James Masters - Investor Relations Manager Marvin Chronister - Interim President and Chief Executive Officer Bill Cassidy - Chief Financial Officer Tony Buchanon - Chief Operating Officer.

Brian Corales - Howard Weil Irene Haas - Wunderlich Securities Mike Kelly - Global Hunter John Malone – Mizuho Securities Michael Hall - Heikkinen Energy Advisors Mike Scialla - Stifel Drew Banker - Morgan Stanley David Deckelbaum - KeyBanc David Beard - IBERIA Ryan Oatman - SunTrust.

Good day, ladies and gentlemen, and welcome to the Q1 2014 Bonanza Creek Energy Incorporated Earnings Conference Call. My name is Chris and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session.

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

Thanks, Chris. Good morning and welcome to Bonanza Creek’s first quarter 2014 earnings conference call and webcast. Yesterday afternoon, we issued our earnings press release and this morning filed our 10-Q with the SEC. You can access both on our website.

As an agenda for today’s call, Marvin Chronister, our Interim President, and CEO will provide an overview of the quarter. Following his remarks, Bill Cassidy, our Chief Financial Officer will report results from the quarter. And Tony Buchanon, our Chief Operating Officer will provide an operations update.

Other members of management are present and will be available during the Q&A portion at the end of the call. I invite you to access our May investor presentation, which is available on our website. We may make certain references to slides during the call.

Today’s remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-K and other SEC filings.

Also during this call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release.

Also, all results discussed today reflect continuing operations and do not include the results from the remaining California property that’s sold on May 21 of this year. With that, I will turn the call over to Marvin..

Thank you, James. Good morning everyone and thank you for taking the time to join us as we discuss our first quarter results and outlook for the year. We are pleased to report another solid quarter. Operations are right on track with plan. And we affirm our 2014 annual production guidance of approximately 50% growth.

Early results from the Super-Section are encouraging and give us increased confidence in our 3-P reserves and inventory assumptions. As you can see, Bonanza Creek looks very much the same today as it did just a few months ago. We have a driven team focused on delivering on our business plan.

I don’t want to thank our stockholders and our analysts for your support through the leadership transitions during the past three months. While nobody likes change very often, we can identify these times as defining moments. I am confident that we will say the same for this company in the years to come.

My confidence in the company grows everyday that I am in the office. It’s a pleasure to work alongside the talented men and women of Bonanza Creek as they pursue their responsibilities with excellence and creativity.

Of course, it also helps that our employees are working in an asset base that delivers consistent economic returns in the top tier of any resource play in the country. I want to comment on two topics briefly before I turn the call over to Bill and Tony to discuss financial and operational results for the quarter.

First, the search for permanent CEO was ongoing and we really have nothing new to report on that front other than to say that we are three months into a process that we expected would last three to six months. The Board is committed to finding the right person to fill the role.

And as I have before that person will lead the company into the next stage of growth with a clear appreciation for the strategy and people that were responsible for that success in the first place. However, I think some off-target speculations regarding corporate strategy have gained too much traction recently.

So, let me reiterate and set the record straight. Number one, we are laser-focused on operational execution hitting our targets and being an efficient low cost operator are our highest priorities. Number two, we prioritize both on acreage acquisitions around our core positions.

We added approximately 4,500 net acres in the Wattenberg and we think we can add another 10% to 15% to our acreage this year. Finally, we continue to evaluate asset acquisitions and other expansion opportunities primarily in the Wattenberg field as prudent to the running of our business.

Holding firm to the commitment that we will manage the value, there is value to be had. We will take advantage of that. If not, then we are contempt to execute on well over a decade’s worth of drilling inventory and wait for a more opportune time.

We price our balance sheet and the concentration of our assets and won’t tarnish that profile in a misguided attempt to grow even more aggressively or to achieve greater scale. With that I will turn the call over the Bill Cassidy, our CFO to run through the quarter’s results..

Thanks Marvin and good morning. First quarter production was down sequentially from the previous quarter. While we don’t typically provide quarterly guidance, we published a range of 19,000 Boe to $20,000 Boe per day average for the quarter, so that you all could be set a baseline for your models as we progress through this year.

If you recall, we began drilling the Super-Section in November and thus had no horizontal completions for nearly three months, that’s what we could forecast. What we did not forecast was the severe cold weather we encountered in Colorado and Arkansas during the first two months of the year.

We estimate having lost approximately 700 Boe per day from the quarter due to the severe weather, but still delivered volumes on plan at 19,701 Boe per day. Turning to Super-Section into sales ahead of schedule was the key factor in achieving a successful quarter, so I wanted to recognize our operations teams for their exemplary work.

Looking ahead to the rest of the year, we plan to place approximately 35 gross wells into sales each quarter which directionally speaking should add approximately 3000 Boe per day each quarter in a linear fashion to arrive at the midpoint of our annual production guidance. Now keep in mind that 90% of our wells will be drilled on pads this year.

So actual completions per quarter will fluctuate to some degree based on timing. Costs incurred on capital expenditure for the first quarter was approximately $150 million putting us on pace to achieve our stated annual CapEx guidance of between $575 million to $625 million. We reported revenue of $127 million.

