Bonanza Creek Energy's CEO Discusses Q2 2013 Results - Earnings Call Transcript

Aug. 9.13 | About: Bonanza Creek (BCEI)

Bonanza Creek Energy, Inc. (NYSE:BCEI)

Q2 2013 Results Earnings Call Transcript

August 7, 2013 11:00 am ET

Executives

James Masters - Manager, IR

Mike Starzer - President and CEO

Gary Grove - EVP, Engineering and Planning

Tony Buchanan - VP, Rocky Mountain Engineering

Ryan Zorn - VP, Finance

Analysts

Irene Haas - Wunderlich Securities

Phillip Jungwirth - BMO Capital Markets

Adam Michael - Miller Tabak

Brian Corales - Howard Weil

Andrew Coleman - Raymond James

Michael Hall - Heikkinen Energy Advisors

Ipsit Mohanty - Canaccord

Michael Scialla - Stifel Nicolaus

Joe Magner - Macquarie Capital

David Beard - IBERIA Capital Partners

Operator

Good day ladies and gentlemen and welcome to the Q2 2013 Bonanza Creek Energy, Inc. earnings conference call. My name is [Bree] and I'll be your operator for today. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions) I would now like to turn the conference over to your host for today, Mr. James Masters, Investor Relations Manager. Please proceed, sir.

James Master

Thanks, Bree. Good morning everyone and welcome to Bonanza Creek’s second quarter 2013 earnings 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, Mike Starzer, our President and CEO will discuss the quarter’s result and will provide an update on our plans for the remainder of the year. Also on the call, Gary Grove, Executive Vice President, Engineering and Planning, will give an overview of our operations during the quarter and the outlook for the remainder of the year. Other members of management will be available during the Q&A portion at the end of the call.

I want to remind everyone, that today's remarks will include forward-looking statements that are based on our current views and expectations, but 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-Q, and our other SEC filings, which you can access through our website or on the SEC’s website.

Also during the 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. Also, all results discussed today reflect continuing operations, not accounting the results from our remaining California property.

With that, it's my pleasure to turn the call over to Mike.

Mike Starzer

Thank you, James. Good morning everyone and thank you for joining us. As you’ve all seen the jet taking off on the cover of our investor presentations with the tag line expanding the runway. When we first came up with that term at last year, we were just beginning to grasp the true potential of our assets. The possibilities were exciting, but untested. Today I am pleased to be able to discuss the results from the past six months of our catalyst drilling program both in the Wattenberg Field, which includes down spacing and extended rich laterals in the Niobrara B and testing of the Codell formation and Niobrara C Bench and in southern Arkansas, where we continue to see encouraging results from our 5 acre pilot program.

We continue to show growth dramatically relative to just one year ago and we maintain one of the strongest balance sheets among our EMP peers in large part because we operate some of the highest rate of return projects in the United States. We had a strong second quarter in advance of what we believe will be a significant ramp in volumes and a steady decline in per unit cost during the second half of the year. As a result, we affirm our 2013 annual guidance for production and per unit LOE and G&A.

I would now like to turn our attention to the results from the second quarter. We are pleased to be ahead of our internal production plan for the first six months of the year. Sales volumes from continuing operations of 13,492 BOE per day, for the second quarter are comfortably ahead of where we forecasted. This is thanks in large measure to the Wattenberg field which continues to impress. We achieved 105% increase in total Rocky Mountain region volumes driven by a 266% increase in production from horizontal wells during the second quarter as compared to the second quarter a year ago.

Importantly in a quarter, when other operators experience sequential declines in Wattenberg production due to infrastructure issues, we were able to grow total volumes by 17% and horizontal production by 30%. Revenues for the quarter increase 64% from a year ago to $84.5 million, supported by a strong crude production and attractive pricing before the effects of hedging of $89.41 per barrel of oil and $4.47 per Mcf of natural gas or approximately $68.83 per BOE.

Net income for the quarter was $14.7 million or $0.36 per share. Excluding unrealized gains from commodity hedges and stock based compensation expense, adjusted net income was $10.8 million or $0.27 per share. Adjusted EBITDAX during the quarter increase 46% from the second quarter last year to $53.9 million thanks to continued strong per unit margins of 66% or $45.34 per BOE.

At the end of the second quarter, Bonanza Creek’s $600 million revolving credit facility was undrawn with a volume base of $330 million a letter of credit totaling 48 million and cash totaling 46 million resulting in total liquidity of 328 million after the completion of our senior notes offering in April.

Our current $330 million borrowing based is subject to redetermination in October. I believe we are well positioned for very strong finish to 2013. We are now moving lastly inflection point, and I see no material impairments to finishing the year will guidance on all metrics.

I will now turn the call over to Gary to discuss operations and the results from our catalyst well testing program.

Gary Grove

Thanks Mike. I am very pleased with the quarter’s results from operations. We continue to be encouraged by what we are seeing from a horizontal Niobrara program in catalyst wells, further confirming our resource and recovery estimates. In addition with only 28 of our 74 plant horizontal Wattenberg wells for the year online at the end of the second quarter, we expect significant production growth in the second half of the year.

