good land team and they're keen to get after what we've acquired, and contiguous acreage. So that's we're pretty excited about where we stand from that position.

Okay, so it sounds like there's [an upside] for potentially both? Okay, and just one final question, just kind of another follow-up on the Carlyle. I mean obviously that Codell test was 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 Codell itself are so good that operators haven't dipped down there yet?

I think you've answered your big question right there. Obviously when we step into the Basin, with the Niobrara first, right? And actually it was the Niobrara B-bench first and then we went to the C-bench and now we're testing the A-bench. The Codell was next right so the Codell was the following test. And again most 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've never ventured into the Carlyle. And again the Carlyle is the source rock for the Codell, so you've 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 concerned 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 these thinner and thinner Codell zones. And it is it's a technological challenge to continue to stay in zone, with that thin of a target. And so I think that's been it. We've kind of moved to the East, Codell is thinner, and now we're starting to see the Carlyle. We'll probably be -- I'm sure we'll probably be a leader on that right now, just because of the location of our acreage. So we'll continue to evaluate that and go from there.

How thick is the Carlyle? Is it a pretty good thickness across the acreage do have a sense of what that is?

Yes it is. We're talking somewhere between 30 feet to 35 feet thick across our acreage position. And again a kind of sits just at the base of the Codell. It is the source rock for the Codell, so it's a shale.

Okay, great thanks.

And your next question comes straight line of Gabriele Sorbara with Topeka Capital Markets. Please proceed.

Thank you. Good morning, guys. 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 recoveries versus accelerating recoveries? And then I guess what you need to see in order to revisit your EUR curve? Thanks.

Yes you bet. We are very encouraged with the results 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 are actually recovering reserves 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're 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 a 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 at the end of the year and kind of revisit it at that time. And kind of reevaluate whether or not we need to make any movements or not on our type target curves. But I do want to go back to that we are very, very encouraged with the results we're seeing so far. There's no doubt about that.

And that stimulation of the rock, fracking up the Niobrara rock near the wellbore and reducing the extensions of those fracs, enables us to lay these things in there at 40-acre spacing. And that we would not be accelerating the reserves out of the ground in that we'd actually be capturing more of the resource that's in between the wells.

Great that's good color thank you. And then just thinking about you have several medium- and long-lateral wells planned for the second half of the year. Just thinking are you experimenting with a 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 4,000-foot laterals first. But we're 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 if 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 stages to 60 stages if you're looking at a 9,000-foot lateral. And we do have the technology available to do that.

Great 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'd at 426, was completed with our conventional 18-stage 4 million pound frac. And again we did that so that we could compare and contrast the results to the other Codell wells that were completed similarly. One of the things that the teams are looking at now, is there some alteration we need to make to those fracs to possibly -- as we get into this thinner Codell, to make those even more economically attractive.

Great and just one final one for me just kind of housekeeping question. DD&A was a lot higher during the quarter, any sort of guidance you can give as in terms of a run rate maybe?

Well I guess we're kind of the victim of our own success. Our production volumes grew at 69% when compared to quarter two 2013. And then our PDP reserve growth was about 50% growth quarter-over-quarter. So our rate, we went up 8% versus Q2 2013. I think we're probably -- I guess it's 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 slush production and we'll have a better sense maybe later in the year on the reserve growth and how that ends up affecting our overall rate. So it's hard to predict.

What the rate as to where it's going to be. But needless to say, I think our production is definitely benefiting on that. Lynn do you want to make you more 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 lag that takes place between the very strong production performance and the ability to book reserves off of it.

Understood, thank you guys.

Great thanks.

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

Hey, good morning guys. Quick question on the newly acquired acreage from DJ Resources. When are we going to see from [well drill] results production from that area? And then does the new acreage exactly mirror the kind of plan you have for your legacy in terms of downspacing tests, ex the lateral tests? So where I'm going with this is, do you have a better contiguous block of acreage that you feel confident in your sort of transferring best practices from your legacy acreage, please?