Before the effects of derivatives, we realized $89.11 per barrel of crude oil, $5.99 per Mcf of gas, $54.53 per barrel of NGLs and a solid $71.85 per Boe, up from the $68.47 per Boe in the fourth quarter of last year. We reported adjusted EBITDAX of $80.5 million.

Crude differentials in the Rocky Mountains improved slightly over fourth quarter to $12.46 per barrel off of WTI. Midstream capacity for both oil and natural gas continues to improve and we do not expect to see significant bottlenecks in transporting our products to markets.

We are forecasting crude differentials to stay in the $11 to $13 range in the second quarter. Lease operating expense was approximately $17.1 million or $9.63 per Boe.

The largest components of LOE in the Wattenberg were well servicing due to the severe cold weather compression and pumping, while in Arkansas we performed our annual gas plant maintenance in the first quarter resulting in increased labor and maintenance costs.

While operating costs were over planned for the quarter, we reaffirmed our annual guidance of between $8 and $8.60 per Boe expecting unit cost to trend lower through the course of the year. General and administrative expense was approximately $23.7 million or $13.37 per Boe of which approximately $7.5 million was related to executive departure costs.

G&A without these costs would have been approximately $16.2 million or just over $9 per Boe and more importantly cash G&A would have been approximately $13.3 million or $7.51 per Boe.

Please keep in mind that the second quarter will also include G&A costs related to executive departures in the amount of approximately $6.9 million including $2.9 million of cash. As with LOE we expect unit G&A to trend lower into the guidance range of between $6.25 and $7 per Boe excluding expenses related to executive departures.

I will now turn the call over the Tony to give an operations update and to discuss the Super-Section in more detail..

Thank you, Bill and good morning everyone. I want to join Marvin and Bill in thanking our operations teams for another strong quarter as executing on the plan. As Bill mentioned their efforts in a very challenging operating environment this winter are the commended.

I know everyone has been waiting to hear about the Super-Section results and we are pleased to present you with the early data of our preliminary – and our preliminary analysis. As we reported in the press release all three of the pads testing, different downspacing and pattern configurations have IP 30 rates within our range of expectations.

Let me begin with an overview of our initial observations. First, early data suggests that 20 wells per section is the minimum for development and 36 wells per section is achievable. Second, strong results from the Niobrara C-Bench when stacked with the B-bench provide increased confidence that this interval is derisked across our acreage position.

Third, multi-bench stacking arrangements have the potential to significantly increase individual well productivity. Four, tracer data on the Codell suggest that testing less than a 160 acre downspacing is appropriate.

And finally and most importantly, optimizing our completion techniques is the key to maximizing the ultimate NPV per section and downspacing to 40 acres within an individual Niobrara bench. It is important to note that these observations are clean from approximately 60 days in a projected well life of over 30 years.

Our technical teams will be focused on the extended production histories that we will reserve in the second half of the year in order to move towards meaningful conclusions about these tests and the path will take 2015 and beyond. With that said let’s dig into the results from each distinct pad.

Please refer to Slide 15 in our May investor presentation for schematic of the Super-Section. We will discuss each pad as they are labeled in the presentation Pad 1, Pad 2 and Pad 3. Also as reported in the press release, we had two wells with mechanical difficulties.

One Codell well was excluded from Pad 1 average, while one of the 8 acre spaced Niobrara B-bench wells was completed sub-optimally which had negative impact on Pad 3’s overall average. Pad 1 featured sacked 80 acre Niobrara B-bench and Codell wells with an offsetting Niobrara C-bench well. Its average IP per well was 448 Boe per day.

Unfortunately, due to mechanical failure in the Codell well, we do not have a full understanding of the potential to downspace to Codell beyond 160 acres. Minimal tracer communication, however between the wells is very encouraging, but we will need additional testing for this concept.

Pad 2 tested stacked 40 acre Niobrara B-bench wells with offset 40 acre Niobrara C-bench wells. As far as we know, this is the first test of its kind in the Wattenberg field or at least the first with published data. We are happy to report five wells of average 374 Boe per day.

Now obviously our B-bench type curve is higher than that in the 460 Boe per day range. Well, we think this is a pretty good early result. I would like to point out that our first Codell well had about that same 30 day rig and that subsequent wells had been terrific.

The results from this pad so far outperformed other single zone 40 acre tests in the B-bench. What we find particularly compelling applied to our understanding of Pad 2 is actually exceptional the result of Pad 3 are demonstrating again that multi-bench patterns are the way to optimally develop the asset.

Now, we are testing ways to optimize completion techniques to better accommodate downspacing to 40 acres and maximize the NPV per section. We are currently testing 28 stage fracs using the same aggregate amount of fluid and sand as our 8 inch stage fracs.

The concept is introducing more entry points along the well bore resulting in increased reservoir contact and less frac extension. We completed two 80 acre space Niobrara B-bench wells in the fourth quarter, one 28 stage, and one 18 stage to test this concept.

The IP 30 rate on the 28 stage well averaged 496 Boe per day and through 90 days this well is exhibiting a flatter decline rate than the offsetting well frac with 18 stage performing 10% to 15% better and tracking meaningfully above our target B-bench type curve.

