Civitas Resources Inc (CIVI) 2014 Q1 法說會逐字稿

Good day ladies and gentlemen and welcome to Q1 2014 Bonanza Creek Energy Incorporated earnings conference call. My name is Chris and I will be your operator for today.

(Operator Instructions)

Would now like to turn the conference over to your host for today, Mr. James Masters, the Investor Relations Manager. Please proceed

Thanks, Chris. Good morning and welcome to Bonanza Creek's 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 marks, Bill Cassidy, our Chief Financial Officer, will report results from the quarter and Tony Buchanan, our Chief Operating Officer, will provide an operations update. Other members of Management are present and will be available at 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 sold on March 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 on track 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 3P 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, and I want to thank our stockholders and 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'm confident that we will say the same for this Company in the years to come.

My confidence in the Company grows every day that I'm 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 an asset base that delivers consistent economic returns in the top-tier of many 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 a permanent CEO is 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 months to six months. The Board is committed to finding the right person to fill the role and as I've said 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 bolt-on acreage acquisitions around our core positions. We added approximately 4,500 net acres in the Wattenberg last year 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. If there's value to be had, we will take advantage of that. If not, than we are content to execute on well over a decade's worth of drilling inventory and wait for a more opportune time. We prise 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 to 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 to 20,000 Boe per day average for the quarter so that you all could 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 estimated having lost approximately 700 Boe per day from the quarter due to the severe weather, but still delivered volumes on time at 19,701 Boe per day. Turning the Super-Section into sales ahead of schedule was a key factor in achieving a successful quarter, so I want to recognize our operation 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 3,000 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. Constant current 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 and transporting our products to market. We are forecasting crude differentials to stay in the $11 to $13 range in the second quarter.

This 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 cost. While operating costs were over plan for the quarter, we reaffirm our annual guidance of between $8 and $8.60 per Boe, expecting unit costs 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've been approximately $16.2 million, or just over $9 per Boe and more importantly, cash G&A would've 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 to Tony to give and operations update and 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 of executing on the plan. As Bill mentioned, their efforts in a very challenging operating environment this winter are to be 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 a 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 de-risked across our 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. 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 gleaned 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 we'll 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 a schematic of the Super-Section. We will discuss each pad as they are labeled in the presentation, pad1, pad 2, and pad 3. Also, as reported in the press release, we had two wells with mechanical difficulties. One Codell well excluded from pad 1 average while one of the 80-acre spaced Niobrara B-bench wells was completed sub-optimally, which had negative impact on pad 3's overall average.

Pad 1 featured stacked 80-acre Niobrara B-benched Codell wells with than offsetting Niobrara C-bench well. It's average IP per well was 448 Boe per day. Unfortunately, due to the mechanical failure in the Codell well, we do not have a full understanding of the potential to down space the Codell beyond 160 acres. Minimal tracer communication, however, between the wells is very encouraging, but 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 that averaged 374 Boe per day. Now, obviously, our B-bench type curve is higher than that, in the 460 Boe per day range. We think this is a pretty good early result.

I would like to point out that the first Codell well had about that same 30-day rate and that subsequent wells have 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 how exceptional the results 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 18-stage fracs. The concept is introducing more entry points along the well bore resulting in increased reservoir contact and less frac extension. We completed 2 80-acre spaced 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 fraced with 18 stages, 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 apply 28-stage fracks on 40-acre spacing. These wells are looking good so far and we look forward to analyzing IP 30 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 the per-well IP 30 average of 516 Boe per day. This is very exciting because it suggests that multi-bench development could materially boost recoveries of oil in place. In fact, while we are only providing pad averages, I should say the results from the C-bench wells in this pad were every bit as good as those from the B-bench. We are now confident that we have derisked the Niobrara B-bench and C-benches across our acreage position and are pursuing full development in both zones.

Now, would like to address the question I'm sure everyone asks, 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 earning more competition for this stimulated reservoir [rye].

As I mentioned, we conducted 18-stage fracs on all the wells on both pads. The 18-stage fracs generate greater extension, but leave gaps of unstimulated reservoir between the fracs. Even though limited sand production and early IP rates indicate that we have not spaced the 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 performance of closer-spaced wells.

