James Masters - IR Marvin Chronister - CEO Bill Cassidy - CFO Tony Buchanon - COO Lynn Boone - SVP, Reservoir Engineering.

Brian Corales - Howard Weil Phillips Johnston - Capital One Welles Fitzpatrick - Johnson Rice Ipsit Mohanty - GMP Securities Michael Hall - Heikkinen Energy Advisors Mike Kelly - Global Hunter Securities Ryan Oatman - SunTrust Robinson Humphrey Paul Grigel - Macquarie Ken Beyer - Stifel Nicolaus Jeffrey Connolly - Mizuho Securities Wayne Cooperman - Cobalt Capital David Deckelbaum – KeyBanc Curtis Trimble - Brean Capital Andrew Coleman - Raymond James.

Good day, ladies and gentlemen, and welcome to the Q3 2014 Bonanza Creek Energy Inc. Earnings Conference Call. My name is Whitley and I'll be your operator for today. At this time, all participants are in 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, Whitley. Good morning, everyone and welcome to Bonanza Creek’s third 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.

On today’s call, Marvin, Bill and Tony will provide the respective updates on the quarter and then we'll turn it back to the operator to open up for questions. Please refer to the November investor presentation posted on our website as we may reference certain slides on this call.

Our 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'll 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 third quarter results and provide a strategic overview of our business. I'll keep my remarks brief and allow Bill and Tony to get further into the details about this quarter's results and our outlook for the remainder of 2014 and into 2015.

However, I will tell you this, we are pleased with the third quarter. We increased production on pace with our internal plan and drove cost lower while managing in every larger base of production in a growing organization. As I look back on the strategic decisions we've made this year, I am satisfied that we've done the right things.

We didn't lever up in the $100 oil just to boost our growth rate because we knew that there are lower oil price environment could be right around the corner. This company faces the future with great confidence today because we've been prudent with our balance sheet and wise with respect to our allocation of capital.

We have abundant liquidity of over $600 million on an untapped revolver. We're well hedged on crude oil into 2016 at around $90 per barrel, a balance sheet level to approximately two times net debt to trailing EBITDAX and our projects making attractive economic return in the current environment. It's been a successful year so far.

We executed on a significant transaction that hit our production targets and raised capital at attractive terms to ensure we operate from a position of strength as we look forward to 2015.

Now anticipating them regarding the CEO question, the Board has informed me that while they are still conducting a thorough review, they expect to name a permanent replacement in the near future.

They, we, I, have been pleased with the effort put forth by management team, tremendous work on everybody's part and I wish to thank everyone for their patience during this process. With that, I'll turn the call over to Bill..

Thanks Marvin and good morning, everyone. As Marvin said, we're happy with the third quarter results.

Despite dealing with high line pressures due to third party gas compression and facility downtime in late August and early September, we managed to achieve excellent production growth, increasing the sales volumes to nearly 2700 BOE per day or 12% over the prior quarter and 44% over the third quarter of last year.

We're particularly proud that we drilled both per unit LOE and cash G&A for the quarter down below their respective annual guidance ranges. Altogether, we saw 14% improvement in our unit cash operating cost from a year ago and we expect both LOE and cash G&A to comfortably land within annual guidance ranges.

However, as it relates to production, we have adjusted our annual guidance range by lowering the mid point from 24,200 BOE per day to 23,700 BOE per day. The expansion of the Sullivan Compressor Station, which has a major impact on our area experienced recurring downtime issues in parts of the third quarter and again two days in the fourth quarter.

We expect the downtime related to mid stream issues to subside in the fourth quarter, but that has not been the case, nor do we have visibility that it will improve sufficiently for us to hit the midpoint of our original guidance range.

As always we're very focused on what we can do to continue to buffer our operations from the negative impacts of third party midstream downtime.

We've made significant strides in upgrading the gathering and compression systems on our property, completing a major upgrade on the western side late last year and with a portion of the 2014 augmented capital budget, we expect to finish our upgrade on the Eastern acreage.

During the quarter, our realized price for crude oil declined to approximately $86 per barrel from $92 per barrel in the second quarter. In the Rocky Mountains we received an average of $13.63 of the WTI, an average of corporate deduct of approximately $12.

However, despite the softening of oil prices, we still managed an impressive 71% cash margin on an unhedged BOE sales price of approximately $67.

In the DJ Basin, we've actively pursued firm transportation agreements on pipelines to sell our crude and are pleased to announce a deal that secured 12,580 barrels per day on Pony Express Pipeline and an all in differential of approximately $10 off the WTI.