Also we are just now pulling back a second test where we applied 28 stage fracs on 40 acre spacing. These wells are looking good so far and we look forward to analyzing IP30 data and comparing them to the wells in Pad 2, which were completed with our standard 18 stage fracs. Finally, as I mentioned, Pad 3 was exceptional.

Quite frankly, it exceeded our expectations with approval IP 30 average of 516 Boe per day. This is very exciting, because the success that multi-bench development could materially boost recoveries of oil in place.

In fact, while we are only providing pad averages, I should say that the results from the C bench wells on this pad, where every bit is good as those from the B bench. We are now confident that we have de-risked the Niobrara B bench and C benches across our acreage position and are pursuing full development in both zones.

Now, I would like to address the question I am sure everyone ask, which is why does Pad 2, our stacked 40-acre B and C test have a lower IP rate than Pad 3, our 80-acre B and C test? I want to emphasize that our technical people are continuing to analyze tracer, pressure and production data from all the wells, but initially, the simple answer is that the wells are closer together and are in more competition for this stimulated reservoir rock.

As I mentioned, we conducted 18 stage fracs on all the wells on both pads. The 18 stage fracs generate greater extension that leaves gaps of un-stimulated reservoir between the fracs. Even though limited sand production and early IP rates indicates that we have not spaced wells so close together as to create nonviable wells.

The 28 stage fracs that we are currently testing reduce frac lengths and stimulate more rock near wellbore, which should optimize the performance of closer spaced wells. So, let me review again our observations that we discussed earlier.

First, early data suggests that 20 wells per section is a minimum for development and 36 wells per section is achievable. Second, results from the Niobrara C bench when stacked with the Niobrara B bench provides increased confidence that this interval is de-risked across our entire acreage position.

Third, multi-bench stacking arrangements have the potential to significantly increase individual well productivity. Fourth, tracer data on the Codell suggests that testing less than 160-acre downspacing is appropriate.

And finally, optimizing our completion techniques is the key to maximizing the ultimate MPV per section and downspacing to 40 acres within an individual Niobrara bench. As it relates to the rest of the company’s operations, I will be brief. Things are moving forward on plan.

We expect to drill 121 operated wells in the Wattenberg field, 10 of which will be extended-reach laterals in the Niobrara B and C benches and the Codell. So far, this year we have successfully drilled a 7,500 foot lateral in the Codell, a 9,000-footer in the C bench, and another 9,000-foot in the Niobrara B bench.

The extended-reach laterals drilled in 2013 have held up nicely continuing to track a 700,000 to 800,000 Boe EUR curve.

We think the potential economic benefit to drilling extended-reach laterals is extremely compelling and we are using this year to reduce the mechanical risk associated with these wells before allocating more of the budget to them in the future.

Also throughout the year, we will be drilling a variety of downspaced and stack wells – stack wells from pads that will augment our learnings from the Super-Section with the goal of informing our 2015 budget and development plan.

In Arkansas, we continue to test down spacing to 5 acres and expect to have delineated the Dorcheat-Macedonia field by the end of the year. Operations there are dependable as usual. We place great value in this asset that can grow 10% plus per year and produce free cash flow. I want to thank you for your time and attention during our prepared remarks.

I am happy now to turn the call over to the operator for Q&A. When we are finished, Marvin will close with the final comments..

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

Hey, guys. I am just going to ask a few on this in the 40-acre spacing. I guess this – I guess we are seeing a lot of the same kind of completion techniques done in another plays.

One, were you all looking at doing this earlier before you saw the 40-acre spacing and then kind of what was your original expectation for your 40 acre spaced results?.

Hi, Brian, this is Tony. I will go ahead and take that. I think the first part of your question will be considering different types of frac techniques before we actually came into the Super-Section development.

As part of that answer is, yes, we were always looking considering ways of optimizing our frac techniques, more stages, less stages or obviously even in the past we had gone from 16 stages to 18 stages in an effort to do that.

But it became more apparent that the 28 stage technique will probably more applicable to downspacing because of the reduced frac lengths and the more – with the more exit points or entry points into the reservoir from the horizontal lateral, it would encourage more rubblization near that wellbore as opposed to rubblization further away from that wellbore.

And also filling gaps between the fracs because if you can envision the 4000 foot lateral with 18 stages, there is going to be gaps of unstimulated rock in between those stages, having 28 stages now minimizes that you, it may not eliminate it totally but it reduces it significantly.

And so if you can envision a lateral with a lot of reservoir rubblized but not so much further from a wellbore contacting to where another well might interfere with it if you will. So from expectations – expectation standpoint and what we expected in the 40 acres, we expected the IP 30s to be within our range of expectations of our B bench wells.

And they were, they are within that range. We are pleased to see that they are actually above the 40 acre tests that were in the B bench by themselves. So indicating that the stack B and C nature has improved upon that, so that was an encouraging event.

So we were expecting that to be within range of our expectation, they are within our range of expectations. And I think the positive note is that the stacking concept B and C was actually a little bit better than the B standalone 40 acre test..

Tony, that’s extremely helpful.

And maybe just one more if I can, are you all going to do like the same tests tightly – or 40 acres spaced in the B and C just like you did now with the new completion technique?.