So, let me review again our observations that we discussed earlier. First, early data suggest 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, provide increased confidence that this interval is derisked across our entire acreage position. Third, multi-bench stacking arraignments 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. Finally, optimizing our completion techniques is the key to maximizing the ultimate NPV per section and downspacing to 40 acres within an individual Niobrara bench.

As it relates to the rest of the Company's operations, I'll 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 and 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-footer 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 the budget to them in the future.

Also, to wrap the year, we will be drilling a variety of down-spaced and stacked-well pad -- 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 downspacing 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 placed 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'm happy now to turn the call over to the operator for Q&A. When we're finished, Marvin will close with a final comment.

(Operator Instructions).

Brian Corales with Howard Weil.

I'm just going to ask a few on the 40-acre spacing. I guess we're seeing a lot of the same kind of completion techniques done in other plays. One, were you all looking at doing this earlier, before you saw the 40-acre spacing? What was your original expectation for your 40-acre spaced results?

Brian, this is Tony. I will go ahead and take that. I think the first part of your question, were we consider different types of fracs techniques before we actually came into the Super-Section development? As part of that answer is, yes, we are always looking at considering ways of optimizing our frac techniques, more stages, less stages. 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 would probably be more applicable to downspacing because of the reduced frac lengths and 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, fill in the gaps between the fracs. Because if you can envision the 4000-foot lateral with 18 stages, there's going to be gaps of unstimulated rock in between those stages. Having 28 stages now minimizes that. It may not eliminate it totally, but reduces its significantly. So if you can envision of on a lateral with a lot of reservoir rubblized but not so much further from the wellbore contacting to where another well might interfere with that, of you will.

From an expectation standpoint, on 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 are. They are within that range. We are pleased to see that they were actually above the 40-acre test that were in the B-bench by themselves, so indicating that the stacked B and C nature has approved upon that.

That was an encouraging event. We were expecting that to be within our range of expectations. 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 was extremely helpful. Maybe one more if I can. Are you all going to do like the same test, a tightly-spaced, or 40-acre 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 -- the 28-stage frac that we have that we are testing, that had mentioned in my comments, is a 40-acre B. Just, 40-acre B-bench test with a 28-stage frac in that within a 40-acre B offset. So, we have that test going on right now. That is not encompassing a C-bench test with that, currently.

Going forward, we're looking at doing that. We have additional 28-stage fracs planned and we are looking at how to orient those to go ahead and further augment the 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 was very helpful. Thanks, guys.

Irene Haas with Wunderlich Securities.

I might have missed it, because I came a little late. Any progress on the CEO position? Secondarily, understanding that only probably half of your acreage is viable for the traditional Codell, any color on pushing this play eastwards? Have you done much work on this recently?

Irene, this is Tony. I will go ahead and take the Codell question. As we had mentioned, the Codell -- we have it already, basically, delineated on the 15,000 net acres on 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. 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 would 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've 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. Then, once we have that, we'll continue step further east in 2015. To recap, one of the wells has actually been drilled so far. We are in process of that completion. Hopefully, we will have some results, here, as we move into the second half of the year, that we can update you on.

Great.

On the CEO question, I will turn that over to -- I'm sorry, Irene, could you repeat the CEO question that you had?

Yes. The permanent position, is it -- any color on when it might be filled?

This is Marvin. As I mentioned in the opening remarks, we're three months into the process and we thought all along it would most likely take three months to six months. Occasionally, they take longer than that. I've seen them take up to a year. In fact, last time you and I saw each other, that's probably exactly what I'd said at that point.

We're three months into it. I know the board is talking to folks, working through the process. But, that's where we are. There's nothing to update beyond that, at this point.

Okay. Thank you.

Mike Kelly with Global Hunter.

I was hoping to get a little bit more color on the subsequent 40-acre test with the 28 stages. Tony had said that wells are looking good right now. Hoping to kind of -- if you could put numbers to that, it would be excellent. How many days do you have on production right now? How many wells are part of this test? Is there going to be any higher costs associated with going with 28 stages versus the 18?

