Civitas Resources Inc (CIVI) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q2 2013 Bonanza Creek Energy, Inc. earnings conference call. My name is Brie, and I will 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, sir.

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, President and CEO, will discuss the quarter's results 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 the 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 counting the results from our remaining California property. With that, it's my pleasure to turn the call over to Mike.

Thank you, James. Good morning, everyone, and thank you for joining us. You have 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 concept 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-reach laterals in the Niobrara B, and testing of the Codell formation and the Niobrara C Bench. And in southern Arkansas, where we continued to see encouraging results from our five-acre pilot program. We continued to show -- grow dramatically relative to just one year ago, and we maintain one of the strongest balance sheets among our E&P 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 experienced 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 increased 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 increased 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 borrowing 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 base is subject to redetermination in October.

I believe we are well positioned for a very strong finish to 2013. We are now moving past the inflection point, and I see no material impediments to finishing the year with 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.

Thanks, Mike. I am very pleased with the quarter' results from operations. We continue to be encouraged by what we are seeing from our horizontal Niobrara program and catalyst wells, further confirming our resource and recovery estimates. In addition, with only 28 of our 74 planned 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 region was 8,357 BOE per day, achieving dramatic gains over produced volumes over second quarter of 2012. Our base production from legacy vertical wells continues to be adversely impacted by the effects of high line pressures, wells fracked into by nearby horizontals, and wells shut in for summer emissions compliance. We consider these effects simply the result of rapidly growing production in such a fantastic area, and expect these issues will moderate in our area, to some extent, with a startup of the DCP with Southland 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 operations teams for their efforts in making it a success. In the Codell formation, we are seeing results above expectations from our two initial horizontal wells. While our first well is tracking a tight curve similar to our Niobrara B Bench wells, as a consequence of very flat declines, our second well has achieved substantially higher initial 30- and 60-day average rates 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 are currently drilling our second Codell of the year, with two more to spud in September and October.

Next, we are gratified by the early results from our 40-acre space wells in the Niobrara B Bench. Down-spacing has already been successfully tested by our neighbors, and conventional wisdom has already moved to accept 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 wells with initial 30-day rates under restricted flowback 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 flowback in early July, and we look forward to reporting those results at a later date.

Another important catalyst to realize in the full value of the Wattenberg Field is our testing of the extended-reach lateral concept, which has the potential to significantly increase capital efficiencies. 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 at 80% crude oil. What is particularly encouraging is that the well continued 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 suggest the production from extended-reach laterals continues to increase through the 30-day period before plateauing for some time over 800 BOE per day. Overall, a very favorable result from this well. Our remaining extended-reach lateral test for 2013 is scheduled to be completed this month.

Finally, our first Niobrara C Bench well drilled last year continues to hold in strong from its 30-day producing rate of 444 BOE per day. The 60- and 90-day average producing rates of 383 BOE per day and 340 BOE per day are consistent with the declines we see in the Niobrara B Bench. We drilled three additional Niobrara C Bench wells late in the second quarter, and they are each currently flowing back. One final C Bench well was completed this week.

Moving on to the Mid-Continent region, we continue to achieve steady production volumes, averaging 5,135 BOE per day for the quarter. We spud twelve 10-acre space wells, and the remaining two 5-acre space wells during the quarter performed 24 recompletions and tied 11 wells to sales. The five-acre testing continued during the quarter, with recompletions being performed on the first test wells achieving initial rates above forecast. The second three-well pilot has also produced above expect expectations, after fracture stimulating the bottom part of the Cotton Valley interval in each well. The [log] characteristics and 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 Mid-Continent region to replace a processing component on our second Dorcheat-Macedonia gas plant and isolated well work. The Rocky Mountain region experienced increased costs of approximately $450,000 related to emissions control requirements and increased compression needs to combat highline pressures. We expect that the additional costs associated line pressures will decline in the third and fourth quarter. Despite these challenges, we maintain our forecast for 2013 unit LOE guidance. Cash, general and administrative costs were also effected 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 for per BOE cash and G&A, as well.