What we have going on right now, Brian and that’s a great question, what we have – the 28 stage frac that we have that we are testing, that I had mentioned in my comments is a 40 acre B, just 40 acre B bench test with a 28 stage fracs in that within a 40 acre B offset. So we have that test going on right not.

That is not encompassing of C bench test with that currently. Going forward, we are looking at doing that we have additional 28 stage fracs planned and we are looking how to orient those to go ahead and further augment B and C stacking technique with those 28 stages.

I think the next key test is that 28 stage in the 40 acre B bench to see how that performs compared to other 18 stage fracs and see how that performs compared to the initial test we had on the 80 acre B bench 28 stage frac..

Okay, that’s very helpful. Thanks guys..

You bet..

Alright. So it looks like you have your next question coming from the line of Irene Haas with Wunderlich Securities..

Yes, hey, good morning. Hi. How are you doing? And I might have missed it, because I came a little late, any progress on the CEO position.

And secondarily understanding that only probably half of your acreage is a viable for the traditional Codell, and kind of any color on you pushing this play eastwards, have you done much work on this recently?.

Yes. Hi Irene, this is Tony. I will go ahead and pick the Codell question. As we had mentioned the Codell, we have it already basically delineated on the 15,000 net acres on the basically the western side of our position. We have two tests going on this year that first well has actually been drilled and we are in the process of completing it.

And what is that, that is testing as we step further east on our western acreage, but we are starting to test those boundaries. We also have a second test in the second half of the year that we will be drilling to do that.

The intent of those two wells I think, if we are successful, if you have 15,000 net acres on the west side, we have got about another 20,000 to prove up in the Codell. Those two wells hopefully will help us prove up about another 5,000 or so. And then once we have that we will continue to step further east in 2015.

But to recap one of the wells has actually been drilled so far. We are in the process of that completion. So hopefully we will have some results here as move into the second half of the year that we can kind of update you on..

Thanks..

On the CEO question, I will turn that over to, I am sorry Irene can you repeat the CEO question that you had..

Yes.

The permanent decision is it – any color when it might be filled?.

Actually this is more Marvin. As I mentioned in the opening remarks with three months into the process and we thought all along it would most likely take 3 to 6 months. Occasionally they take longer than that. I mean I have seen them take up to a year.

I think in fact last time you and I saw each other that’s probably exactly what I had said at that point. We are three moths into it. I now the Board is talking to folks working through the process, but that’s where we are, there is nothing to update beyond that at this point..

Okay, thank you..

Alright, so it looks like you have another question. Next question comes from the line of Mike Kelly with our Global Hunter. Please proceed..

Hey guys, good morning..

Good morning, Mike..

Hi. I was hoping to get a little bit more color on the subsequent 40 acre test with the 28 stages.

Tony, you’ve said that wells are looking good right now, open to kind of if you could put numbers to that it would be excellent, but how many days do you have on production right now, how many wells are part of this test and is there going to be any higher costs associated with going with 28 stages for C18?.

Hey Mike, that’s a great question. Yes, if I had numbers I have given to you right now, it’s early, we obviously don’t have an IP 30 on those wells yet. So we are probably 7 weeks away from that as we continue to test it, but those wells are actually producing and the early performance is encouraging. So there are four wells involved in the test.

Now we have two 28 stage fracs and two 18 stage fracs that we are looking at in that test pattern. So we will see how that progresses. From the additional cost standpoint we are looking at about $200,000 or so to do the additional frac with the additional stages.

We are using the same amount of fluid and same amount of sand really so the cost is more along the lines of liner itself and this may simulate the time to pump the extra 10 stages if you will. And so about $200,000 or so is going to be directionally in the ballpark and how much more it will cost for us to execute these things..

Okay, so really early stages. I mean in terms of taking it one step further I mean is this – should we think of this now maybe there is a disconnect between how you guys are viewing your results here and what the market expects with the stock off 7% right now and you guys seem encouraged by these results.

I mean with 40 acre spacing do you think ultimately you are going to get to that 458 type 30-day average, which you need to hit your type curve or is this a deal where, hey there is a trade off between tighter spacing and you have to take EUR assumptions down if you are going to go to 48 spacing?.

I might obviously I’m going to say that it’s too early to make that final decision, but what I would say is that what we are aiming at is 20 wells in a section when we have the B, C, and Codell present is kind of our minimum now. And we weren’t there a year ago, right. Now we know that 36 wells a section is feasible we can do that.

The results what we have on the 36 wells on B bench wells if we had nothing else on our inventory would be something we would pursue.

We have seen that the 28 stage fracs by shortening the frac lengths increasing the rubblization near wellbores shows potential to increase the individual well component or the individual well performance of those patterns. So we can move – we are moving from a very good baseline.

Again the 374 is within our expectations, obviously it is below the 460 type curve that we have, but we are starting in a position that those work as is and now can we move forward from there. And I think the 28 stage fracs are giving us the indication and there are signs behind that.

Right, it just makes sense, shorter frac lengths, more rubblization near the actual wellbore itself when you lay those wells close enough together.

They are going to be communicated but you want to get to that happy spot where they don’t over communicate from each other and that’s kind of what the 28 stages will enable us to do, where we maximize the rubblization of the reservoir we will get the right well count seen here.