During the quarter production from the Rocky Mountain was 8357 BOE per day achieving dramatic gains over produced volumes during second quarter of 2012. Our base production from legacy vertical wells continuous to be adversely impacted by the affect of highlighting pressures, wells fraced in to by nearby horizontals as well as shut in for summer emissions compliance.

We consider these affects include the result of rapidly growing production in such a fantastic area and expect these issues will moderate in our area to some extent with the startup of the DTP (inaudible) plant in late September. Moving on to our catalyst wells in the region, we’re encouraged that this program continues to achieve very attractive results across the board, and I credit our talented operation teams for their efforts and making it a success.

In the Codell formation, we are seeing results above expectations from our two initial horizontal wells. While our first wells a tracking a tight curve similar to our Niobrara B Bench well as a consequence of very flat declines, our second well has achieved substantially higher initial 30 and 60 day average rate of 601 BOE per day and 467 BOE per day respectively with oil cuts averaging 64%. We are very satisfied with our Codell program to-date and our currently drilling our second Codell of the year with two more spud in September and October.

Next we are gratified by the early results from our 40-acre space wells in Niobrara B Bench. Down State and has already been successfully tested by our neighbors and conjunction [Wisdom] has already moved to except 40-acre spacing in the B Bench. The company’s first two 40 acre Niobrara B Bench test wells produced at rates consistent with 80-acre space well with initial 30-day grades on a restricted flow back of 426 BOE per day at 82% crude oil and 409 BOE per day at 77% crude oil.

This performance compares favorably with existing nearby wells. We have another 40 acre test from a four well pad that commenced flow back in early July and we look forward to reporting those results at a later date. Another report catalyst to realizing the full value of the Wattenberg deal is our testing of the extended reach lateral concept which has the potential to significantly increase capital efficiency. We are very encouraged by our first two extended reach laterals. Our most recent well was drilled for a total cost of 7.4 million well under our budget of 8 million and produced an initial 30 day rate of 767 BOE per day and 8% crude oil.

What is particularly encouraging is that the well continues to clean up towards the end of the 30 day period with the last 10 days averaging 824 BOE per day. This appears to be consistent with other operators published data that suggests the production from extended reach laterals continues to increase through the 30-day period before plateauing for sometime over 800 BOE per day. Overall, a very favorable result from this well. Our remaining extended reach lateral tests for 2013 is scheduled to be completed this month.

Finally, our first Niobrara C Bench well drilled last year, continues to holding strong from its 30-day producing rate of 444 BOE per day. The 69 day average producing rates of 383 BOE per day and 343 BOE per day are consistent with the declines we see in the Niobrara C Bench.

We drilled three additional Niobrara C Bench wells late in the second quarter and they are each currently forming back. One final C Bench well was completed this week.

Moving on to the Mid-Continent region, we continued to achieve steady production volumes averaging 5,135 BOE per day for the quarter. We spud 12 10 acre space wells and the remaining two five-acre space wells during the quarter performed 24 recompletions tied 11 wells into sales.

The five acre testing continued during the quarter with recompletions being performed from the first test well, achieving an initial rates above forecast. The second three well pilot has also produced above expectations after fracture stimulating the bottom part of Cotton Valley interval in each well.

The [log] characteristics in reservoir pressures were encouraging and the average initial 30-day production rate of 72 BOE per day was above planned. Together with the first five acre pilot, no interference with adjoining wells has been observed to-date.

Moving over to expenses, LOE was again higher than expected largely as a consequence of non-recurring items of approximately $650,000 in the net Mid-Continent region to replace the processing component on our second Dorcheat-Macedonia gas plant and isolated [well work].

The Rocky Mountain region experienced increased cost of approximately $450,000 related to emissions control requirement and increased compression needs to combat high line pressures. We expect that the additional cost associated with line pressures will decline in the third and fourth quarter. Despite these challenges, we maintained our forecast of 2013 unit LOE guidance.

Cash general and administrative costs were also affected by one time charges of approximately $900,000 as a result of increased legal expenses and professional services. With our increasing production volumes, we maintain our forecast to be within 2013 guidance range per BOE cash G&A as well.

In summary, I am pleased that our planning for this year is still closing at actual results to this point. Through the first six months, we have tied in the sales only 38% of our planned horizontal wells for the full year. So we're looking forward for a significant production growth over the coming two quarters.

We are also very pleased with our catalyst wells and believe we were passing through the de-risking phase in all our tests, thanks to consistent and positive results.

With that I'll turn the call back over to the operator to open up for questions. Mike will close with a final word after the Q&A

Question-and-Answer Session

Operator

(Operator Instructions)

Your first question comes from the line of Irene Haas with Wunderlich Securities. Please proceed.

Mike Starzer

Hi, Irene.

Irene Haas - Wunderlich Securities

Hi. Just wondering why the news channel (Inaudible) on some of your gas sales also was something to drive those and also natural gas liquid, and give us a little a view at to how you look at the second half, that's a little bit softer than it has been historically.