In summary, I am pleased that our planning for this year has so closely matched actual results to this point. Through the first six months we have tied into sales only 38% of our planned horizontal wells for the full year, so we are looking forward to significant production growth over the coming two quarters. We are also very pleased with our catalyst wells and believe we are passing through the de-risking phase in all of 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.

(Operator Instructions) Irene Haas, Wunderlich Securities.

Just wondering why -- can you shed a little light on your gas sales, both the wet stuff and dry stuff, and also the natural gas liquid, and give us a little feel as to how you look at the second half, felt a little softer than the half has been historically?

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

Yes. I am talking about price -- yes, price realization.

Ryan -- let Ryan comment on that.

Yes, Irene. This is Ryan Zorn. We had a situation in the second quarter where gas prices escalated a bit. Meanwhile, gas liquids declined, especially the butane stream. That really threw us off our original annual guidance for a 50% premium in the Rockies for our wet gas stream.

Having realized 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 have seen gas prices dip down again here recently. But we don't have enough data here in the third quarter to really give you and ourselves a strong sense for what we should expect in the second half. But we thought this was the best way to guide you, given what we know now.

And the same thing on the NGLs in the Mid-Continent region. We're guiding slightly lower there, as well, due to what we've seen over the first half of the year, primarily on butane again.

Same with -- yes.

Yes. So do you see the situation getting a little better, perhaps, in 2014, or otherwise?

There are some things that could definitely have some impact on that. Again, we've talked about a potential line, although I think there has been some recent hesitation there, about moving some NGLs down from the Rockies down into the Mont Belvieu pricing area versus Conway. But that being said, we've not programmed any of that into our forecast at this point in time. We're sticking with currently what we have in this situation as it sits today.

Okay, great. Thank you.

Phillip Jungwirth, BMO Capital Markets.

In the release you mentioned that you would be completing the Niobrara program in late October, and Mid-Continent in early September. If you could decide to increase the budget and continue that program, when do you expect that we'd hear about that? And if that's the case, do you think you would maintain a flat recount or reduce it late in the year?

Yes, Phillip. 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 interests, but we don't operate wells, that their program may increase a little bit. We will want to do that in conjunction with having that information and giving further guidance on capital for the year. Once we know that from our Board, I should say, we will be able to communicate that.

As far as whether the recount would stay the same or drop down, that will be a part of that discussion, as well. I think the thing for us is we have the ability and the balance sheet to 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 out 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.

Great. And I think you mentioned that the 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 and Codell, at the lower 3P EURs at your Analyst Day. How much production history do you think you need there to be able to increase that to be closer to what you have the B Bench booked at?

This is Gary again.

I think the important thing about the Analyst Day is we looked at that from a true reserves picture. So, obviously, we were using something that we felt like if we were going to put in a 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'd 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 then 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. You'll see us move slower, maybe, than you might expect to move EURs up.

Okay. Then if we see reduced line 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 the DD&A rate?

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. 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 online with those wells performing to their previous volume.

Great. Thanks, guys.

Adam Michael with Miller Tabak.

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 if you stopped drilling, literally, on October 31 and finished everything, would you still meet that guidance?

Yes, Adam, that is correct. The current guidance is just for the program that would end, 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.

Okay. Great.

And this -- yes, this is Tony Buchanan. I just wanted to add, too, when we say our capital program ends in October, that's our drilling rigs. We will have completions extending through November and December. We will be still spending capital, obviously, in November, December to complete those wells.

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

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

You talking about -- the earliest would be the latter half of December.

Okay. So it's about 60 days?

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

To be honest with you, we do have some pad drilling. I would have to look at the specific wells 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 a pad completed -- drilled-wise, before you can come back and frac them. We have a variety of wells there at the end.

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

And Adam, you got give them time to clean up, too. It's a matter of putting them online and then giving them a chance to reach their peak rates and have real meaningful volume contribution.

Okay. Thanks, guys.

Brian Corales, Howard Weil.