We've secured an additional 15,000 barrels per day on another proposed pipeline, project is starting in 2016. Ultimately our goal is to significantly reduce truck traffic by centralizing or gathering facilities and installing pipelines that will more efficiently transport our product to sales, eventually achieving a more modest deduct to WTI.

For the fourth quarter, we expect some improvement to Rocky Mountain differentials in the $11 to $13 range. As we navigate the current downturn in oil prices, our hedging program and strong balance sheet should have the company maintain steady growth and operational continuity.

We took advantage of strong oil prices in late June and increased our hedged oil volumes in the third and fourth quarters by 50%, double our hedge oil volumes in 2015 and initiated oil positions for 2016. In late September, we achieved a significant increase in our borrowing base from $450 million to $600 million.

We've still have liquidity of approximately $670 million. We're we'll positioned to weather a downturn and take advantage of potential opportunities. Now I'll the call over to Tony for an operations update..

Thanks Bill and good morning, everyone. Operational execution remains our single minded focus. All of the positive things Marvin and Bill mentioned about being we'll positioned to weather a downturn in commodity prices, hinge around our ability to maximize recovery of oil and gas for lower cost.

It starts with a world-class asset and ends with talented people and I think we have both in spades. Let me start with an update on our catalyst oil program and finish with a discussion around the operating environment in the DJ Basin and an outlook for the remainder of the year in 2015.

Over the course of this year, we have dramatically improved our down spacing results by utilizing 28 stage sliding sleeve completions. Our success today continues to validate a combined 32 wells per section in the Niobrara B Bench and C Benches and an additional four wells per section in the Codell.

We first reported an average IP 30 of 480 BOE per day in May on a four well pad spaced at 40 acres in the Niobrara B Bench. All four wells were 4,000 foot laterals using 4 million pounds of sand. The two internal wells were completed with using 28 stages while the two external wells used a traditional 18 stages.

The average IP for these four wells are 416 BOE per day is almost 20% above our type curve for an 80 acre B Bench and after 200 total days of production, they're still tracking above that type curve. However, we would caution folks not to reset expectations without a statistically significant data set.

We just completed a second major down-spacing test with a five well pad. Each well completed with 28 stages targeting 40 acre spacing in each of the Niobrara B and C benches. It is a direct analogue to the tightest spaced pad on our super section, except this time each well was completed with 10 additional stages.

This pad has been on pull back for about 10 days and so far the pressures in early production results look encouraging. Also one of the catalyst well pipeline is a recently completed Niobrara A bench test, which achieved an initial 30 day production rate of 325 BOE per day.

The A bench is half a stick as the B & C benches and the well performed above as expected given the less attractive target sound. While lower in rate than the Niobrara B & C wells we now have our starting point.

This well was completed using traditional 18 stages and we're encouraged by the potential to optimize this result over time and to eventually include the B bench into our inventory and reserve assumptions. Regarding extended reach laterals, we don't consider them to be much of a catalyst at this point.

We all know that the economics are better, so the question is can we successfully execute them over and over again. I believe we can and have demonstrated that today. Our XRLs drilled in 2014 all are holding up very well and you can expect a significantly higher percentage of XRLs to be included in our 2015 program.

Finally, before we turn the call over to Q&A, let me touch briefly on the operating environment in the DJ Basin and our strategic outlook for the rest of this year and 2015.

Regarding the operating environment in the DJ Basin it used to be that we simply didn't have enough gas processing capacity to keep up with production, but the situation is very different today, with the O'Connor Gas Plant and Sullivan Compressor Station directly benefitting our acreage.

Not to mention that we expect an additional 245 million cubic feet of day of processing and compression capacity online by mid next year. Now from time to time, we will still deal with periods of facility downtime or upgrades to infrastructure, but the larger view is quite positive.

In the fourth quarter this year, we added approximately $55 million to the 2014 capital budget to lay the ground work for 2015 in three key areas. First infrastructure, while it represents the smallest relative capital spend, it is our most important.

We will complete an upgrade to the gathering system on our eastern legacy position, which will enable us to develop that area simultaneously with a Northern acquisition acreage and provide for even lower line pressures in 2015.

Second, development; we will kick off our efforts on the acquisition acreage by drilling and completing one well to hold in the expiring lease and completing two existing wells. We will also spend additional capital to continue completion technology trials like more 28 stage and 6 million pound fracs and also two plug and perfs tests.

Finally and thirdly leasing and seismic acquisition. Our land department is focused on increasing working interest and accreting value to the company post acquisition and we have acquired 3D seismic over much of the acquisition acreage.

As we have mentioned in the past, we see significant opportunity to increase working interest and add acreage over the next couple of years. It's important to make clear that the increase to this year’s capital is purely supplementary based on projects that we believe are essential to maximizing our operating efficiencies in 2015.