Hey, Ipsit. Yes, on -- 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 and 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're seeing, of course.

So we'll have a rig -- we're probably going to drill somewhere around five to six wells in the fourth quarter part of that is to kind of get ahead of some lease expiries that we needed to take care of. We are not in a bind on those expiries, but we are encouraged with what we're seeing that 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 in that first pass was the 80-acre spacing on the B, 80-acre spacing on the C and 160-acre spacing on the Codell. Our technical teams right now are doing kind of update 3P analysis, if you will, to kind of take the key learnings, the key understandings, that we have from our legacy acreage and applying that now to the new acres that we have with a 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 of what we call high-value acreage. Is probably going to look a lot more like our legacy acreage and I would suspect that downspacing is going to be probably more applicable there as you go to the north and to the east. We're just going to have to continue to look at that. We have fewer data points to the north and to the east and that's a -- 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 a new acreage position and start drilling at that. Coupled with our legacy acreage position that should put us about six rigs starting around beginning of January. So we're planning to run six rigs next year. And obviously the drilling when you look at that, I suspect our 2015 inventory is going to have more extended reach laterals in it. So I don't really want to give you a well count because I'd give you a well count right now and it'd be based on a 4,000 foot lateral look. But we're going to probably be leveraging more long reach laterals into that. And the acreage, both our legacy acreage and the new acreage being as contiguous as it is, really lends to the application of extended reach lateral drilling.

And of course our biggest thing this year was we know extended reach laterals deliver superior performance to 4,000 foot laterals from a rate of return standpoint. The big thing was can you execute those guys and we have kind of really felt -- we feel that we have mowed down on the role on the execution piece of extended reach laterals that they are going to be a much bigger part of that. You'll see us applying that on the new acreage too. Then coupling that with the key spacing learnings that we have going on right now with the 28-stage fracs and all that. And I think you'll see us applying that in the new acreage as we go forward also. So Ipsit I'm not sure if that answered your question, but that's kind of the scope of what we're looking at.

It did more than answer my question and I truly appreciate the color. Second one is, Tony, if you can give some color on the [I think more] on the geological side and the [2%] decline in fracs on the [figures you stated] (technical difficulty) from 40 acres. Is there anything [concerning] that you saw here? And then also, similarly [the not surpluses] I mean I understand that it is early quality that the [amount] to $600 per day from the 9,000 lateral in Niobrara C. What you are you seeing in both?

Ipsit if I understand -- the tailwind of your question was a comparison of the 9,000 foot C-bench lateral. Is that correct -- compared to our (multiple speakers) -- am I hearing that right? Yes, Ipsit, I tell you what, we look at that 9,000 foot C-bench lateral, we feel very confident that's fitting with right within our normal long reach lateral performance.

When you look at these 9,000 foot laterals, they are out -- when you think about the lateral length being almost two miles, right? Basically we've complete these things with 36 stages to 40 stages that's -- 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, there's -- we're pretty good at what we do, but understanding perfectly how each one of those stages unload that's almost like having 40 individual vertical wells unload at the same time.

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

And that's kind of the explanation that we're looking at right now is that there some downhole flow dynamics that these things unload in different ways. Depending on -- you frac these wells, you put fluids in the wells, how they clean up every one of them is going to act a little bit differently. But when you pull them altogether we think they're all performing well within our range of expectations for long reach laterals. And we think obviously that they deliver -- when you talk about performance we're looking at 15% to 20% improvement of rates of returns over our 4,000 foot laterals and I think that might be a little bit conservative. So I don't really see much difference on that. So but I think that hopefully tries to explain why you might see some difference on IP rates and things along that lines.

Got you. And then I heard it on a comment about starting to test plug-and-perf and you also mentioned about sort of leading completions. Is that going to alter your plan with regards to what you see in 2014, where your completion schedule -- does 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 completion we would deployed. But I don't see any significant changes.

Okay thank you and one last, which is I see a little bit of under performance right now, and just to be sure the White Cliffs Pipeline open season that affects all operators around equally?