But again we haven’t over drilled to a point where the wells that we have are non-viable. So it’s not like we are starting at that 40, 20 pad in the situation where the wells just didn’t work and we are trying to move ourselves from that standpoint. These wells, they are workable and now we are looking at optimizing those..

Let me make a quick comment, too, this is Marvin. I would ask you to remember that IPs don’t as many of our technical folks here pointed out IPs don’t necessarily dictate the EURs.

You could have a lower IP with – held with stronger – longer if you will first production, actually changing the type curve due to increased rubblization to where you may hold a higher level overall production rates for a longer period of time and still wind up with the same EUR of the typical type curve..

Got it. Fair point. And just really quick, just industry activity in the basin, what are you seeing as the tightest density test for a single zone.

I believe I thought Noble had potentially 24 Niobrara C wells that looked really good announced with their last conference call, what is – what’s you take on that, what have you seen in terms of the density?.

That is the tightest density, this is Tony again. That was a tightest density that we have seen so far, the 24 wells in the C bench. I think that equated out to about 27 acre spacing or so.

So what I can’t tell you is that exactly how that correlates to our acreage position because I do believe that was a little bit further more into the core of the area.

But we are very encouraged, we are also very encouraged though with the results coming out from Noble to the north would be basically stating with 40 acre spacing in the B bench of given. And that Niobrara bench in the wells ranch area, correlates obviously very well to our acreage position.

So I think Noble is probably leading on taking a testing this tighter downspacing. And I was pleased to hear that they had taken the C bench down to 27 acres. I mean that’s quite a downspace test, so to hear those results are encouraging, was encouraging to me also..

Alright, it sounds good guys. Thanks for the added color..

Alright. So it looks like your next question comes from the line of John Malone with Mizuho Securities. Please proceed..

Yes. Good morning guys.

Just following on Mike’s question, if I understood you said correct, earlier correctly, for the 28 stage you are looking to use the same amount of fluid and proppant as you would for an 18, is that correct?.

That is correct, yes..

What is that, I mean as you see in other plays and other parts of the country you are putting more sand down holes seems to correlate better returns.

Are you just testing this out with the same amount with the possibility increasing later, do you think you will get better returns based on just that, just same fluid, some proppant?.

Well, the concept of our test, the reasons we are going with the same amount of fluid in the sand is we are not looking to increase frac lenghts.

By maintaining the same amount of fluid and sand we are actually trying to reduce the frac lengths and by having more entry points in the lateral and at the wellbore we are filling in those gaps that you have, when you have your stages the frac will extend, but it will leave gaps between the next frac that you do and it will create a unstimulated part of the reservoir.

So that pretty more entry points in there we are getting that rock that’s near the wellbore stimulated and not leaving it unstimulated.

Putting more sand into it as we downspace would probably encourage longer frac lengths and what we are trying to get to is not to have so long, so that we want to stay out of each other’s way to be – to make it simple from that standpoint.

So more rock near wellbore rubblized, the less rock further away from the wellbore rubblize this kind of our intent there, because we are going to have another well coming there and the spacing to go ahead and catch that rubblization, be we will rubblize that part of the reservoir from that well..

You are trying to keeping them from competing with the neighboring wells if you will..

Okay, excellent. That makes sense.

And for the Codell, what’s the next step you can take to determine downspacing potential, given the fact that one of the wells don’t work here, when is the next move you are going to make to try test that downspacing potential again?.

We right now are on our drill schedule it looks like it’s obvious we have another 80 acre space Codell test. So we are looking doing that as and as practical August is our timing to go ahead and get two well drilled that 80 acre based upon..

Okay and obviously that’s distinct from the pressing of these, the one’s who joined on the East are just showed on (indiscernible)..

Yes. That is correct. There are two different tests. The ones to the east are just to test whether or not we can go to thinner and thinner Codell. These well could be actually targeted in our 15,000 acres that we have already proved up in the Codell..

Okay. Thank you..

You bet..

Alright. So it looks like you next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed..

Thanks. Good morning. I guess just want to follow-up a bit more on this 40 acre test.

Just curious, are there any different implications as you looked at the B and C between the two or the – with the B 40 acre space test perhaps more encouraging than the C and might not downspace, C as much or is there any variability between the two reservoirs in that test or?.

That’s a great question, actually, it’s a great question. Actually, we are very encouraged that the Bs and the Cs have performed so similarly, if you will. It really lends towards that when you stack Bs and Cs together they work. I think that’s key learning that we are taking out of this right now.

As obviously we get delineated the B-bench individually and we have delineated C bench individually. But the next question is how do they work when you putting them together. Both Pads have indicated that when you do them together, the Bs and Cs perform pretty much just like each other which is what we had hoped to see.

So that was a great outcome for us. So obviously the 40, 20 pad performed a little lower than the 80, 40 Pad as we had talked about some of the reasoning on that. But still when you compare them inside the Pads to each other the Bs and the Cs are very comparable..

Okay, that’s helpful. Thanks. And then look that has been the other two I guess 40 acre tests you had throughout the acreage block.

Is there any variability East to West, North to South that you are seeing in terms of likely density of drilling or you think it will be can twice it all across the whole acreage frac 1 to dial in the completion?.