Mike Starzer

Irene are you talking about pricing on the wet and dry gas or you talking about volumes right? Prices?

Irene Haas - Wunderlich Securities

I was talking about price, yeah price realization.

Mike Starzer

Good. Let's - Ryan comment on that.

Ryan Zorn

Yeah Irene, this is Ryan Zorn. So we had a situation in the second quarter where gas prices escalated a bit and meanwhile gas liquids declined especially the butane stream. And so that really kind of threw us off our, our original annual guidance for 50% [premium] in the Rockies followed by gas stream. So having realize that right on guidance in the first quarter, but coming off of that level in the second quarter, we thought it was prudent to guide you to what we saw in the second quarter for the second half of the year.

Now we're seeing gas prices dip down again here recently, but we don't have an update here to really give you, or to ourselves a strong sense for what we should expect in the second half but we thought this So as a strong sensor where we should expect in the second half , but we thought the best way to guide you given what we know now.

And the same thing on the NGLs then the Mid continent region we're guiding slightly lower there as well due to kind of what we've seen over the first half of the year primarily butane again.

Mike Starzer

Same, as -- yes.

Irene Haas - Wunderlich Securities

Yeah, so do you see the situation getting a little better past in 2014 or otherwise?

Gary Grove

There's some things, that could are definitely have some impact on that again we've talked about potential line although I think there's some recent hesitation there about moving some NGLs down from the Rockies down into Mont Belvieu pricing area versus Conway but that being as said, we've not programmed any of that into our forecast at this point in time, we're speaking with currently what we have in the situation as we sit here today.

Operator

Your next question comes from the line of Phillip Jungwirth with BMO Capital Markets. Please proceed.

Phillip Jungwirth - BMO Capital Markets

And in the release you mentioned that you'd be completing the Niobrara program in late October in Mid continent in early September. And when do you - if you decide to increase the budget and continue that program when do you expect that we hear about that and if that's the case, do you think you've maintained a flat rig count or reduced it I late in the year?

Gary Grove

Yeah, so but great question. We are currently looking at that right now and having discussions with our Board about what we potentially may do for the remainder of 2013. We're starting to get some information from some of our offset operators as well where we own some interest but we don’t operate wells. That the program may increase little bit, and we want to do that in conjunction with having an information and giving further guidance on capital for the year, once we know that from our Board I should say will be have a communicate that.

As far as whether the rig count would stay the same or drop down that would be part of that discussion as well. I think the thing for us is we have the ability and the balance sheet go ahead and keep our rigs busy if we so choose to do that. But I think what we want to do is continue to concentrate on some of the catalyst work that we think is important for us to understand exactly how to place wells in sections and therefore be prepared for 2014 and 2015 in terms of how we’re going to continue to develop about in the Wattenberg field.

That being said right now we’re in line with our capital guidance for the year nothing has changed there again short of any additional things that we may put in place here after conversation and communication with the board.

Phillip Jungwirth - BMO Capital Markets

Okay, great. And I think you mentioned that one C Bench well that you have on production and the one Codell well were tracking in line with the B Bench curve. I know you had booked those the C Bench in Codell at lower 3P EUR at your Analyst Day, how much production history do you think you need there to be able to increase that to be closer to when you have the B Bench booked at?

Gary Grove

This is Gary again and so I think the important thing about the Analyst Day, as we looked at that from our true reserves picture. So obviously, we were using something that we felt like, if we were going to put in reserves report that was very consistent and comfortable at a third party analyst situation, so we used something more on the lower end of the range of what we’re seeing from the current wells, that we had in the B for the C and the Codell you’re exactly right.

We have now about 90 days on the first Codell well. And 30 days, if you will or 30 to 60 days on the second Codell well. Honestly, we'll continue to look at that and start to move those up. I would say, we probably want to have at least six months worth of data on both of those and the C Bench wells together, along with some additional wells in that count and you will see us start guiding maybe a little bit higher on the C and the Codell if you will across the property. Again, remember that we're talking about a pretty limited well set and you will see us move slower maybe than you might expect to move the (inaudible).

Phillip Jungwirth - BMO Capital Markets

And then if we see reduced volume pressures later this year or sometime next year, and the vertical well performance improves, would you be able to have positive revisions on those reserves and bring back down [DD&A]?

Mike Starzer

Yes, we would be able to. That was definitely a component of the higher DD&A during this particular quarter because we look at things as a point in time as you well know for reserves. So, internally and externally. So yes, as we continue to get some additional vertical performance back, we could expect to see some additional reserves come back on line with those wells performing to the previous volume.

Operator

Your next question comes from the line of Adam Michael with Miller Tabak.

Adam Michael - Miller Tabak

So if I could go back to that capital program that’s scheduled to finish up by the end of October, I guess my question would be regarding the current guidance right now. Is the current guidance just for the capital program through October and like if you stop drilling literally on October 31 and finish everything would you still meet that guidance?