Any operator can elect to participate in the open season. All the -- anyone that had committed volumes per similar to ourselves and got nullified with the FERC ruling, so it's open season to everyone going forward.

Thank you

And that's just the expansion.

Your next question comes reline of Brian Corales with Howard Weil. Please proceed.

Hey guys. Two quick questions. One, are all the wells going forward with the -- be using the 28-stage frac?

Brian, no not yet. But we're moving a lot more toward those. Obviously any wells that are tighter spaced will have the 28-stage fracs. We still probably have -- if we have some one-offs that are out there, we'll consider that. But we're looking at moving towards more and more 28-stage fracs and obviously we like what we're seeing there.

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

It's about $250,000.

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

Yes, 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 4,000 foot laterals. Having a failure on a 9,000 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. So our job this year was, can we now improve our execution of drilling long reach laterals to where we can get them to the bread-and-butter type wells like our 4,000-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, 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 a much more -- greater proportion if you will of long reach laterals as we look at that next year. (Multiple speakers) I'm sorry. The only other thing that drives a little bit, Brian, is we are still acreage position still drives a little bit of that. Obviously you'd love to go with long reach laterals, but obviously if you can only fit a 4,000 foot lateral in and drill that with 100% interest or something along that lines. You'll still have some 4,000 foot laterals obviously the mix, even if you do go forward with the extended reach laterals. There's just going to be some putting the puzzle together if you will.

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

Brian right now not currently planned, but the teams are looking at that to see if we need to make an alteration on that. But right now they're 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.

All right thanks, guys.

Thanks, Brian.

And your next question comes the line of David Deckelbaum with KeyBanc. Please proceed

Thanks for taking my questions. Wanted to just follow a little bit more on the extended reach laterals. I know you talked about the -- you talked about making these wells the bread-and-butter and where is the thought process now between the differences and operational risk between 9,000 footers and 7,500 footers?

Hey. David. Again we drilled one 7,500 footer and obviously we successfully completed it. And the two 9,000 footers we can successfully completed this year. I think inherently the 7,500 footers are going to have inherently less risk than a 9,000 footer. It's a little shorter to deal with, it's 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 the 7,500 footers. What we're trying to figure out though is right now, if you ask me on the three wells this year, I did two 9,000 footers and one 7,500 footer without any issues at all. So there was zero difference on risk, they're both executable. We're going to probably continue to pursue I think we'd like to go with the longer laterals if possible. But the 7,500 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 7,500 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 7,500 footers may be a little bit more applicable. Because again, as you drill these long laterals when you start and go out 9,000 feet the [toe] of the well can start waiver if you will as you drill it. I mean we're pretty good at what we do, but it can waiver. And when you get down to tighter and tighter spacing you don't want the toes of the well to get too close to each other if you can. So that's something we're going to have to look at and maybe the 7,500 footers are that perfect mix to where you can do that when you get the tighter spacing. But then again, we maybe able to execute the 9,000 footers and continue to do that and kind of plow ahead with those in the tighter spacing. So that's kind of where we are in the risk on that. I hope that answered your question.

It does. I guess I'm also trying to get a sense of perhaps can you give us any color on the drilling times for this recent batch of extended laterals? And are you seeing a significant difference between at least drilling efficiency for the 7,500 footers versus the 9,000 footers just considering the depths of the Niobrara?

We had one 7,500 foot well and I'm not sure if we had our best rig on it. But I think we might have and things just went great. But the 7,500 foot well didn't take much longer than a 4,000 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 to the 9,000 footers. We're still looking at that cost being in the $7.5 million range when we're doing that with our conventional 36-stage to 40-stage fracs at 9,000 feet. The 7,500 footers are kind of in that $6.3 million range. So that's kind of where we are right now David.

I'd like to get a few more data points on that. But like I said, we plowed ahead on that 7,500 foot well, really well. Got it in zone and it was also the Codell well, so it's been obviously a really good performer for us.