I think once we dial in the completion it’s going to be close to one-size fits all. I mean there is always going to be slight variability as you develop your field but at the end of the day, I think it’s going to be pretty close to one-size fits all type development..

Okay. That’s helpful. And then I guess just curious on the outlook around differentials.

Bill you mentioned a $11 to $13 again in second quarter any outlook beyond that should we be or any good reason to think with that comes in just from a infrastructure standpoint things starting up kind of review that?.

Yes, thanks Michael. We are beginning to talk to different folks and hearing folks putting different pipeline capacity into the areas. So that obviously would help us, but certainly in the quarter ahead of $11 to $13 is a good range. Hopefully, that will come in as we see some of these projects coming on. I don’t have any updates beyond that..

Okay. And then last one if I will.

Again on the midstream side of things, just curious on the outlook around line pressures that summer obviously we have upgrades to this system here throughout the late last year and early this year, feeling good about likely outlook on line pressures as we move into the heat of summer?.

Yes, this is Tony. I think we are very in pretty good shape on line pressures. I think the – our midstream partners especially DCP with their systems that they put in place have helped that.

Also with our internal projects we have actually an internal project going on right now and our eastern acreage will help to mitigate line pressures should they climb – normal climb during the heat – heat of the summer. But we definitely don’t see it to be affecting us look at did last year..

Okay, great. I appreciate your time..

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

Yes, good morning guys.

Tony just wanted to understand a little bit more on the 28 stage completion if I am understanding you are still using sleeves there, is that correct?.

Yes. Mike, we are. Those are still sleeves..

Okay.

And some operators have going to plug and perf and slick water to try to maximize the near wellbore rubblization, is that anything you are considering or do you think this is the best alternative for your acreage?.

Mike, that’s great question. Are we considering it, yes. We are looking at that, we don’t have them planned yet. We are still thinking that and its comparable thinking to some other things that obviously other operators near us, Noble being one of them, I am sure they are trying some different techniques, too.

But in general, we think that the gel systems that we use placing the higher concentrations of proppant near wellbore, is still helpful getting up to 4 and 5 pound per gallon proppant placement near wellbore is helpful. Slick-water, typically you can place 1.5 to 2 pound at a maximum.

So, we are still looking at that, but we still think that, that 4 and 5 pound placement near wellbore is helpful getting more of that near wellbore is what the – 28-stage frac will let us do, but I wouldn’t say never, but obviously, the teams are looking at the different options, but we think the 28-stage right now is the best option in front of us.

And again, we are obviously encouraged with the results we have had on the first one that we tried early or at the end of last year with the results coming in earlier this year..

Got it, okay.

And then have you looked at the coiled tubing completions at all? And then that’s another operators talked about that here recently, too?.

I am sorry, Mike, what was the question on quarter and I missed that, Mike, can you repeat that please?.

Yes.

Just another operators actually done a completion here recently with coiled tubing, I wondered if that’s something you guys have looked at all?.

Mike, actually, no, we haven’t. To be honest with you, I have not heard about that typical completion with coiled tubing, so that will be something I’d have to go look at. Mike, obviously, coiled tubing on our clean ethanol, but actually as part of the frac process now we do that in Arkansas, but not up in here..

Okay.

And then just on the Super-Section, just want to get a sense for how the gas and oil split was on those wells? Is that similar to what you are seeing across your areas that I think you are a little bit gassier on this side of your acreage block, do have any numbers that you could put around that?.

They were – when you look at the Super-Section, it was about 75% oil, which is pretty comparable to the wells in that area of the field..

Again, it’s still black oil..

Got it. That’s all for me. Thank you..

Alright. So, it looks like your next question comes from the line of Drew Banker with Morgan Stanley. Please proceed..

Hi, guys.

Just hoping you could talk about if there are any differences you are aware of between what Noble did in Wells Ranch with its downspacing tests, 40 acres versus what you have done either with completions or otherwise?.

Obviously, I’m not privy to all the Noble data, but there is nothing that I am aware of from a completion standpoint, as how we frac the wells and things along that lines that were different. My understanding is they are very comparable.

Now, some of the down-spacing that they have done, obviously they are experimenting even more with down-spacing in the A bench and things along that lines up in Wells Ranch, but of course, I don’t have those results in front of me at this time, but that’s the only significant difference I know.

Actually, the completion techniques that I feel have been very, very comparable..

And so I guess maybe if anything, it’s something to do with the geology?.

Our geology is very similar. Our geology in Wells Ranch and the geology that we have across our acreage we think is very similar. Probably the only different step we have would be in the A bench as I mentioned probably previously, but their A bench is thicker zone up there and a little more perspective from that standpoint.

So, that’s why they have pursued the A bench more, but when you look at the B, C and the Codell, no, our geology is very, very comparable..

And then to go back to the 28-stage completions you mentioned, how quickly can you shift to that 28-stage completion across the board, if you end up deciding that’s the right way to go?.

Between benches, it’s 660 feet, I believe, when you talk, is that correct? Yes, 660 feet on 80s..

Okay.

I guess as you think about the sand kind of or I guess the amount of proppant pumps, I mean what would you need to do or could you see a path to putting more sand in the ground as you continue to test these fracs?.