To conclude I would like to comment again briefly on commodity prices and our impact on our planning for 2015. As we are in the later stages of budgeting for this year -- or for next year I can't be very specific but let me provide a view into how we are thinking about the world.

We use $80 WTI and $3 Henryhub as our base case pricing scenario and are very comfortable with how our business performs at those levels given our current well performance to date, recent catalyst well results and long-term field efficiencies we plan to achieve as our development evolves.

At $80 WTI, we still expect to increase our capital budget next year. You should also expect a higher percentage of extended lease laterals possibly as much as one quarter of the program as we've gained increased confidence in the improved economics and the mechanical proficiency required to execute the program successfully.

If oil prices slide in the low 70s, we will evaluate our pace out of respect for our balance sheet as we remained focused on staying within view of the two times net debt to EBITDAX metric, which is core to a balanced operating plan. Again it all comes back to assets, execution and safe and environmentally responsible operation of our business.

Among the many benefits that Wattenberg offers, our low cost shallow drilling in a competitive service price environment. As always, but even more importantly now, we're focused on getting more for less and continue to drive down our per unit LOE and G&A cost. With that, I’ll stop there and turn the call back over to the operator for Q&A..

(Operator Instructions) Your first question comes from the line of Brian Corales with Howard Weil. Please proceed..

Good morning..

Hey, good morning, Brian..

I look at your presentation you have a good slide that shows kind of the 3P inventory. It does not include anything in the A Bench. And just I know it's early, but is this everywhere, is this just a little bit of your acreage.

Do you have general thoughts there?.

Brian, the A Bench -- first of all, yes the A Bench is present across our entire acreage position, but it will come down through the kind of the thickness of the A Bench section, the chalk section its and also the contribution of that A Moral section that sits below the A Chalk.

The morals are the calcium carbonate rock that have clays in it, but they are oil and gas bearing and they are in between the chalk sections and so when we talked about the A bench previously, if it's just the A chalk that would be something that would be productive for us we kind of saw that productivity across our legacy position of about 9,000 acres directionally.

But if the moral section is also going to contribute especially as we stack these with B’s and C benches in Codells as we put the A bench into kind of the total program development as we develop the entire Niobrara section in combination with Codell, that the A bench -- if the model does contribute, we could expand that 9,000 actually to more across our entire acreage, but again, we don’t have it in our inventory right now, but the first result of 325 I think it gives us something to work with..

Okay. No, thank you.

And you talked over the last couple of quarterly calls on the 28 stage I guess the near wellbore rock breaking that up first, are you all fully committed to that yet? Is it like 2015? Is that going to be your standard completion?.

I am going to say yes. We are fully committed to the 28 stage frac especially as we do our down spacing to 40 acres, no doubt Brian.

We are liking the results we are seeing, again I do want to emphasize, it's only a couple of wells, but we have the second test that we are doing that we have stacked with the B and C staggered stack test with the 28 stages, 10 days of low back encouraging for us right now. I would expect us to do a lot more 28 stage fracs going forward yes..

Okay. I'll let someone else hop on. Thank you..

Your next question comes from the line of Phillips Johnston with Capital One. Please proceed..

Hi guys. Thanks.

You mentioned the midstream issues are still ongoing, has the upgrade at the Sullivan plant has that been completed and if so, is the plant running at 100% now?.

Good morning, Phillips. Yes the Sullivan compression expansion, the actual setting of the compressor has been completed. They are in the commissioning stages of that as they run through that. So there is kind of some up and down time if you will as they get that lined out.

So to answer your first question, the expansion is completed, the second question is no, it's not at 100% yet..

Okay. And the oxygen issues at the O’Conner and [Mueller] (ph) plants have those been solved or are those issue still..

Those have cleared from the system that we know of right now. We have not heard of any additional oxygen issues in the system at this time..

Okay. Great and just looking at the four well pad on 40s, it looks like the decline rate there is still fairly low in the 90 day average looks to be about 17% above your type curve if I am not mistaken versus kind of the 30-day rate was only slightly above the type curve. So I am wondering, which you attribute that to..

Again, I think what we're seeing on that 40 acre pad is more efficient rubblization of the reservoir in between the wells placing more sand near the wellbore to 28 stages allows us to do that.

It kind of limits the -- I would say the frac lengths, its limiting or almost eliminating the competition between the wells at the tighter spacing and again more rubblization of the rock near well and again I would refer you to Slide 11 of our November presentation as you kind of see how those are tracking out of our about 200 days above the type curve..

Okay. Great. Thank you..

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

Good morning..

Good morning, Welles..