Great. Just one more if I might. On the acquired DJ acreage, on the southern portion, how's the progress going I guess with negotiations with mineral owners down there? And do expect that to be an ongoing process or should we hear some resolution by the end of the year of the potential to increase I guess you're working interest in some of the areas there through some swaps?

I'm 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 [un]checkerboard it if you will. So we are looking at that right now. 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 acreage is going to be focused on the north side. We'll probably have a little bit of drilling on that south side. But I would suspect it's going to be well into 2015 before we can kind of probably come to you on that with some sort of resolution on what that's going look like.

Great. Thanks everyone.

Thanks.

Your next question comes the line of Joe Magner with Macquarie. Please proceed

Good morning thanks for taking my question. On the I guess changes to some of the frac designs. I think one of the reasons why the cost hasn't gone up so much on the 28 versus the 18 is that you're using the same amount of proppant I believe between those two designs. Is there any thought about increasing the proppant loading on the 28-stage to test whether that'll be more effective?

Hey, Joe just to confirm that 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 stages. So really the cost is more driven by the actual liner and the time to pump the fracs. Our teams are as for improving the frac techniques and increasing proppant size, our teams are looking at that right now. Everything's in the hopper right now. Plug-and-perf, even maybe possibly some tighter spacing on stages and increasing proppant size. Is -- what is the optimum proppant size? That's something we're still looking at. We'll be looking at those kind of tests as we kind of go here in the second half of the year.

Okay great. And then sorry if I missed some of these details during the prepared comments, but on the severance tax situation. I appreciate that 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 the well is completed. I just wanted to see if I'm clear on that and is are any opportunity to see perhaps some relief in the future as the timing of those completions and applications level out?

This is Bill here, Joe. The ad valorem taxes are not eligible for deduction in the year the well is completed, so there's a lag in there. And I guess we're again as we've move further to more and more or all horizontal wells and higher returning horizontal wells and taking off the vertical wells, we'll continue to see higher production. And then 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 it's deductibility.

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

It's not really something that you really apply for. Wade, I don't know if you want to comment on that?

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 a well is completed and when ad valorem taxes with the completed -- during the year of completion are actually paid.

Okay, maybe I'll follow-up on that off-line. And then on the White Cliffs open season is there a time frame for when that might take place?

Well, we're expecting a given that the expansion isn't till the first quarter -- or Q3 2014. So August, September, we're expecting that hopefully start fairly soon. As I'm sure they'll want to fill up their pipeline as soon as possible. We're waiting for that to happen. So as soon as we year I'm sure it will get out to the market pretty easily.

Got it that's all I have. Thank you.

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

Thanks appreciate the time. A lot of mine have been answered, so try to keep it quick. First on the, just following-up on the extended reach laterals. Can you talk a little bit how you're managing production and the early flowback on those wells, relative to how you manage it on the 4,000 foot wells? And is there any potential to kind of close the gap between those two if you're choking back the longer wells a bit more than the shorter?

Hey, Michael. On our flowbacks basically we do flow them back a little bit differently but it's kind of proportional if you will. We realized that we're trying to unload a 7,500 foot or 9,000 foot lateral. So directionally, when you look at that, we on a 4,000 foot lateral we're going to be flowing back kind of in that 700 barrel to 800 barrel a day range if you well. The extended reach laterals, we'll be at a little higher rate on that somewhere in the 1,200 barrel to 1,500 barrel a day type range on pulling those back. It just kind of 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 the 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 too 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's 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. So we're always going to air to the cautious side of not pulling the wells too hard. And then go from there.

So these flatter declines that we're seeing on the long reach laterals, it's very satisfying from an operational standpoint when you bring wells on and you see the flat decline rate and you can kind of count on them being there for a while. So that's very satisfying too from a production prediction standpoint.

Okay that's helpful appreciate the color. And is there kind of a point at which the -- as you've seen it so far, comparing the legacy extended reach laterals to the base design? Is there a point at which the curves kind of start mimicking each other's shapes more closely and when might that be?