I have a question on your drilling -- I guess you drilled the four 40-acre space wells. Were those all in the B Bench?

Yes, they were. And we drilled -- Brian, we're reporting on two this quarter. We drilled two. And then we drilled another four-well pad. So all together we'll have six wells that are drilled to test the 40 acres this year. We talked about the two and the four we are just flowing back. But yes. They are all in the B.

Do you all plan to test those in the C, or is that the out years? A 40-acre spacing in the C Bench, as well?

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

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

Yes, 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've talked about before on capital. One comment to that is probably what we would end up doing with that capital is looking at that kind of structure out in the Wattenberg Field.

But we just had a conversation about time to get wells online and things like that. One thing we do want to put out there, as well, is anything we would augment the capital budget with for this year would have pretty minimal, if any, impact at all on 2013 volumes. That's something we're looking at, as well.

Okay. And that's helpful. Thanks, guys.

Andrew Coleman, Raymond James.

The completion times, I guess, it sounds like they are on a 40 to 45 days. What sort of levers do you think you will pull over the next six months to try to bring that down, if you are having success on the spud times?

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

We may be able, obviously, to shave off some time as we get on the pads where we can frac wells back to back. So an individual well time could come down. But again, as you get into the pads, it could extend those times, because you have to leave wells shut in until the other wells on the pads are fracked.

And then it does take the time to come back onto those pads to clean those wells out. You have to do them one at a time because they are on a pad. 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. The costs should be coming down. So the timing may not improve, but costs should improve.

Okay. All right. And then on the mix for the quarter in oil -- or liquids was 71%. Your type curves are in the 65%-ish range. Is that a higher level? Is that a result of lower compression on the gas side, or should we be trending our forecasts up toward that higher liquids mix?

Andrew, I think overall we guide to 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. So, I think that's what you are seeing, is more of our wells are newer, so the average mix is going to tend to be higher from that standpoint.

Although I will agree with you that there is a little bit of impact on gas, obviously, from some of the high line pressures we are seeing out in the area. But overall, we are 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.

Okay. All right. And then last question. Just looking at the extended-reach lateral versus the regular length lateral, there is probably a more elegant way of saying it than that. But it looks like they're about 65%, 70% more production for about the same amount of cost improvement. Would that suggest that you all are -- what can you do, or what are you looking at doing to try to bump up the IP performance on those extended-reach laterals, or does it suggest that maybe you're going to continue to have a mix of regular and extended-reach throughout the portfolio?

This is Tony. I will step in and take this one. I think we will have a mix as we go forward. Extended-reach laterals, again, we're early on in the program of extended-reach laterals. We are just into our third well right now. Obviously, repeatability on the extended-reach laterals, mechanical repeatability is important. The longer the lateral, the more complication 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 are not really going to be focusing on just improving IP performance. Our focus is going to be on the best things for the well to maximize the EUR recovery. I'm 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. We really like to look at these things as we get out 60, 90 days, and then even further than that.

I think if you've looked at some of our competitive data that's been out there, our neighbors, specifically Noble, as you looked at the type curves that they have for their long reach lateral wells that are very close by to our acreage, they gradually clean up in the first 30 to 60 days, peak over 800 BOE a day and then stay stable. I think that's really what we are going to be looking for more now in our extended-reach laterals is, once they peak out, how long do they stay stable, and see if they track that same type of type curve. Again, I am going to probably try to counsel 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 type curves.

Andrew, just let me add to that, too. As we look at some of the offsetting data in some of the published EURs, if you will, and capital requirements to generate those EURs, we obviously see F&D costs trending downward with the extended-reach laterals beyond 4000 foot. There has been some conversation about 7500-foot laterals and 9000-foot laterals, again, from some offset operators. 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. 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 and that's the direction we will be heading.

Okay.

Andrew, this is Mike. I might also interject. I have asked our technical teams to look into our control flowback procedures, which we apply pretty conservatively on all of our 4000 and extended-reach lateral wells. Where maybe some of our offset operators are lessening the strength of their control flowback, we have maintained a very conservative control flowback. As Tony mentioned, maximizing EURs is our priority. But we are looking into that. You may see some changes there in the future.