It sounds like the midstream issues are a little bit up in the air. Is it enough and its centralizing enough that you would potentially shift your drilling patterns around in '15 to try and avoid specific areas or are you really kind of rounding everything to do same type of systems..

First, let me just emphasize, we're really pleased with the expansion that has taken place at Sullivan and we want to commend DCP for doing that. They worked with us really well on getting that upgraded and that is going to be and it will be significant benefit to. So I want to point that out.

Obviously we have had some issues as we kind of move up in the fourth quarter just get everything lined out. As equipment comes online, it takes a little bit of time to line things up.

But we really do expect the combination of the Sullivan plant coming online in concert with the capital projects that we are doing that we're accelerating into fourth quarter of 2014 from 2015 the pipeline and compression projects on our Eastern acreage, that in combination as we go into the 2015 that we will be in a very good position from pipeline capacity for our gas and we will see lower line pressures.

So we don’t see a reason to moderate or change our programs based on that..

Okay perfect.

And I know it's always hard, but any kind of estimation as to how much production was held back by the higher line pressures?.

Directionally, in the third quarter, we were hit for about 200 BOE a day..

Okay perfect. And just I can I sneak one more in.

The two wells that you guys are completing on the new acreage that were presumably drill by the other operator, we those drilled and landed the same way that you all would have? Is there anything different about that kind of methodology that we should know before seeing this?.

No we think that they drilled and land those in pretty well in the Niobrara B bench. So we feel pretty good about them. The only thing that is limiting on the 4000 foot lateral if anything is believe it only has about 15 stages that we're going to be able to complete.

They did not run the standard even our own standard 18 stage completion, but we still think that that's going to be on an attractive event for us since the wellbore is there and it also give us a great understanding what's going on but other than that, I think we feel pretty comfortable with that..

That’s perfect. Thanks so much..

The next question comes from the line of Ipsit Mohanty with GMP Securities. Please proceed..

Hi. Good morning, guys. With the number of extended laterals that are due to come online that needs to be drilled in the fourth quarter and two of them completed now wasn’t that enough to sort of offset any kind of midstream that you have to guide the fourth quarter down.

I am just curious about the timing of extended laterals in the fourth quarter?.

We have some extended reach laterals coming on in the fourth quarter, but all wells are subject to line pressure. So when we have higher line pressures it basically if the wells are drilled in that area, they will be impacted.

So again as we talked about it, higher line pressures kind of act as an additional choke our flows and it will reduce rates across the build systematically whether it’s a standard reach lateral or extended reach lateral. So I think you would see that no matter what..

And then Tony I am just trying to understand the rational of drilling a Niobrara A when you have so much of DNC to deal with the new acreage from DJ resources.

So would it be safe to assume that as you get more prudent on capital in a low oil price environment you will probably go slow on that program in '15?.

The answer to your first question on why would drill a Niobrara A-Bench. Obviously it’s the next step in evaluating the full resource potential of the Niobrara and also getting an A-Bench test gives the ability to see how we can now factor in the A-Bench in concert as we drill B and C and Codells together.

Going into next year, obviously I don’t want to give away what we are doing on our '15 program. We're going to keep on oil prices and see how that goes, but yet being more efficient would also be in our mindset as we go into 2105..

On the timing of the 2015 program -- in terms of not any color on the 2015 guidance both on the capital and production side as well as giving some meaningful rate from the B and C of the 28 stage frac what are we looking at?.

I would think up from a guidance standpoint, we will be doing that probably by the second week of January or so of 2015 and if we had the ability at that point to have that data on the 28 stage frac on that pad, we would probably issue that at about the same time..

All right. Great. Thank you, Tony..

You bet..

Your next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed..

Thank you. Good morning. I guess some of mine have been addressed actually, but just one question around I am just trying about the cycle times in 2015 given the increased proportion of capital being allocated today and reach lateral program.

Anything we ought to keep in mind just as it relates to potential lumpiness or just the evolution of cycle times as you move into a more [URL] focused program..

Good question. The cycle time on extended reach lateral pads obviously will take slightly longer than our standard 4,000 foot lateral. So that is something to factor in. What I can't say is that, when we put together our plan and release our production forecast for next year our guidance for next year that will all be baked in that.

We will have that cycle time the pads that have extended reach laterals on them all baked in. So to give you an idea yes, extended reach lateral take a few more days to drill. Obviously they are a little bit longer and they take a little bit longer to complete. So that will add some cycle time.

I am not really able to give you a specific number because obviously the pad size is going to factor that whether it's a three well pad, four well pad, or five well pad those kind of things, but that’s all going to be baked into our guidance..

Okay. Fair enough.