I'm following you I see what you're saying. I can't say I can answer that right now. Again we've got -- I've got six extended 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 that small data set to have kind of an indication of how they're going to kind of a tail off or how they will track on a 4,000 foot lateral until we have some more data.

What I can say is that when we look at the other extended reach lateral data that we're seeing alike from Noble and that where they actually have more data points, we sure feel like our wells are acting a lot like their's. And so our early data points are kind of tracking in that. And again I know they have a short time data too but they sure have a lot more data points than we do. So we kind of leverage that a little bit so I don't think I can directly answer your question right now other than saying we like the flatter decline rates that kind of kind of 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.

Makes sense. Appreciate it. And then on the, can you just remind me, I know you've kept the proppant for the entire well flat or unchanged on the 28 versus 18, like you said. But how much total sand are you putting in the wells, what's your base design?

Our base design is about 1,000 pounds of sand poured per lateral foot of horizontal. So on your 4,000 foot lateral, you'd be looking at 4 million pounds of sand. Obviously if you go to 7,500 feet, it makes the math pretty easy.

Perfect. And then on the work you're doing on the new assets in terms of readjusting inventory post-deal, when might you communicate that with the Street?

Yes you bet. Our technical teams are looking at that right now. We expect to probably look at that here in the next three to four weeks I would expect that we'll have kind of another assessment of what we feel that the acreage looks like. What I can say is we're very, very encouraged with what we're seeing. And I think obviously that initial assessment of 700 net wells we like that assessment. It may be 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's a lot of things that they're now digesting with the data that we now have our actual hands-on.

And of course with a lot of the additional information that we're gathering from our legacy acreage with the test of the six-foot Codell with the 28-stage fracs, the downspacing and all that to apply that across that other acreage too, it's taking a little bit of time to do that. But give us three or four weeks or so and I think we'll be coming out with something.

Fair enough. Sure there, you are very busy. And I just last one on my end is just timing on the A-bench test can you remind me on where that's at and --

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

That's good. Appreciate it. Thanks again

And your next question comes relying of Mike Kelly with Global Hunter Securities. Please proceed. Mr. Kelly would you check your mute feature?

I apologize, I'm that guy. Good morning guys. Congrats on getting quite a bit done since the last conference call.

Thanks, Mike.

A lot of my questions been asked. I'll just kind of two quick ones here. One the rate you gave, the 30-day rates and the 60-day rates, obviously encouraging. Was wondering if you had an average 30-day rate though for all wells you put online that had that much history during the second quarter?

Mike are you asking for an average 30-day rate for I guess -- an average 30-day rate for all the wells we've drilled in the quarter?

Yes, obviously we got look at it apples-to-apples basis vary if you look at all the 4,000 foot Niobrara wells. I'm really just trying to assess and you could say I don't have it in front of me, but everything's at the type curve or better. Is that really the takeaway -- I think that we should be having here I guess is my question.

I guess I'll go back and say Mike I don't have all that data in front of me, so let us get back to you. But what I can tell you is if you look and I'm guessing that you're referencing obviously the 28-stage fracs, the IPs that we put there, correct? And how they compare to the other wells that we've drilled during the quarter is that correct?

Yes -- a blend and if you could break it out on the 28 versus the 18. But just really just trying to get -- we got some great wells out of you that you have select data points on, but as a whole the 18 versus the 28 how they faring versus that group?

You bet Mike. Here's how I'll answer that. One, when you look at our wells that we've drilled in the quarter -- I've gotten some data now in front of me real quick, but when you look at the wells we've drilled during the quarter they're all basically falling within our normal B-bench range. So I think if you look at the average of those wells kind of targeting right around what our type curve averages is. So if you want to compare and contrast what the 28-stage fracs have done, they're performing right now what we think our 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.

Okay great and then just real quick just you mentioned a couple times on the call that three or four weeks timeframe we could expect an update from you. Can you give a little more clarity on that what should we expect to come with that release?