Gary Grove

Yeah, Adam, that is correct. The current guidance is just for the program that would and like we talked about in October and you mentioned. And yes, we are currently on pace for that particular level of capital for the year.

Tony Buchanon

Yeah, this is Tony Buchanon. I just want to add to when we say our capital program ends in October, that’s our drilling rigs. We will have completion extending through November and December, so we will still spending capital obviously in November, December to complete those wells.

Gary Grove

Great point, Tony. Thank you. That being said, just to follow up on that as well, so the completion schedule that we present in our Analyst Day really hasn’t changed. So the wells coming online in the third and fourth quarter from the existing plan, that’s exactly what we are online for right.

Adam Michael - Miller Tabak

Okay. So just to refresh like if you were to finish drilling a well October 31st, how long would it take to bring that well online and actually contributed to production?

Gary Grove

Are you talking about that earliest would be the latter half of December?

Adam Michael - Miller Tabak

Okay. So it’s about 60 days.

Gary Grove

Yeah, I would say 45 to 60 days is a good approximate time if it’s not on the pad and I don’t believe Tony any of the remainder of this year, we don’t have a lot of pad drilling.

Tony Buchanon

We do have some pad drilling and have to look at this specific well at the end, but we do have some pad drilling, and as Gary mentioned pad drilling would delay those probably 15 days or so as you get the second and third well on pad completed growth wise before you come back and frac and so. We have a variety of wells.

Gary Grove

So that 45 to 60 day is probably a pretty good range.

Tony Buchanon

And Adam you got to give time to clean up, so it’s a matter of putting them online and then given them a chance to reach their peak grades and have real meaningful volume contribution.

Operator

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

Brian Corales - Howard Weil

I have a question on, I guess, you drilled the 40-acre space wells, were those all on the B Bench?

Mike Starzer

Yes, they were and we drilled, Brian we’re [40.2] this quarter and so we drilled two and then we drilled another four well pad, so altogether we have six wells that are drilled to test the 40 acres this year. We talked about the two and the four, we just are flowing back, but yes they are all in the B.

Brian Corales - Howard Weil

Do you all plan to test those in the C or is that kind of the out years a 40 acre spacing in the C Bench as well?

Mike Starzer

It will be in the out years right now. In 2014, 2015 we would look to or just starting to look at exactly how we want to go after some of the catalyst layers in those particularly years. So, that will be more towards our annual guidance for next year, yes and beyond.

Brian Corales - Howard Weil

And I guess, one final question, some of your peers in the neighborhood have kind of taken a pad I guess and drilled multiple layers stacked drilled a B, or C in Codell on various spacing. Is that something that you’re plan to do, or you all just going to be fast follower based on their results?

Mike Starzer

Yeah, we do plan to do that Brian relatively soon, it will be in the early part of 2014 unless we tend to augment this year like we talked about on capital. One comment to that is probably what we’d end doing with that capital is looking at that kind of structure out in Wattenberg Field, but we could have a conversation about time get wells on line and things like that. One thing we do want to kind of put out there as wells as anything we would augment the capital budget with for this year would have pretty minimal if any impact at all in 2013 volumes. That is something we are looking at as well.

Operator

Your next question comes from the line of Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James

And about the completion time, I guess so there is still 40-45 days I guess, what sort of levers that can help, you think (inaudible) over the next six months to try to, I guess bring that down if you have a success on the spud time?

Mike Starzer

We would probably again that 45 days is pretty reasonable because there are sometimes after we drill the wells, we still have to run packers and those packers need time to swell for our completion and that is usually a two week time period. So those two weeks are always going to be given in a process.

We may be able to obviously to shave off some time as we get on the pads where we can frac well back to back, so an individual well time could down, but again as you get in to pad, it could extend those times because you have to shut in until the other wells on the pads are frac and then it does take the time to come back on to those pad to clean those wells. Actually you have to do one at the time because they are on the pads.

So I wouldn’t be shifting from that 45 days too much from a timing standpoint, but the costs we should see it in the costs, as the costs should be coming down, so the timing may not improve, the cost should improve.

Andrew Coleman - Raymond James

Okay, all right. And then on the mix for the quarter and oil was likely to like 71% your type curve during the 65% range. I mean, is that higher level or is that result of lower compression on a gas side or should we kind of trending our forecast up for that higher liquids mix?

Mike Starzer

Andrew, I think overall we guided that 62% to 65% oil in our type curve, but early on we do guide higher than that up into the range that we see today. And so I think that’s what you’re seeing as more of our wells are newer, so the average mix is going to tend to be a little bit higher from that standpoint. Although I will agree with you that there is a little bit of impact on gas, obviously from some high line purchase that we’re seeing out in the area. But overall, we’re reporting a 75% initial oil cuts in these wells, that’s exactly what we have in our type curve as well in the early time data.