There is probably always an opportunity possibly to that, but again, we are really trying to minimize the frac lengths, because I think that’s where that the goal of going with these 28 stage fracs again is not putting more sand. We think we can effectively rubblize all the rock near the wellbore with approximately 1,000 pounds per lateral foot.

And then when you put another lateral at 40-acre spacing apart from that and do the same thing it, but you would had most effective rubblization above that rocked over extending into each other sphere of influence, if you will..

Okay..

Other opportunities for more profit, I would say based what we know right now is more profitable maybe applied in places where you be further based apart right now. But we don’t see that because we think 40 acre development would be what we want apply cross our entire acreage position..

Okay. So, you couldn’t get some of that by playing with higher pump rates, just trying to watch out for screen outs? Fair enough. I’ll give you. Go ahead..

No, I would go back to I think again were just trying to maximize of rubblization near wellbore without over extension. And so that’s kind of the concept that we will be pursuing..

Okay, great. And then just more on couple minutes questions just looking at the financials, I know you all guided the higher LOE for the first quarter.

What sort of ramp should we assume to get back closer to guidance by the end of the year or should we assume that the run rate in the first quarter is the run rate for the year?.

I think we said earlier, we should see other come down I think the cold weather and some of the work we did down in Arkansas ramped it up in the first quarter we should see that come down to get into line with our guidance by the end of the year..

Okay, great. I will take that.

And then last one is just, can you give us a current run rate on production or some?.

We are talking about the first quarter, so we don’t we had any updates beyond the first quarter on production at the moment..

Okay, thanks a lot..

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

Good morning, guys. Just recently I know that you have a test planned later this year.

Do you preliminarily see the A-bench as perspective potentially on the Eastern area acreage? Can you give us general thoughts about what 3P locations might look like for that?.

Yes. You bet, David. The A bench part, we have a testing the second half of the year. The A bench consist of a two sections if you will, we have the A chalk section and the A marrel section. The chalk section, as I mentioned before is calcium carbonate rock that’s very clear and marrel section is calcium carbonate rock that has clays in it.

The A marrel sit below the A chalk and so if you look at the A chalk, if the A chalk is the only thing that is actually going to be perspective and you need a certain amount of thickness to make that work. We see that perspective about across about quarter acreage position somewhere in that range.

Mostly on the western side in the northern side close to Wells Ranch where Noble is doing their testing, but if you actually look at the marrel section which is oil bearing and its part of the reservoir and if you augment to then drain the marrell section from A bench and you are actually not draining the A marrell section from the B bench, which sits below the A marrell, then, if you combine those two bench is together at the A chalk and A marrell together.

And it is actually perspective across pretty much our entire acreage position. And so if its perspective across our entire acreage position move its expect with the A bench would be base stimulated to B’s and C’s bench. And then of course it’s only across about quarter it still be spaced pretty much accordingly to the B and C bench tests.

I would say 40 acre down-spacing would be the intent if it is there and this test approves that..

That’s, helpful. I appreciate that..

Another question?.

Yes..

I did want to mentioned to we have none of that in our 3-P right now. So, that is not included in our 3-P analysis that we have provided that includes our 1,800 wells of inventory..

I understood. Next question just there is a lot of variables right now. You guys are testing different completion designs, intermediate lateral lengths, longer lateral lengths, different spacing designs. I think one of the biggest takeaways you will have from these Super-Section was that the stacked development as yielding better results.

Given I guess like at a high level given the aerial extent of the acreage, how quickly do you feel like you need to isolate all of these variables and come to a conclusion before moving to a small T zone pad development versus what you are doing now?.

Yes, it’s a great question. Our intent is to come to those conclusions. A lot of those by the end of 2014, because we would like to build our 2015 program with a majority of these key learnings, so that we can move into 2015 and apply these learnings and move forward. So that’s our intent.

That’s why we are doing the extended-reach laterals to prove that we can do it mechanically. We have got the stacks. We may do some slight adjustments to our 2014 program. As we had mentioned, we would always keep that as an option if we wanted to test possibly now a stacked medium-reach or long-reach lateral tests.

There maybe something we may do before the end of the year. Our teams are looking at that right now, but again the intent is to have us up and running by ‘15 so that we can take this forward and apply it basically across the rest of our acreage.

We designed our ‘14 program to leave ourselves as much blank space, if you will, as possible to go ahead and apply these techniques in ‘15 and forward. So we try to combine these tests into limited areas so that we could then go apply them..

Okay.

Well, say that you feel like I guess even the historical wells that had been drilled, you feel like the design has been such that would still allow you the flexibility to introduce all of these additional concepts or do you feel like there is some acreage that’s already kind of been cannibalized by the way you drilled previous wells?.

Well, I would say obviously we have wells that are out there that are – we can’t go change those. So, we do have the wells out there, but again, we would be coming back in and infilling around a lot of those wells.

I mean, you have one-off and two-off wells out there that we had to drill to delineate that, but that’s not going to prevent us to come back in there and offset those wells in drill in between them and apply these new techniques, because even if I had a four-well 40-acre pad that I tested, I can come back at a certain amount of time and I will be coming back in to drill these remaining B bench wells, C bench wells and the Codell wells in that.