Mike, this is Tony. Great question. If I had numbers, I'd give them to you right now. It's early. We obviously don't have an IP 30 on those wells, yet. We're several -- probably several weeks away from that, as we continue to test it, but those wells are actually producing. The early performance is encouraging.

So, there's four wells involved in the test. We have two 28-stage fracs and two 18-stage fracs that we are looking at in that test pattern. So, we'll 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 the same amount of sand, really, so the cost is more along the lines of the liner itself. This may simulate the time to pump the extra 10 stages, if you will. About $200,000 or so was going to be directionally in the ballpark on how much more it would cost for us to execute these things.

Okay. Still, really early stages there. In terms of taking it one step further, should we figure 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. With 40-acre spacing, do think, ultimately, you're 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's a trade off between tighter spacing and you have to take EUR assumptions down if we are going to 40-acre spacing?

Mike, obviously, I'm going to say that it's too early to make that final decision. What I would say is that, where I'm at, 20 wells in a section when we have the B, C and Codell present is our minimum, now. We weren't there year ago, right? Now we know that 36 wells a section is feasible. We can do that.

The results that we have on the 36 wells, on the B-bench wells, if we had nothing else in our inventory, would be something we would pursue. We've seen that the 28-stage fracs, by shortening the frac links, increasing the rubblization near wellbores shows potential to increase the individual well component -- 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's below the 460 type curve that we had, but we are starting in a position that those work as is, now can we move forward from there, and I think the 28-stage fracs are giving us the indication and there's science behind that, right? It just makes sense -- shorter frac lengths, more rubblization near the actual wellbore itself when you lay of those wells close enough together.

They're 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 what the 28 stages will enable us to do, where we maximize the rubblization of the reservoir, get the right well count in there. Again, we haven't over drilled to the point where the wells that we have are nonviable. So, it's not like we're starting at that 40/20 pad in a situation where the wells didn't work and we are trying to move ourselves from that standpoint. These wells, they're workable. Now, where looking at optimizing those.

Let me make a quick comment, too. This is Marvin. I'd asked you to remember that IPs don't -- as many of our technical folks here have pointed out, IPs don't necessarily dictate the EURs. You could have a lower IP, that 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 longer period of time and still wind up with the same EUR of the typical type curve.

Got it. Fair point. Real quick, industry activity in the basin, here? 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 looks really good announced with their last conference call. What's your take on that? What have you seen in terms of the density?

That is the tightest density -- this is Tony -- that was the tightest density we have seen so far, the 24 wells in the C-bench. I think that equated out to about a 27-acre spacing or so. So, what I can't tell you is, 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. We're very encouraged.

Were also very encouraged, though, with results coming out from Noble to the north, basically stating that 40-acre spacing in the B-bench is a given. That Niobrara bench in the Wells Ranch area correlates, obviously, very well to our acreage position. I think Noble is probably leading on taking -- testing this tighter downspacing and I was pleased to hear that they had taken the C-bench down to 27 acres. That's quite a downspace test. To hear those results are encouraging, was encouraging to me, also.

Sounds good, guys. Thanks for the added color.

John Lowe with Mizuho Securities.

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

That is correct, yes.

Why is that? In other plays, in other parts of the country where are putting more sand down holes seems to correlate with better returns? Are you testing is out with the same amount with the possibility of increasing later? Do think you can get better returns based on just that, same fluid, same profit?

Well, the concept of our test, the reason we are going with the same amount of fluid and sand, is we're not looking to increase frac lengths. By maintaining the same amount of fluid and sand, we are actually trying to reduce the frac lengths. By having more entry points in the lateral into the wellbore, we're filling in those gaps that you had 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. By putting 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're trying to get to is not have so long, so that the well stay out of each other's way, to make it simple from that standpoint. So, more rock near wellbore rubblized, less rock further away from the wellbore rubblized is our intent there, because we're going to have another well come in there and the spacing could go ahead and catch that rubblization. We'll rubblize that part of the reservoir from that well.