Andrew Coleman - Raymond James

Okay, all right. Last question is looking at the extended reach lateral versus the I guess the regular length, but lateral is probably more. I think we’re saying in that, but it looks like there about 65%, 70% more production for about same amount of cost improvement, would that suggest that there -- that you all are I guess what tend to do or what you’re looking at doing to try bump up the IP performance on those extended reach lateral or does it suggest that maybe you’re going to continue to have a mix of regular and extended reach throughout the portfolio?

Tony Buchanon

This is Tony, I will step in on and take this up. I think we’ll have a mix as we go forward. Extended reach laterals again we’re early on in the program of extended reach laterals, we’re just into our third well right now, Obviously repeatability on the extended reach laterals, mechanical repeatability on the extended reach laterals, mechanical repeatability is important. The longer the lateral, the more complications you have in completion and drilling. So you want to be able to repeat those over and over again.

From the IP performance, to be honest with you, we're not really going to be focusing on just improving IP performance. I mean our focus is going to be on the best things that a well to maximize the EUR recovery and so I am careful to get caught up in the IP comparisons. Different wells clean up differently in the first 30 day time period. There is other variables in the reservoir that drive that and so we really like to look at these things as we get at 60 to 90 days and then even further than that and I think if you’ve looked at some of our competitor data that's been out there, our neighbors, specifically Noble, as you looked at the tight curves that they have for their long reach collateral wells that are very close by to our acreage, they gradually clean up. They gradually clean up in the first 30 to 60 days, peak over 800 BOE a day and then kind of stayed stable.

I think that’s really what we are going to be looking for more now and our extended reach laterals is once they peak out, how long do they stay stable and see if they kind of track that same type of tight curve. So again I am going to probably try to cancel to, to back away from IP comparisons and give ourselves a little bit more time to compare more longer time production data to see if those start to match those types of tight curves.

(inaudible), will definitely add to that too. As we look at some of the offsetting data and some of the published EURs if you will and capital requirements to generate those EURs, well obviously see F&D cost trending downward with the extended reach laterals beyond 4000 foot. I mean there has even been some conversation about 7,500 foot laterals and 9,000 foot laterals. Again from some offset operators. So as we see that trend continue to work downward, that’s obviously our goal is to be efficient on our capital side, and do the best economics for retrieving the oil and gas from the area. So as we continue to see more information not only from ourselves, but again from our neighbors that’s exactly the position we’ll be taking in that direction we’ll be heading.

Michael Starzer

And Andrew this is Mike, I might also interject, I’ve asked our technical team to look into our control flow back procedures which we apply pretty conservatively on all of our 4000 and extended reach lateral wells and where maybe some of our offset operators are lessening the strength of their control flow back, we maintain a very conservative control flow back as Tony mentioned maximizing EURs as our priority, but we are looking into that. You may see some changes there in the future.

Operator

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

Michael Hall - Heikkinen Energy Advisors

I guess to duck say a little bit into sort of the equation on Andrew’s question there, and the extended reach laterals you came in at $7.4 million versus $8 million kind of targeted cost, how much further you think that 7.4 could get in terms of the [NAFTA] economics from that angle?

Tony Buchanon

Yeah, this is Tony again. Well let me just kind of step in first how we put that $8 million estimate together for our initial cost assessment. We put that together to end of 2012 when we were doing our budget process and we had our first well under our belts. So we are probably a little bit conservative on that $8 million.

We achieved the $7.4 million right now and I think it's a very good result, driving that cost down further is just something we're going to have to continue to look at obviously taking it from 8 down to 7.4 is a significant achievement so far. I'd be careful to get out there and LOE can come down a whole lot further. We do have opportunities probably taken out another couple of $100,000, 7.1, 7.2 to be realistic, but we haven't executed one of those yet.

I think we have improvements on the completion techniques, we have improvements on the clean up techniques that we need to perfect yet again being that we've only are three wells and who are experienced in doing these . So there is some room there, but I want to be careful, because there is other variables always kind of crop back up and I'm very pleased with the 7.4 result, though and that works out real well at the economics that we'd be seeing on this well right now.

Michael Hall - Heikkinen Energy Advisors

That make sense. So you are now looking to discount to 7.4 just

Tony Buchanon

Right.

Michael Hall - Heikkinen Energy Advisors

And one more on the extended reach lateral, you talk about it hanging in there around 800 barrels a day for sometime. Any quantification of that and how we might think about 60 rate in the context of the 10 day rate that you said?

Gary Grove

Yeah. I'll step in. Right now where we are in that well, we are in the middle of our probably, we're probably about 45 days in on our testing on that well right now. So you have the IP 30 of 767, we have the last 10 days of that IP 30 of over 800 as we had mentioned and we're seeing that trend to continue into the 60 day time period. So really no change from that 10 day extrapolation we had at the end so far into the IP 60 time period and we are not ready to call on IP 60 yet, because we did not have the number of days yet.

Michael Hall - Heikkinen Energy Advisors

And that's pretty typical, what you've seen in the offset.