Excellent. Thank you very much for your time today.

Michael Hall, Heikkinen Energy Advisors.

To dovetail a little bit into just the other side of the equation on Andrew's question there, on the extended-reach laterals, you came in at $7.4 million versus the $8 million targeted cost. How much further do you think that $7.4 million could get in terms of the advancing economics from that angle?

Yes, 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 estimate. We put that together at the end of 2012, when we were doing our budget process, and we only had our first well under our belt. So we were probably a little bit conservative on that $8 million. We achieved the $7.4 million right now. 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 million to $7.4 million is a significant achievement so far.

I would be careful to get out there and tell you we can come down a whole lot further. We do have opportunities to probably take out another $200,000. $7.1 million, $7.2 million could 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-out techniques that we need to perfect yet, again, being that we've only -- are three wells into our experience of doing these. So there is some room there.

But I want to be careful because there's other variabilities that can always crop back up. I am very pleased with the $7.4 million result, though. That works out real well with the economics that we have been seeing on this well right now.

That makes sense. Certainly not looking to discount the $7.4 million. Just curious.

Right.

One more on the extended-reach lateral. You talk about it hanging in there around 800 barrels a day for some time. Any quantification of that and how we might think about 60 rates in the context of, you know, that 10-day rate that you said?

Yes. I'll step in. Right now where we are in that well, we are in the middle of our -- 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 ten days of that IP-30 of over 800, as we had mentioned, and we are seeing that trend 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. But we are not ready to call an IP-60 yet because, like I said, we just don't have the number of days yet.

And that's pretty typical of what you have seen in the offset?

Yes. I tell you, I would reference -- yes, I would reference -- if I could, go ahead and reference the Noble presentation that was pulled out. They have a really good type curve analysis on their extended-reach laterals that show the gradual build in the first 30 to 60 days of their extended-reach laterals. Our well is tracking pretty much, very much what you would see on that type 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.

Great. I will do that. And then on the Codell test, I guess just curious on the type curve there, I mean, the first one was pretty flat from the 30-day to the 60-day. This test showing, you know, my math even steeper declines from the 30 to the 60 than the B Bench-type curve. I am trying to better understand the dynamics at play. A little higher gas content on this well and just how that all interacts and how you think those type curves ultimately shape out. How we ought to think about it.

Well, again, Gary -- this is Tony again. As Gary mentioned, we have only got two Codell wells on line right now. I always caution drawing a lot of conclusions when you have two data points. Really there is a difference between the two wells. The first well that we drilled last year was a little bit more oily.

And of course, the well that we drilled this year, our second Codell test, was a little bit more gassy. That is significant. The gas tends to probably help the well clean up faster. Our second well that we drilled, this well being more gassy, the clean-up would curve better if the gas is more energetic in getting the water back out of the formation. So that could encourage, one, you have a quicker clean-up and a higher IP-30. Also, it made more gas. So when we are looking at BOEs, you have a little bit more gas weighed into that BOE content when we quoted the 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. So therefore, we added more depressed IP-30. But as it cleans up gradually, you have a much less decline. As that thing gradually cleans up, it would tend to stay more flat as it comes back. 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, it's two data points. It's early. We see both wells looking like 80-acre B Bench, and I'm -- we still projecting that the first well right now early on is actually performing basically and above what we would see as an 80-acre B Bench Niobrara.

Yes, Michael, this is Gary. Just let me add, too, 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 in the Niobrara at this point or the Codell. So we know we are 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 that we feel wells need to fall into for us to be considered successful. And both of these do that.

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

Great. That's helpful color. I appreciate it. And then just finally on my end, on the plain vanilla B Bench wells, what do completed costs or AFEs come in at on the second-quarter wells?

Yes. Right now we're looking at that $4.2 million for our standard 4,000-foot lateral B Bench.

Good number. Great. Thank you.