And then as we think about extended reach lateral, how are you kind of defining them as we look to '15 in terms of what that laterally length actually looks like?.

Directionally it's going to be between 7500 footers to 9,000 footers..

Okay. And then you guys made some really good progress on the LOE and G&A front like you mentioned any additional commentary around how sustainable that is as you look to 15 I think you had some comments in the prepared remarks.

You are optimistic you can keep driving that down on the strength I think because driving those per barrel rates down from the third quarter level or down relative to the full 14 average.

I am just trying to think about the trajectory as we look to '15?.

Well and again looking I think we continue to make progress on LOE year-over-year and typically quarter-over-quarter. You may see a quarter depending on -- winter quarters may have a little bit more LOE than summer quarter it just depend, but typically we see our LOE continuing to trend downward.

We are offsetting obviously some additional cost that come up with environmental regulations and things like that but again overall we see our LOE trending downward..

And on the G&A front we're basically the same, I think we're below our guidance at the moment and we hope to fall within our guidance for the overall year. So we're continuing to see that trending down and we're very focused on that obviously in today’s environment..

Michael Hall - Heikkinen Energy Advisors:.

:.

Yes, that would be correct..

Okay. Perfect, thanks guys. I appreciate it..

Your next question comes from the line of Mike Kelly with Global Hunter Securities. Please proceed..

Thanks good morning..

Hey good morning, Mike..

Hi, I've got a question just kind of may be bigger picture question on the capital efficiency front for your guys and seems like each ops update we get from you is great because you are at your type curve if not better and this implies to me about $16 F&D cost.

Yes, if we look at your DD&A rate you are close to $27 this quarter, it’s increased $5 since the beginning of 2013 and that's putting downward pressure on your recycle ratio and capital efficiencies kind of declined in the corporate level.

So I was just kind of trying to understand that and reconcile why the DD&A rate would be going up versus [Inaudible] pressure applied to it..

Thanks, this is Bill here. I guess we're producing more than we're adding on reserves and what we've typically seen in a normal cycle is DD&A rate tends to creep up as we go through the year and then as we go back and redo and report our reserves at the beginning of the year it tends to move down.

So we expect that normal cycle to continue and that then will obviously impact the recycle ratios etcetera. So hopefully that will add the reserves that we continue to drill as Tony moved through in his [Inaudible], and we continue to produce a lot more than that we're adding reserves at the moment..

Okay.

Is that a function of just not getting full credit and reserve orders being just conservative in nature?.

We've tended to be very conservative in our reserve bookings. We had a full as prepared reserve report by [Inaudible] last year and we are going to be - we have an audited report early in 2015 and we will continue on that as [conservative] [Ph] nature. Lynn do you want to comment further on reserves [Inaudible]..

We've done a lot of different kind of testing -- spacing testing both vertically and laterally this year between the both Niobrara and Codell. And it really takes the acquisition of data throughout the year to make a judgment on what can be booked as proved reserve.

So as Bill alluded to the last quarter and the year is when we really have the data to analyze and make those final decisions for year end. So you will see additional bookings that pop up in the fourth quarter.

So as Bill indicated, you would expect your DDNA to go down at that time and this was especially interesting year because of all the testing and I would expect something similar next year as well..

Okay. Maybe just order of magnitude if you can give that color on - you got a 313 type curve, what's in an average type of well that you would go in your orders and try to book as proved..

Not really following your question..

So 313 is your average kind of 80 acre spacing. You are the chief presenter in your presentations here.

In terms of what you asked your reserve auditors at the end of the year to prove what is that average number? You come in at 313 so it was booked at or is there something considerably lower than that?.

Well our reserves are determined or estimated deterministically which means that the PUDs are estimated based upon the PDPs, which are in there, or immediate offsets and so I can't give any light to whether average PUD reserve will be at this year-end. So it varies throughout the field.

We see higher reserves on the West side than we do on the East side. And I think if you went back to our Analyst Day and the three P there that kind of gives you some color on how that changes across the field from West to East..

Okay. I’ll follow up with you guys offline. Thank you..

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

Hi. Good morning..

Good morning, Ryan..

I was wondering if you guys could talk about what you saw in your view of the acquired acreage. No change in the location kind of 900 well or 700 wells.

But wondering if you could speak more specifically how that acreage compares to what you expected? Did anything surprise you or change significantly behind kind of the unchanged headline there?.

The simple answer to that one is no, nothing changed. What I can tell you is that we've completed a thorough technical analysis and we are still very, very excited about the acreage position that we have.

We have even more confidence in the numbers that we have out there the 700 net locations, but we also still feel again that’s probably a conservative assessment. So again our excitement about acreage is unwavering.