Gary Grove

I would reference, yeah, I would go ahead and reference the Noble (inaudible) that was pulled out. They have a really good tight curve analysis on their extend laterals that show the gradual build in the first 30 to 60 days of their extended reach laterals, and our well is tracking pretty much very what you would see on that tight curve if you wanted to pull out their presentation, you could probably lay our well down right now and it looks very, very close to that.

Michael Hall - Heikkinen Energy Advisors

Great, will do that. And then on the Codell test, I guess just curious on the tight curve there. I mean the first one was pretty flat from the 30 days to 60 day this test shown, by my math even steeper declines from the 30 to 60 and the B bench tight curve. I was just trying to understand the dynamics in play, a little bit higher gas content on this well and just how that will interacts and how you think those tight curves will ultimately shape out how we got to think about it?

Tony Buchanon

Again Gary is next, this Tony again. As Gary mention; we only got two Codell wells on line right now, so I always caution drawing a lot of conclusions when we have two data points. But really there is a difference between the two wells, the first well that we drilled last year was little bit more oily and of course the well that we drill this year our second Codell test was a little bit more gassy and so that is significant. The gas tends to probably help the well clean up faster, so our second well that we drilled this well being more gassy, the clean up would curve better.

The gas is more energetic in getting the water back out of the formation, so that could encourage one that you have quicker cleanup and a higher IP 30, also it made more gas. So when we are looking at BOEs you have a little bit more gas weight in to that BOE content when we quoted to 601.

The first well oily, probably as we look back on it now technically probably taking a little bit longer to clean up since it was more oily and so therefore you had a more depressed IP 30, but as it cleans up gradually you have a much less decline. I mean as that thing gradually cleans up, it would tend to stay more flat as it comes back and I think that’s probably right now as we look at it technically just more driven by the oiliness of that first well.

So those are kind of the two things, again its two data point its early we see both wells looking like 80 acre B Bench and we’re still projecting that to be a first well right now early on. It’s actually performing basically and above what we would see as an 80-acre B Bench Niobrara.

Gary Grove

Michael, this is Gary, just let me add to that. We see both of these wells within our range of expectations for what we expect out here from our catalyst wells or for any well that we drill on Niobrara at this point or the Codell. And so we know we’re going to see wells above that 30 day average rate and wells below that 30 day average rate. But we have a certain range above and below that we feel wells need to following too for us to be considered successful and both of these do that.

In the Codell the first two that we’ve drilled, especially in comparison to some of the other information we’re seeing from some offset operators as well. So we’re very encouraged by what we’re seeing, we’ll continue to look program, we have additional Codell this year, that we’ll drill and bring online and build up the amount of wells we have in our property and also see additional work from outside operators throughout end of the year.

Michael Hall - Heikkinen Energy Advisors

Great, that’s tough color. I appreciate it. And then just finally on my end on the plain vanilla B Bench well what is kind of completed well cost rate and fees coming in on the second quarter well.

Gary Grove

Yeah, right now we are looking at that 4.2 million for our standard 4000 foot lateral B Bench.

Operator

Your next question comes from the line of Ipsit Mohanty from Canaccord.

Ipsit Mohanty - Canaccord

Lot of my questions were answered but if I could dig a little deeper in to the schedule, you talked about 21 horizontal wells in the Rocky Mountains but is it possible for you to give me a monthly break up. I am obviously pointing towards that eight completion schedule number. So if you could just break up that 21 please?

Tony Buchanon

We haven't really done that much, Ipsit, because I know honestly if we tell you, we can move things from month to month pretty easily but I think what I would guide you to right now we've been very consistent with that number. As now we're seeing the full effect of all the rigs being online since the latter part of March. And so we're seeing a very consistent number going forward. So I don't think we'd have any problem with you breaking those completions up equally through the quarter by month at this point in time as pretty good example of where we are today.

Ipsit Mohanty - Canaccord

Sure. All right, and just, I think borrowing from the last question, not to make too much out of the two wells but how far apart were the two Codell wells geographically? Were they very close together? I'm just trying to get in terms of the geological aspect, what was the difference between the two, why the difference between the two rather?

Tony Buchanon

I think to answer your question on a distance, the first Codell well was if you have a picture in your head of our acreage position was kind of on the northern side of our western acreage.

And the second Codell well that we drilled this year was in the far south western side of our western acreage. So it's about six, seven miles apart, there is a slight difference from as you move further west again we tend to see it get a little gassier as we move further west in the second well, is further west in the first well.

So that’s part of it, and then from a thickness standpoint, the first Codell well, we've probably looked at that about a 12 foot thickness zone in at first Codell well and then second Codell well were probably in about a 14 foot thickness so we had a little thicker on the second Codell well.

That could be effecting it again, two feet doesn’t sound like a whole lot but when its compared 12 feet, you're talking 15% more potential reservoir. So that’s the difference that that we see so far and again but it's early as we continue to analyze the data but that’s kind of couple of things you can put your fingers on.

Gary Grove

This is Gary, too as again I would guide you towards using the average of the first two wells, because again that’s exactly what we're looking for. We know we're going to see certain wells be higher than others, the mix is going to change throughout the property there could be some achieved geologic features that had come into play there as well.