Ipsit Mohanty, Canaccord.

A lot of my questions were answered. But if I could dig a little deeper into your (technical difficulty) [completion] schedule. You talked about 21 horizontal wells in the Rocky Mountains, but is it possible for you to give me a monthly breakup? I am obviously pointing towards that eight completion schedule number. So if you could just break up that 21, please?

We haven't really done that very 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 as being 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. We are 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 a pretty good example of where we are today.

Sure. All right. And just, again, 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 am trying to get, in terms of a geological aspect, what was the difference between the two? Why the difference between the two, rather?

To answer your question on the 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 southwestern 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, and the second well is further west than the first well. That's part of it.

And then, from a thickness standpoint, the first Codell well -- we probably looked at about a 12-foot thickness zone in that first Codell well, and the second Codell well we're probably in about a 14-foot thickness. So we had a little thicker zone in the second Codell well. That could be affecting it. Again, two feet doesn't sound like a whole lot. But when it's compared 2 feet to 12 feet, you're talking 15% more potential reservoir. That's the differences that we see so far. And again, but it's early, as we continue to analyze the data. But that's a couple of things we can put our fingers on.

Ipsit, this is Gary. 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 are going to see certain wells be higher than others. The mix is going to change throughout the property. There could be some key geologic features that have come into play there as well.

But with a two-well set, again, we are pretty excited about what we see because we think that's the best way to do the -- to drill and produce the Codell, is to do it horizontally also. And as Tony mentioned, we are six, seven miles apart. It tends to be a little gassier as you move to the west/southwest just normally in this section. And we are seeing those results. So we're not surprised, I guess, (technical difficulty) with what we would expect to see.

Sure. And my final one. In your Analyst Day you had spelled out the drilling plan for the non-B Bench wells. Are you -- given your success, are you seeing an extra in the lateral in Codell? Is there any change to the number of wells you will drill there, or does it retain -- is it the same?

Right now, our program is not changing for the year at all short of any augmentation. 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.

Thanks, guys.

Mike Scialla, Stifel.

It looks like you are pretty pleased with the five-acre results you have seen in Dorcheat-Macedonia at this point, meeting or beating your curve, it sounds like, and no impact, I think, if I heard you right, on even the parent wells. Do you have enough data there to proclaim victory and book additional reserves on five acres? And can you remind me, is there the opportunity for significant reserve adds here, or is this primarily rate acceleration?

Yes, Michael, can we say the won the battle, but the war's still going on? How's that? It's early still. We have got two three-acre pilots right now. Both look encouraging from what we've seen to date. I think we have kind of talked about this -- when we talk about the five-acre program, we are going to want to see some additional five-acre wells across the property before we claim total victory, I guess, to paraphrase that.

The impact to it, though, will probably be pretty small up front. And as we continue to gain data across the field, we will be able to add five-acre PUDs, if you will, in different sections of the field. But that will probably span at least probably, I would say, two to three years before we'd be in the range of maybe having them all potentially in our pre-reserve report. That being said, I think we've guided towards an additional 200 to 220 locations at five acres. Right now, I don't think we would consider them rate acceleration. I think we would see them as a true reserve add, due to the lenticular nature of the reservoir.

Okay. So a 2 million barrel potential? Is that kind of in the ballpark of what you're looking for?

Just from the pilot, Mike?

Yes.

Yes.

Yes, just from the pilot -- pilots.

Okay.

Actually, yes, as we move forward, but --

Okay.

We can circle back with you on that, Mike.

Yes, we can circle back with you on that, Mike. I mean, realistically, if you are going to book 200-plus additional locations out there, you are more in the 15 million to 20 million range on just potential. I think we shared that in our Analyst Day, as well.

Got it. Okay. And, Gary, you mentioned that you'd really want to see more data on the C bench and Codell before you put out a type curve there. I was wondering about -- you had your 313 MBOE curve for the Niobrara B. How are the B Bench wells now 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?

Yes. Michael, I'm going to let Tony talk about that. He has, obviously, got the most information there, and talk about the gas lift and anything that would be happening there.