You're trying to keep them from competing with the neighboring wells, if you will.

Okay. Absolutely makes sense. And then for the Codell, what is the step you can take to determine downspacing potential? Given the fact that one of the wells didn't work here, when is the next move you're going to make to try to test that downspacing potential again?

Right now, on our drill schedule, it looks like it's August we have another 80-acre spaced Codell test. We are looking at doing that as soon as practical. August is our timing to go ahead and get two wells drilled that are 80 acres spaced apart.

Obviously that's distinct from the pressing of the east. The one's you are drilling in the east are drilling on this traditional 160 --

That is correct. They 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 wells will be actually targeted in our 15,000 acres that we have already proved up in the Codell.

Thank you.

Michael Hall with Heikkinen Energy Advisors.

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, with the B 40-acre spaced test perhaps more encouraging than the C and you might not down space the C as much? Is there any variability between the two reservoirs in that test?

That's a great question. Actually, that's a great question. Actually, we are very encouraged that the Bs and the Cs have perform so similarly, if you will. It really lends towards that, when you stack Bs and Cs together, they work. I think that's a key learning we are taking out of this right now. Obviously, we had delineated the be delineated the B-bench individually and we had deliniated the C-bench individually. The next question is, how do work when they put 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 hoped to see. That was a great outcome for us. Obviously, the 40/20 pad performed a little lower than the 80/40 pad has 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 were very comparable.

Okay. That's helpful. Thanks. When you look at that test and the other two, I guess 40-acre tests that you have 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? Do think it will be one-size-fits-all across the whole acreage block, once you dial in the completion?

I think once we dial in the completions, it's going to be close to one-size-fits-all. There's going to be slight variabilities as you develop your field, but at the end of the day, I think it's going to be pretty close to a one-size-fits-all type development.

Okay. That's helpful. I could ask -- just curious on the outlook around differentials, Bill. You had mentioned $11 to $13 again in the second quarter. Any the outlook beyond that? Should we be -- any good reason to think that comes in from an infrastructure standpoint, things starting up? Can you review that a little bit?

Thanks, Mike. We are beginning to talk to different folks and hearing folks putting in different pipeline capacity into the area. So, that obviously would help us. Certainly in the quarter ahead of us, $11 to $13 is a good range. Hopefully, that will come in as we see some of these projects coming on. Don't have any updates beyond that.

Okay. Last one, if I will. Again, on the midstream side of things, just curious on the outlook around line pressures this summer. Obviously we have some upgrades to the system here throughout -- late last year and early this year. Feeling good about likely outlook on line pressures, as we move into the heat of summer?

This is Tony, again. Yes. I think we are in pretty good shape on line pressures. Our midstream partners, especially DCP with their systems that they've put in place have helped that. Also, with our internal projects. We have actually an internal project going on right now in our Eastern acreage that will help mitigate line pressures should they climb, normal climb, going to the heat of the summer. But we definitely don't see it to be affecting us like it did last year.

Okay. Great. Appreciate the time.

Mike Scialla with Stifel.

Tony, I wanted to understand a little bit more on the 28-stage completion. If I'm understanding right, you're still using sleeves there, is that correct?

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

Some operators have gone to a plug-in 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 a great question. Are we considering it, yes. We are looking at that. We don't have one planned yet. We are still thinking that -- and it's comparable thinking to the some of the things that other operators near us, Noble being one of them, I'm sure they're trying different techniques, too. 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.

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. 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. Again, we are obviously encouraged with the results we've had on the first one that we tried early -- at the end of last year, with the results coming in earlier this year.

Have you looked at the coiled tubing completions at all? I know other operators talked about that, here, recently, too.

I'm sorry, Mike. What was the question on coiled tube? I missed that, Mike -- can you repeat that, please?

Other 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've not heard about that typical completion with coiled tubing. That would be something I'd have to go look at. Obviously, coiled tubing on our cleanouts and all that. Actually, as part of the frac process, we do that in Arkansas, but not up in here.

Okay. Just on the Super-Section, wanted 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 -- 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?