Over the two wells said, again we are pretty excited about what we see, because we think that’s the best way to do that to drill and produce the Codell is to do it horizontally also.

And as Tony mentioned, we're six, seven miles apart on and it tends to be a little gassier to move to the west, southwest, just normally in the section and we're seeing those results, so we're not surprised I guess with [fracing] with what we would expect to see.

Ipsit Mohanty - Canaccord

Sure. And my final in your Analyst Day, you had spelled out shut the drilling plants for the non B Bench wells. Are you given your success in you are seeing extended lateral and Codell. Is there any change to the number of wells you're going to drill there or does it treating, is it the same?

Gary Grove

Right now, our program is not changing for the year at all, short of any argumentation. But as we move into the out years you would expect to see that mix start to increase for the additional C Bench, Codell et cetera versus the normal B Bench wells. I think that would be a very normal expectation.

Operator

Your next question comes from the line of Mike Scialla with Stifel.

Michael Scialla - Stifel Nicolaus

It looks like you're pretty pleased with 5 acre results you've seen in Dorcheat-Macedonia at this point meeting in or beating your curves it sounds like and no impact I think if I heard you right and even the parent wells. Do you have an update there to I guess proclaim victory in book additional reserves on 5 acres. And can you remind me is there it upturning for a significant reserve at here or is this primarily rate acceleration.

Gary Grove

Yeah Michael. Can we saw we won the battle, but war is still going on how is that. It's early still, we've got 2, 3 acre pilots right now, both look encouraging from what we've seen to date.

I think we've kind of talked about this, when we talk about the 5 acre program, we're going to see, we want to see some additional 5 acres wells across the property and before we claim total victory I guess to paraphrase that, the impact to it though will probably the pretty small, upfront and as we continue to gain data across the field, we'll be able to add 5 acre spud if you will in different sections for the field but that will probably stand this probably I would say two to three years, before we get in the range of maybe having them all potentially in our proved reserve report. That being said, I think we've guided towards additional 200 to 220 locations at five acres.

And right now I don’t think we will consider them rate acceleration, I think we would see them as to reserve that due to the lenticular nature of the reservoir.

Michael Scialla - Stifel Nicolaus

Okay, so a couple of million barrel potential is that kind of in the ballpark what you're you are looking for?

Mike Starzer

Just from the pilot, Mike?

Michael Scialla - Stifel Nicolaus

Yeah.

Gary Grove

Yeah. Just from the pilot.

Michael Scialla - Stifel Nicolaus

Okay.

Gary Grove

Actually as we move forward, but.

Michael Scialla - Stifel Nicolaus

Okay. To consider that will be on that line.

Mike Starzer

We can circle back with you on that Mike.

Gary Grove

Yeah, we can circle back with you on that Mike, but I mean realistically if you're going to book 200 plus additional locations out there, you're more in the $15 million to $20 million range on just potential. I think we shared that in our analyst day as well.

Michael Scialla - Stifel Nicolaus

Got it, okay. And Gary you mentioned that you really want to see more data on the C bench and Codell before you put out the type curve there. I was wondering about you had your 313 in MBOE curve for the Niobrara B, how are the B bench wells now are tracking against that do you have enough data there to move that curve at all I know you'd seen a lot of improvement with the installing gas lift early do you have enough data there to change that curve at this point?

Gary Grove

Yeah Michael, I am going to let Tony talked about that, he's obviously got some most information there and talk about the gas lift and anything that would be happening there.

Tony Buchanon

Hey Mike, Tony here, yeah, if you remember during Analyst Day when we had our 313 type curve our actual well results we had called that our target type curve and our actual results were tracking just slightly below that from our Analyst Day.

And what we see now as we more wells have come online and we've gathered more data our B Bench average is now tracking closer and closer to that target 313 type curve. So I am not really ready to move to 313 type curve, but I am very encouraged that the B Bench wells and again if you look at our Analyst Day, we had a little gap in between where our actual performance was in that type curve, we've closed those gaps down. And so those the B Bench wells are now tracking almost right on that 313 type curve. So not ready to move it but we have seen improvement as we’ve gotten more B Bench wells online.

Gary Grove

And Tony would you say that the kind of the changes in operations it’s helping us move towards that on the gas within those Pennsylvania.

Tony Buchanon

Yes, very good point. Now I think we obviously made some improvements there, last year when were completing our wells we had several weeks of downtime, lots of things going on as we transitioned the wells from flowing artificial lifts. And again our flowing to artificial lift right now is much more smoother, we installed our equipment immediately after where are the initial completion and have it ready to go as soon as wells stops flowing we’re able to kick on the gas with smoothing that process up.

Now not to say that everything goes perfect always have small problems in there as we transition but that we’re getting a lot better this year than we were last year.