Yes. Hey, Mike, Tony here. Yes, if you remember during Analyst Day, when we had our 313 type curve, our actual results, we called that our target-type curve, and our actual results were tracking just slightly below that from our Analyst Day. What we've seen now as we -- as 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 ready to move to 313 type curve, but I'm 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 and 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.

And Tony, would you say that the changes in operations is helping us move towards that on the gas lift and those types of things?

Yes, very good point. I think we, obviously, made some improvements there. Last year, when we were completing our wells, we had several weeks of downtime, lots of things going on as we transitioned the wells from flowing to artificial lift. Again, our flowing to artificial lift right now is much more smoother.

We install our equipment immediately after the initial completion and have it ready to go as soon as the well stops flowing, we're able to kick on the gas lift, so that's smoothing that process out. Now, not to say that everything goes perfect. We always have small problems in there as we transition. But we're getting a lot better this year than we were last year.

Mike, this is Gary. Let me add one other thing. When we look at EURs, obviously, once we get it -- we continue to get more and more data beyond a 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 that will really point a lot more towards EUR changes as we might make. So, again, as we've communicated, we will probably be 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.

That makes sense. Thank you.

Joe Magner, Macquarie.

Just a question on 40-acre down-spacing. Where were those first two wells drilled, and how could those first two wells -- or how those wells were drilled differ from how the new four well 40-acre wells were drilled?

Yes. This is Tony. Good question. The first two wells that we were reporting on are, if you would, our acreage -- it is over on 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. The difference is, is that those two wells were drilled near a parent well, testing the concept that we have drainage. Are we going to see any significant difference in drilling a 40-acre offset well to an existing well and then bounding it 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, Section 28 of 562. And if you look at that, the difference there is those were a four-well, 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 of those and trying to understand the concept of how much better we might be able to so rubblize the reservoir during the fracking techniques of that process. So that's the difference in that. Actually, from a distance standpoint, they are apart -- they are about three miles apart when you look at it as the crow flies.

Okay. And just to confirm, the restricted flowback on those first two wells is consistent with the way you treat your other B Bench wells, or is that -- anything to note on that front?

No. Very consistent with the way we treat the B Bench wells. And I do want to emphasize that the two 40-acre wells that we reported on, we had 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 exact same section.

So we try 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 the 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 80-acre B Bench wells, that's always a good thing. When we look at these things, we are not seeing any significant differences telling us that something strange is going on with our catalyst tests.

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

Again, on the offsets, 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's changed any of that.

Okay. Great. Thank you.

David Beard, IBERIA.

Just wanted to talk a little bit about the impact of the vertical well production, especially on your guidance. Because my calculations, and maybe you could confirm or deny them, 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?

David, we did assume some drop in the vertical performance, obviously, year over year. Quite frankly, we knew that we would have 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. We have seen a little bit further vertical performance down than maybe what we did expect. But quite frankly, we have been able to see our horizontal wells more than make up for that. And so we feel like we are right in our guidance range for the year.

Moving forward now, again, we made an earlier comment about the impact on some of our reserves and 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 moving some of these line pressure issues going forward throughout the remainder of this year and into next year.

David, this is Mike. I might interject, too, is that all the operators are seeing the same thing with the vertical impact. That's why in 2009, only 1% of the wells 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're drilling are horizontal. So we're seeing -- that is the mix of the future. And again, continual deemphasis of the vertical wells and more emphasis on our horizontal development.

Okay. That's 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?

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, four-six-seven.

All right. Great. That's helpful, guys. Thank you for your time.

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.

Thank you, Bri. Thanks again to everyone for your interest in Bonanza Creek. To summarize our key take-aways for this quarter, first, we are on plan for significant production growth during the second half of the year. Second, our catalyst well results are very encouraging and continue to affirm estimates of ultimate resource potential. And third, we are affirming our 2013 annual guidance for production and per-unit costs. So I appreciate everyone's interest, and the questions, they were terrific. And everyone have a great weekend.

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