We feel good, but we really don’t want to do much more on this until we actually gear up there and start drilling our own wells, which we start here in the fourth quarter and moving from there and we will start drilling even more in the first quarter of 2015..

Makes sense. And can you just remind me kind of how that compares to the legacy acreage whether its infrastructure or prospectivity of the different zones etcetera, just kind of conceptually..

You bet. I will tell you what, obviously you probably have seen our map in our investor presentation, but we consider on the North side, the Western North side, there is a about 14,000 acres or so on that Western North side, very blocky and contiguous. We think that that acreage we call it high quality acreage.

The higher working interest for that and similar to basically our legacy position and similar to Wells Ranch. So we feel like we have the B, the C, and Codell potential on that part of the acreage. The southern acreage is about 8,000 or 9,000 acres, little blockier, the checker boarded sections, if you will, on the South side, again very attractive.

We call that high value. We feel that we also have the B, C, and the Codell prospectivity there and similar to our legacy position.

The other acreage as it goes to the North and to the East as you know that’s a lower working interest and we haven’t really called that high value and we'll look at that later, but that added up to about 11,000 of that total 35 that we added in..

That’s perfect, it’s a great view. And then one just kind of tidying up question for me.

On the 2014 capital plan can you just remind me what percentage of that $630 million to $680 million it going to the drill bit versus infrastructure etcetera?.

It's about 90%. It could be about 90%, is going to be a pretty good number for you..

Perfect. Thank you, guys..

Your next question comes from the line of Paul Grigel with Macquarie. Please proceed..

Hi good morning. Just following up on the acquired acreage and the resources there.

As you guys go into year end and booking reserves, is there a potential upside or it is just with the handful of new wells in the fourth quarter that that will be something that would roll more likely into 2016?.

Yes. We won't be booking any reserves but that would be new that we would have the Montreal wells in 2014 this year. Again those will be drilled in the fourth quarter late and we wouldn't have the production available to actually extract that out. So any reserve bookings on the new acreage will take place in 2015..

Okay. Great. And then just on the oil mix for the quarter. This quarter is at the low end of the historical oil percentage.

Was there any specific driver of that be it oil declines coming in a little bit faster than gas over time as the wells do or just location of wells? And then what should we expect going forward on the oil mix?.

I think what you can see is there really -- I don’t think we have anything really anomalous on the oil mix for this quarter that we would say that’s going to be changing. It's probably just a factor of the production volumes for this quarter that we came in. But we do not see anything significantly changing from an oil mix going forward on our assets.

So that's about how I can answer that one. I don't see anything different going forward from that standpoint..

Okay. Perfect. Just wanted to make sure. Thanks so much, that's it for me..

You bet..

Your next question comes from the line of Ken Beyer with Stifel. Please proceed..

Hi, good morning..

Good morning..

On the four-well Niobrara B pad, I was just wondering if you can completely attribute that success to the new 28 stage frac technique or are there other factors you can contribute that rate to.

Is there anything with the geology over there?.

Our objective on that pad was to select an area geologically similar as close as we could to the super section test that we did earlier in 2014. That was the absolute intent of that was to get the geology as best we could similar to that super section test and we felt like we did that.

So we've kind of eliminated the geology as a factor and try to get it down to where it is basically just the frac technique being the major influence on that pad performance. That was the specific intent in picking that pad..

Perfect. Thank you..

You bet..

Your next question comes from the line of Jeffrey Connolly with Mizuho Securities. Please proceed..

Hi, good morning, guys. Wanted to ask about the Eastern Codell well in the intersection.

Tony, can you talk a little bit about how that compares to the Codell wells on the Western acreage after 60 days?.

You bet. The Eastern well is tracking a little bit lower than the Western Codell wells as you probably saw on the IP 30 and the IP 60. But, we do still think - we think that there is a possibility for that thinner Codell to be something that we can move forward and develop.

Again, remember that we went into that well with our standard 4000 foot lateral, standard 18 stage frac again for us to make sure that we minimize variables so that we can compare and contrast the data that we get out.

So we think we are at a pretty good starting point for the thinner Codell and we think we can move forward with hopefully optimizing that and getting that to where we would be thinking about maybe adding that into our inventory. But again it is not in our inventory as of this point. But we'll continue to work on that.

We have a second test here in the fourth quarter will help us kind of move our thoughts on that forward..

Okay. Great.

And then on the new drill well on your acquired acreage, is that on the Northern block or the Southern block?.

Northern block..

Okay. Thanks, guys..

You bet..

Your next question comes from the line of Phillips Johnston with Capital One. Please proceed..

Just a follow-up on Brian's question earlier on the A-bench.