Gary Grove

Mike, this is Gary. To let me add one other thing, when we look at EURs obviously obviously once we continue to get more and more data beyond the year, and get into one, two, three years worth of data, that will really give us a bigger well count to see the turnover in these wells and I don’t really point lot more towards the EUR changes as we might make. So again, as we kind of communicated, we will probably slower to change in EUR just because we will want to see more and more of that data because we feel it becomes more concrete at that time.

Operator

Your next question comes from the line of Joe Magner with Macquarie Capital.

Joe Magner - Macquarie Capital

Just a question on the 40 acre downspacing, where were those first two wells drilled and how could those first two wells, I guess how those wells are drilled different from how this new four well, 40 acre wells are drilled?

Tony Buchanon

This is Tony. Good question. The first two wells that we're reporting on are if you would our acreage a reserve from the eastern part of our acreage, they were in Section 24 of 561. So that's the western part of our eastern acreage if you will and so the difference is that those two wells drilled near parent well testing the concept that we have drainage or we going to see any significant difference in drilling a 40 acre offset well to a existing well and then bounding in on the other side with another 40 acre B Bench well.

The other four wells are on the eastern side of our western acreage if you will look Section 28 of 562 and if you look at that, the difference there is those were four wells, 40 acre pad, drilled from one pad and there are no parent wells in that area. So that was the test concept of drilling four wells going ahead and drilling them, completing them back to back before producing all those and trying to understand of the concept of how much better we might be able to (inaudible) reservoir doing the fracing technique of that process.

So that’s the difference in that, actually from a distance standpoint where they are partner about three miles apart, when you look at it there is [wash].

Joe Magner - Macquarie Capital

Okay. Just to confirm the restricted flow back on those first two wells is consistent with the way you treat your other B bench wells or is that any things to note on that front?

Tony Buchanon

We’re very consistent with the way we treat B bench wells and I do want to emphasize that the two 40 acre wells that we reported on we have drilled two 80 acre B bench wells in that same section and these wells are performing very much in the same similar fashion as the two independent 80 acre wells that we have in that same section.

So we’ve tried to minimize the geological differences when we compare that by drilling them in the same section and having those two 40 acre wells perform like a two new 80 acre wells at the same time is very encouraging. When you can’t tell the difference between your catalyst wells and your 40 and your 80 acre B bench wells, that’s always a good thing. And so when we look at these things, we are not seeing any significant difference that’s telling us that something strange is going on with our catalyst test.

Joe Magner - Macquarie Capital

Okay. I am just curious do you have any insight into other pilot or 40-acre production history for other wells that have drilled by outside operators and how those rates have performed over time?

Tony Buchanon

Again on the offset the data that we’ve seen published is making the same comments that the 40 acres are right in line with the 80 acre results in the B Bench. So we haven't seen any recent information that changed any of that.

Operator

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

David Beard - IBERIA Capital Partners

I Just wanted to talk a little bit about the impact of the vertical well production, especially on your guidance these my calculations and maybe you can confirm with (inaudible) show that the vertical production was down about 40% year over year. And if that was the case, I wondered what type of sequential vertical production you assumed in your full year guidance?

Gary Grove

David, we did assume some drop in the vertical performance obviously year over year. And quite frankly, we knew that we had continuing line pressure issues during the year. And so essentially, we tried to put that into our guidance.

Now as with everything, things move up and down a little bit on what your expectations are. So we have seen it's a little bit further on vertical performance down than maybe what we did expect. But quite frankly we've been able to see our horizontal wells more to make up for that. And so we feel like we're right in our guidance range for the year.

Moving forward now what we can we made an earlier comment about the impact on some of our reserves in DD&A calculations from the vertical wells. Our goal is to obviously see that performance start to come back up again on some vertical wells that we have out there in the legacy as a result of removing some of these line pressure issues going forward throughout the remainder of this year and into next year.

Mike Starzer

David, this is Mike. I might interject too is it all the operators you are seeing and the same thing course for the vertical impact. That is why in 2009 only 1% the well is drilled in our area were horizontal and currently the first six months of this year 97% of the wells drilled in the area are horizontal. And all of ours that we are drilling a horizontal, so we think that is the mix of the future and again continued the emphasis of the vertical wells and more emphasis on our horizontal development.

David Beard - IBERIA Capital Partners

Okay, that is helpful. And remind me did you give any longer term flow rates from your first extended reach lateral either a 60 or 90 day flow rate?

Gary Grove

We have those, hang on one second, for the first extended reach lateral the IP-60 rate was 680 BOE per day, the IP-90 was 467.

Operator

Ladies and gentlemen, this will conclude the question-and-answer portion of today’s conference. I would now like to turn the call over to Mike Starzer, President and CEO for closing remarks.

Mike Starzer

Thank you. Thanks again to everyone for your interest in Bonanza Creek. To summarize our key takeaways for this quarter; first, we are on plan for significant production growth during the second half of the year; second, our catalyst well reserves are very encouraging and continue to affirm estimates of ultimate reserve potential; and third, we are affirming our 2013 annual guidance for production and per unit cost.

So I appreciate everyone’s interest and the questions as they were terrific and everyone have a great weekend.

Operator

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

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