When you look at the Super-Section, it was about 75% oil, which is pretty comparable to the wells in that area for the field.

Again, it's still black oil.

Got you. That's all for me. Thank you.

Drew Banker with Morgan Stanley.

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've done, either with completions or otherwise.

Obviously, I'm not privy to all the Noble data. That's nothing on aware of from up 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 downspacing that they've done, obviously, they are experimenting even more with down spacing in the A-bench and things along that line in Wells Ranch. Of course, I don't have those results in front of me at this time. That the only significant difference I know. Actually the completion techniques, I feel, have been very, very comparable.

If anything, it's had 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 difference at we have would be in the A-bench, as I mentioned, probably previously. Their A-bench is a thicker zone up there, a little more perspective from that standpoint. That's why they have pursued the A-bench more. When you look at the B/C in the Codell, no, our geology is very, very comparable.

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?

We could shift very quickly. Really, the only significant change is being able to get the liners, themselves, the 18-stage going to the 28-stage, but that is something we can do very quickly.

Thanks. That's all for me.

Andrew Coleman with Raymond James.

Can you just refresh my memory with what the inter-well spacing is on the 80s and the 40s? Is it 700 feet? Am I calculating that right on the B-bench 80-acre test?

Between benches, it's 660 feet, I believe, when you talk it on. Is that correct? 660 feet on 80s.

Okay. Cool. (Multiple speakers) As you think about the sand -- or the amount of prop and pumps, what would you need to do? Could you see at path to putting more sand in the ground as you test these fracs?

There's probably always an opportunity, possibly, to do that. Again, we're really trying to minimize the frac lengths because I think that's where -- the goal of going with these 280-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. Then when you put another lateral at 40-acre spacing apart from that, and do the same thing to it, that you would have the most affect of rubblization of all that rock without overextending into each other's sphere of influence, if you will.

Okay.

Are there opportunities for more proppant? I would probably say, based on what we know right now, more proppant may be applied in places where you'd be further spaced apart right now, but we don't see that because we think 40-acre development would be what we want to apply across our entire acreage position.

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 would go back to -- I think, again, we are just trying to maximize the rubblization near wellbore without overextension. That's the concept that we are pursuing.

Okay. Great. A couple minutia 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 stated earlier we should see LOE come down. I think the cold weather and some of the work we did down in Arkansas ramped it up in the first quarter and 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. The last one is, can you give us a current run rate on production? Or some (technical difficulty).

No. We are talking about the first quarter, so we don't really have any updates beyond the first-quarter production at the moment.

Okay. Thanks a lot.

David Deckelbaum with KeyBanc.

Something -- you mentioned the A-bench 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 consists of two sections, if you will. We have the A-chalk section and the A-[marrell] section. The chalk section, as I've mentioned before as calcium carbonate rock that's very clean. The marrell section is calcium carbonate rock that has clays in it.

The A-marrell sits below the A-chalk. 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 as perspective across about a quarter of our acreage position, somewhere in that range, mostly on the Western side and the Northern side, closer to Wells Ranch where Noble is doing their question. If you look at the marrell section, which is oil bearing and it's part of the reservoir, and if you are to then drain the marrell section from the A-bench and you're actually not draining the A-marrell section from the B-bench, which sits below that A-marrell, then, if you combine those two benches together, the A-chalk and the A-marrell together, it's actually prospective across pretty much our entire acreage position.

If it's perspective across our entire acreage position, we would suspect that the A-bench would be spaced similarly to the Bs and C-benches. And then of course, if it's only across about a quarter, it would still be spaced pretty much accordingly to the B- and C-bench tests. I would say 40-acre downspacing would be the intent ff it is there and this test proves that out.

That's helpful. I appreciate that. (Multiple speakers)

I did want to mention, too, we have none of that and our 3P right now. It's not included in that 3P analysis we have provided that includes our 1,800 wells of inventory.

Understood. Next question, there's a lot of variables right now that you guys are testing. Different completion designs, intermediate lateral lengths, longer lateral lengths, different spacing designs. One of the biggest take-aways that you all had from these -- from the Super-Section was that the stacked development is yielding better results. Given 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?