On the capital piece, we're -- right now we're still guiding to the $575 million to $625 million range on the capital. We are looking at that obviously we have some additional testing we want to do with the 28-stage fracs. We will 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'll continue to look at that. And get back to you here, it'll be shortly if we do decide to make any kind of changes.

Okay is there an inventory update that's going to come with this too? Is there production guidance ramifications? I guess what all is encompassed in it?

I think, I was referencing the inventory update probably a little but earlier, we're probably a three or four weeks out on an 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.

As for a guidance range change, I suspect that nothing's going to change on that. But you know we made a minimal adjustment based on the obviously the acquisition that we just had with the kind of the proved production that came with it. 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.

Okay great, guys. Thanks

Your next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed.

Hey, guys thanks for squeezing me in here. Just kind of a clarification where I think that might've missed it earlier. On the long lateral well cost I think that might've missed that there. And then just kind of building off of that would you guys maybe think, early stages with incremental cost maybe with the added frac stages you guys are looking at?

Sure on the long lateral our standard long lateral directionally is on a 9,000 footer we're looking at about $7.5 million and that would be completed with about 36 stages to 40 stages. A 4,000 foot lateral, when we go to the 28-stage frac adds about $250,000. So our long laterals 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'll probably looking at another $500,000 to $650,000. So that long reach lateral maybe with 60 stages probably put you in that directionally around that $8.2 million, $8.3 million range is what I would guess right now. But we'll obviously finalize those cost estimates as we go forward.

Okay perfect and then most of my other questions have been asked but only other one for me. On this the Codell step out that you guys had. Are there any early indications or just kind of 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?

Yes obviously we've got an IP-30 right now so we're looking at the decline rates and we'll 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, then we probably aren't getting so much. So we'll just have to kind of take a look at that. But I don't have any more data than what I've got right now on that IP-30. But those are some of the things we will be looking at.

Okay great that's it for me. Thanks, guys.

Thanks

Your next question comes the line of David Beard with IBERIA. Please proceed

Hi good morning guys. I'll keep this quick. Maybe you could just comment a little bit on the service cost in the Basin? And would you be able to put some color on the [leverage] for 2015 Cap Ex -- or high or low or give us some outlook there? Thanks.

Yes, I'll go ahead and on the service cost we're seeing a little bit of pressure nothing significant yet. But [gel] frac cost I think there's some labor pressures there that are causing us a little bit of increase in the frac cost. But nothing of major consequence yet. So we're keeping our eye on it though, we're keeping our eye on it.

Drilling costs, our contracts we've had our rigs locked up for the year so we haven't seen any significant pressure there, but we're going to be looking at contracts for 2015 as we do our budget process. And so I'll have a better read on that. But we're not seeing, again anything of consequence that is just out there saying it's going to be a significant jump or a significant drop. So there's other error bars, if you will, on estimating cost and all that I think we're absorbing most of these if anything goes up in cost we seem to be kind of finding other ways where other things are costing 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 2015 we're really starting off the budget budgeting process at the moment. So we should have better visibility on that latter part of the year. So it's pretty early to talk about that so we'll come back to you on it.

I certainly understand and thanks for the time and congratulations on some great operational metrics. Appreciate it.

Thanks very much.

Thanks.

Your next question comes the line of Andrew Coleman with Raymond James. Please proceed Mr. Coleman would you please check your mute feature? And your next question comes the line of Richard Dearnley with Longport Partners. Please proceed.

Good morning 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 ranch around the whole -- over your acreage?

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're keeping our eye on it and again we'll be a fastball on the Greenhorn again because we have so much other stuff to work on to be perfectly honest with you. But 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 the Greenhorn's going to be present across most of that. But honestly I don't have that full assessment yet. We know that it's there and that we'll 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 2015 going forward. It'd probably be more like a 2016 and up event for us, testing the Greenhorn.

Okay, thank you.

Thanks.

At this time we have no further questions. And with that ladies and gentlemen I would like [to thank] you for your participation on today's conference. This concludes the presentation. You may now disconnect and have a great day.

Thank you.