What sort of EUR you think that that A well is tracking to so far and do you think the well is economic in sort of $80 to $90 price environment?.

My first question -- answer was I really probably don't know that answer right now. It is very early. We've got our first IP 30 out. 325 obviously that is a lower IP than our B&Cs as we have indicated. But we have not gotten a chance to put anything on an EUR yet.

We are going to definitely need more time and more production data before we can actually call that..

Okay.

And then can you just give us an update on the progress of your first North Park well?.

Yeah. Actually the first North Park well we actually have drilled the first well vertically and successfully cored the Niobrara section and got that out. We pulled that core and we then shut down the rig at that point. We are starting to get into the end of the season up there to where we could actually execute the work.

So we shut it down at that point. We are going to take the core up and go look at the core over the winter and then come back next year and determine at that point whether or not to go horizontal on that well.

We also have a second well that we did not have time to get in and drill, but we will target that in the next year again based on these core results we will look at that probably sometime late second quarter I would suspect..

Sound good. Thank you.

Your next question comes from the line of Wayne Cooperman with Cobalt Capital. Please proceed..

I jumped off for five minute so I missed something, but what -- you guys are out there in the Niobrara. You've got some pretty good acreage but you got a lot of operational issues.

What's your attitude as far as mergers and acquisitions and being part of a bigger company that might really covet your acreage and could fix some of your issues?.

I'm not sure I'll answer it but will give it a go. We think we have very attractive acreage. 70,000 net acres to the company in the area. We've had a really strong quarter across the board from revenue, EBITDAX and cost perspective. And we've had some really good results on the production side that Tony's gone through.

Regarding M&A, there is always talk about M&A and every basin especially in today's oil environment, but we continue to focus on our operations that’s kind of how we get paid on a daily basis and that's how the market regards us as a company.

Our operational expertise has helped us to acquire the acreage in DJ Basin or the DJ Resource acreage earlier this year. And our focus is to execute on our legacy and our newly acquired acreage. So there is always lots of chatter on M&A but we're focused on our operations really..

I mean no offence but you're the only energy stock in the whole market that's down today, so I guess most people don't agree that you had such a good quarter and a good outlook..

I guess the market – we’ll react the way the market reacts on a day to day basis, so can't really make a comment on one day's reaction..

That one day your stocks are down enormously from lately, but whatever I guess you guys think you’re doing a good job then everybody else doesn’t..

Your next question comes from the line of David Deckelbaum with KeyBanc. Please proceed..

Tough act to follow guys, but I will give it a shot..

Thank you, David, appreciate this very much..

At the risk of asking an operational issue I guess or a question, you said that next year's program perhaps could be 25% extended reach laterals. But you also said that you feel like you have a lot of confidence in the execution on that.

I guess what could change that sort of percentage? Is there a sensitivity to a commodity in doing more extended reach laterals or is there still a waiting period until you feel like you can pound these things out 100% of the time?.

David, I think what you can look for is, we can execute those, we think we can execute the extended reach laterals fairly consistently. But again bear in mind we are working up through 11 right now and before we continue to move even more forward, I think additional repeatability is needed. We are seeing that right now.

I think we leave our program available for next year for optimization if we think we can put more extended reach laterals then we would.

But also our programs are always going to have 4,000 foot laterals involved when you look at the -- as I've talked about I think on the road, when you look at our acreage position a lot of it is conducive to the extended reach laterals, but we have 4,000 foot laterals necessary to kind of fill in the blanks if you will.

It's kind of filling in the puzzle to maximize the development of the acreage.

So kind of leaves that with you but we are confident in extended reach laterals, we are going to be increasing that next year and long-term I think extended reach laterals again you’ll see obviously more and more of those unless something significantly changes and I don’t see anything on the horizon that will do that right now..

Got you. and I don’t know if I missed this, but can you guys quantify at all had it not been for sort of the downtime at Sullivan, do you know where you would have been tracking relative to your original guidance or is there an actual barrel equivalent per day that you feel was lost due to the down time..

Well in the third quarter, we felt that it hit us about 200 Boe a day in the third quarter for the quarter. .

Do you have any read on 4Q?.

Well in 4Q I think as we had talked about before, we felt that we were tracking towards the midpoint of our guidance, but with the issues that we're seeing right now, that’s why we've made the adjustment. We saw that in October and we see this continuing through the rest of the quarter.

As I had mentioned probably earlier, we have the infrastructure project that we’ve moved into 2014, Sullivan is working through the commissioning issues that we see, and again the capacity is there, but we did see this temporary issue on run times and down times probably lasting into this quarter a little bit more than we initially anticipated in our plan, and that causes us our adjustment.