So I would be still able to apply those techniques to all those wells basically vertically if you will, if I have got a kind of a pad out there stacked horizontally across in say a certain bench, but I could stack around that and still apply these techniques..

Sure. Appreciate the answers and good luck..

Thank you..

Alright. So, the next question comes from the line of David Beard with IBERIA. Please proceed..

Hi, good morning everybody..

Good morning..

Maybe we could just move up to the North Park field and I would like to just sort of remind us strategically what you are thinking about that field relative to development. And then specifically, if you could talk about, I think this is originally planned, it being drilled last year.

You had moved it up and I thought it was a vertical test initially and wanted to make sure it still is vertical.

What would you need to see out of that test to move forward to putting more wells down in that basin?.

Well, where we are? We are planning drill of 1 to 2 horizontal wells up there this year. We are moving forward with the permitting on that process right now.

We are going to drill a vertical pilot hole on these wells to extract some key data, probably oil samples, pressure data, those kind of things to confirm that we want to again go ahead and make sure we want to drill the horizontal, but the intent is to drill a horizontal well in the Niobrara.

The area that we are testing up in North Park is a fractured area of the Niobrara. The initial intent is to drill a horizontal in there. And since the rock is so naturally fractured we may not have to do a fractured stimulation on that. That’s the initial thought process. So, we are going to execute that test before the end of the year. That’s our plan.

And from results, obviously, we are just going to have to evaluate the production from the well. We would like to see some oil production, some stable production rates, those kinds of things before we would move actually move up and expand our program in 2015 of any measure..

Okay, great. Thank you..

Alright. So your next question comes from the line of Ryan Oatman with SunTrust. Please proceed..

Hi, good morning..

Good morning..

I am going to try and not ask you about the 28-stage completion and stick with a couple of broader strategy questions here.

Can you discuss the grassroots leasing environment and where you see opportunities within the DJ Basin? Do you feel like kind of on the map that you have in your presentation that there is opportunities there or do you feel like you would need to step either further North or Northeast or perhaps back into the Wattenberg field proper?.

Hi, Ryan, it’s Bill Cassidy. I will take that. And I think we are looking at some of the acreage around where we have our core area to-date. And clearly, some of that acreage just makes sense for to be – for Bonanza Creek to develop that acreage. And we will then stop beyond that and again as much contiguous to where we are today it’s possible.

And we have clearly, our geoscience business development team look across those basins to make sure we are up to speed as to where the B, the C and the Codell are and where there is opportunities, so will continue in that pattern. We do see some opportunities and the area is closest to where acreage will be first and then beyond..

And do you see that being kind of picked up from smaller operators or is there a chance with some of the big brand names out there to pickup acreage, some stuff that they might not be able to get to you in time? Where do you see the most success?.

I think it’s across the map really and when it comes to certainly some of the big guys, they maybe focused up in Wells Ranch. They have a acre here or there and may not makes sense for them to retain that. If we can see that, we will take advantage of it.

And then there are lot of small, mom-and-pop folks that really can’t develop some of the acreage that makes a lot more sense with Bonanza Creek and other operators frankly. I am sure those are out there doing the same thing. So, we will continue to do that.

Marvin, do you have any color for that?.

No, I am just going to say it’s really all the above. You’ve got the small stuff where you are really just tracking on working interest. You could have the mom-and-pop stuff, but where you could pickup 500 or 1,000 acres here or there, there could be some larger plays out there.

So, it could come from larger operators with farm-outs or I mean, there is numerous opportunities available..

Very good.

And then one more on the CEO search if I may, without getting into specifics about the process, can you discuss some of the characteristics and experiences you are looking for in a CEO and kind of how you are thinking about that person fitting in, whether it be from a cultural standpoint or geographical or leadership? However, you are thinking about a new CEO coming in?.

I think the easiest way to answer that is just really to reiterate what I have said recently at various conferences and that’s that we really don’t feel like the company needs another strategic direction, what we need is somebody that can come in and meld with the existing team.

These are the folks that have – had been making it happen and have been here for a while. We don’t want somebody coming in and deciding we want to take off in another direction.

So it’s really trying to find the right person that fits with the existing team that has the best chemistry, good balance of the industry knowledge, and beyond that I don’t really know since I have the – as I pointed before previously I am not actively part of that process. So, that’s where I’d probably have to leave it..

Very good. I will leave it there as well. Thank you..

Operator, I think we have come to the end of our hour. So, we will hand it over to Marvin for closing comments and I apologize for the folks that are still on the call. If you have any further questions, feel free to give myself or Ryan Zorn a call and we’d be happy to answer those questions. Thank you all for your time..

Good. And I want to thank everyone as well for joining us on the call. And before we sign off, I also want to take a moment and offer condolences and deepest sympathies to the people in Arkansas and the families who lost loved ones in the tornadoes that devastated communities outside of Little Rock a few weeks ago. We have some operations in the area.

Thanks goodness that it didn’t affect our properties substantially. Anyway, with that, I would also wish everyone a good weekend. Don’t forget your mom on Sunday and as James said if you have any other questions, I encourage you to call either James or Ryan. Thank you..

Alright, so ladies and gentlemen, that does conclude today’s conference. Thank you all for your participation. You may now disconnect. Everyone have a great day..