That'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 the majority of these key learnings so we can move into 2015 and apply these learnings and move forward. So, that's our intent. That's why we're doing the extended reach laterals, to prove that we can do them mechanically. We've got the stacks.

We may do some slight adjustments to our 2014 program, as we had mentioned. We'd always keep that as an option if we wanted to test, possibly, now a stacked medium-reach our long-reach lateral test. There may be 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 2015 so that we can take us forward and apply it basically across the rest of our acreage. We designed our 2014 program to leave ourselves as much blank space, if you will, as possible, to go ahead and apply these techniques in 2015 and forward. So, we try to combine these tests into limited areas so we can then go apply them.

Say that you feel like -- 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 feel like there's some acreage that's already been cannibalized by the way you drilled previous wells?

Well, I would say that obviously we have wells that are out there. We can't go change those. We do have the wells out there. But, again, we would be coming back in and in-filling around a lot of those wells. 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 and drill in between them and apply these new techniques. Even if I had of 4-well, 40-acre pad that I tested, I can come back at a certain amount of time and I'll be coming back in to drill the remaining B-bench wells, C-Bench wells and the Codell wells in that. So I would be apply those techniques to all those wells, basically, vertically, if you will, if I've got a pad out there stacked horizontally across a certain bench, I could stack around that and still apply these techniques.

Appreciate the answers and good luck.

David Beard with Iberia.

Maybe we could just move up to the North Park field and I'd like to remind us strategically what you're thinking about that field, relative to development. Specifically, if you could talk about, I think, this is originally planned, it being drilled last year. You'd 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 put in more wells down in that basin?

Well, where we are -- we are planning to drill one to two horizontal wells up there this year. We are moving forward with the permitting on the 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 then to go ahead and make sure we want to drill the horizontal well. The intent is to drill a horizontal well in the Niobrara.

The area that we are testing 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 fracture stimulation on that. That the initial thought process. So, we are going to execute that test before the end of the year. That's our plan.

From a results, obviously, we are going to have to evaluate the production from the well. We'd like to see some oil production, some stable production rates, those kind of things, before we'd, obviously, move out and expand our program in 2015 of any measure.

Okay. Great. Thank you.

Ryan Oatman with SunTrust.

I'm going to try to not ask you about the 28-stage completion and stick with a couple broader strategy questions, here. Can you discuss the grassroots leasing environment and where you see opportunities within the DJ basin? Do you feel like on the map that you have in your presentation, that there's 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?

Ryan, it's Bill Cassidy. I'll take that. I think we are looking at some of the acreage around where we have our core area to date. Clearly, some of that acreage just makes sense to it be -- for Bonanza Creek to develop that acreage. We will then step beyond that and, again, as much contiguous to where we are today as possible. We have clearly -- our geoscience business development team look across the whole basin to make sure we're up to speed as to where the B, the C, and the Codell are and where there is opportunities, so we will continue in that pattern. We do see some opportunities in the areas closest to our acreage will be first and then beyond.

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

I think it's across the map, really, when it comes to that. Certainly, some of the big guys, they may be focused up in Wells Ranch. They may have an acre here and there and may not make sense for them to retain that. If we can see that, will take advantage of it. There are a 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'm sure there's others out there doing the same thing. We'll continue to do that. Marvin, do you have any other comments on that?

No. I'm just going to say, it's really all the above. You've the small stuff where it you are really just tacking on working interest. You could have the mom-and-pop stuff where you could pick up 500 or 1,000 acres here or there. Or there could be some larger plays out there. It could come from larger operators with farm outs. There's numerous opportunities available.

Very good. 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 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 said recently at various conferences. 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 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 industry knowledge. Beyond that, I don't really know, since I have, as I pointed out before, previously, I'm not actively part of that process. So, that's where I probably have to leave it.

Very good. I'll leave it there, as well. Thank you.

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

Good. I want to thank everyone, as well, for joining us on the call. 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. You know, we have some operations in the area. Thank 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. As James said, if you have any other questions, I encourage you to call either James or Ryan. Thank you.

All right. 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.