So our plan felt like we’d up and running full speed ahead right now, and that’s not the case, so that’s why we made the modification..

Okay.

And if I could just ask one more, it seems like with the down time in 3Q, Rocky still performs quite well even with some of fewer completions than you had originally planned, would you characterize or is it too early to say that for the most the B bench wells that you drilled this year have been outperforming your base case curves, and how quickly could you look to revise that?.

I would say that obviously there’s a lot of factors in the production performance yield timing of when the wells actually come online and all that. So, we’ll be looking at our reserves. That data is being analyzed right now.

We’re going to come through the end of the year reserve process and I think if any changes are made at the appropriate time that would be it..

Thank you for the responses. Best of luck, guys..

Great. Thank you..

The next question comes from the line of Curtis Trimble with Brean Capital. Please proceed..

Thanks. Good morning everyone. Was just hoping to drill down little bit on the rubblization on the 40 acre wells.

Have you noticed any change in composition of production for those internal wells completed with more stages and presumably better rubblization?.

No, we have not. We see the similar type oil and gas mix, if that’s the question, absolutely, similar oil and gas, no change on that..

Good.

How about for the A well, any difference in composition of production there vis-à-vis the B?.

No, we have not. It seems that the A, B, and C all are very comparable on the oil and gas mix when we look at that. The only place we see a little bit of change is in the Codell. As we’ve always mentioned, that the Codell tends to be just a tad little gassier..

Good deal. I appreciate it..

You bet..

Your next question comes from the line of Andrew Coleman with Bonanza Creek. Please proceed..

Hey great. Thanks lot, it’s Raymond James. Appreciate your time this morning.

I just had a couple of more questions, just more on the Sullivan compression station there, I guess or plant; how much of the downtime there is related just to kind of ramping that operation up? Or is it just the number of wells that are being brought on and batch completions or, and I guess can you give me a sense also how much of that plan is Bonanza Creek versus other players?.

I’ll take that in pieces. The first question is how much of the time we think is -- I think most of the down time it might being in the way we see it is just associated with getting this thing up and running to 40 million a day.

So, it’s all about the commissioning of the plant, the size, the amount of capacity getting everything up and running smoothly. So, that’s pretty much it.

As for – we are – we contribute probably a good portion of the gas to that plant that comes from our Eastern acreage position, but there are several other operators that do have gas going to that but I think we are probably a majority of the gas going to that plant..

As you head into winter, I don’t know if it's lower ambient temperature that are going to make much of a difference in that plant performance but I think you might smooth out some of those issues through that, is that a fair assessment?.

What we think in the fourth quarter – again, that’s kind of what we’ve revised our guidance top end our range downward, we see down time associated through the fourth quarter still kind of continuing.

I think it’ll be lined out the way we see it by the end of the fourth quarter, that coupling with the infrastructure project that we have going on in our Eastern acreage that will help us improve our own efficiencies on our own side. That will help us leverage that $40 million capacity much better by the end of the year.

So I see still down time impacts in the fourth quarter..

Okay. All right. Fair enough. Then just one question on the [XLs] [Ph] again, remind me again what the limitations are between move in to a bigger portion of your drilling program using [XLs] [Ph]..

What we want to make sure on the XRLs before we go down to 40 acre spacing is, we’ve talked about the 28 stage density on 4,000 foot laterals, the next step on the XRLs is to duplicate the 28 stage density on the XRL 9,000 footer. So that would be more comparable to like 60 stages.

So, that’s probably the next step in our process to get us to execute that. We will be doing that here shortly to get that plan, so that we can execute that. So, that’s probably the biggest piece of that is we like the 28 stage fracs on 4,000 footers, love 9,000 foot wells and now we get to combine all that..

Okay. And so it sounds like that’s basically the frac placement less maybe stratigraphic issue with placing the actual well bore..

Yeah, absolutely..

Okay.

Given the little pullback we've had here in oil prices, as you look at your service contracts, do you think that some flexibility is built in those contracts that you might have a chance to I guess to get access to different operators that might help smooth that out if need be?.

Well, obviously going into 2015, the lower pricing environments tend -- service cost tend to follow that but there is also some sort of time period involved before those costs catch up. So, all I can say is we’ll keep an eye and do everything we can to obviously get the service cost as optimal as we can as we look at this environment moving forward..

Okay. Great. Thanks a lot for you time today..

Appreciate it..

There are no further questions in queue. I’ll now turn the call over to Mr. Tony Buchanon for closing..

Great. I just would like to thank everybody for the time on the call today, and wish everybody a great weekend. Thanks again for joining us..

Ladies and gentlemen that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day..