Civitas Resources Inc (CIVI) 2015 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Bonanza Creek Energy third-quarter earnings and operations update. At this time all participants are in a listen-only mode. (Operator Instructions). As a reminder, this conference is being recorded. I will now turn the call over to your host, James Edwards. You may begin.

Thank you, Stephanie. Good morning, everyone, and welcome to Bonanza Creek's third-quarter 2015 earnings call and webcast. Joining me this morning on the call are Richard Carty, President and Chief Executive Officer; Bill Cassidy, our Chief Financial Officer; and Tony Buchanan, our Chief Operating Officer.

Yesterday evening we issued our earnings release and filed our 10-Q with the SEC, both of which are accessible on our website. If you haven't done so already, I would encourage you to visit the website at www.bonanzacrk.com, to access the slides that we will reference this morning during our prepared remarks. Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-K and other SEC filings.

Also during this call we will refer to non-GAAP financial measures because we believe they are good metric to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release. As usual, we have endeavored to keep the prepared remarks short to leave ample time for Q&A during this 60-minute call. Once again, if you would like to reference the IR slides, please find the updated deck at our website.

Now it's my pleasure this morning to introduce Rich Carty, Bonanza Creek's President and Chief Executive Officer, who will start the call by providing a brief overview of the third-quarter results and Midstream (technical difficulty). Rich?

Thanks, James. For those of you who have not yet met James, he recently joined us from SM Energy to run our Investor Relations effort, and we welcome him to the Bonanza Creek team.

Good morning, everyone, and thank you for making time to join our call today. We are pleased to announce a very good third quarter, which is the culmination of many months of efforts at the Company with all the arrows headed in the right direction and meaningfully so. Bonanza Creek is demonstrating our sustainability and resilience, with ongoing successes in our continuous improvement programs throughout the Company.

In operations, production execution was solid and above guidance, and our dedication to increasing capital efficiencies, productivity yields and operating expense reductions showed real traction in Q3 with meaningful, sequential reductions in cash operating costs and accelerating approvals in field wide efficiencies. Improved completions designs, commendable reductions in spud-to-rig-release time, and systematic declines in gathering system pressures each contributed.

Similarly, our balance sheet and liquidity have also materially improved, with a very successful $475 million bank redetermination process in October, complemented by the recently announced $255 million monetization of our Rocky Mountain Infrastructure business, which represents over $5 per share in value realization. This RMI divestiture has the effect of both significantly increasing our liquidity and, at the same time, reducing our capital intensity in 2016 and 2017 by minimizing infrastructure investment and field development. The RMI event represents an important third-party validation of our shareholder value creation strategy at the Company.

Given that we have a very full Q3 report to discuss with you today, allow me to quickly set the stage and provide some key highlights about the quarter before I turn the call over to Bill and Tony to go into details. For the quarter, sales volumes were up 4% quarter over quarter to 29,000 BOE a day, ahead of expectations and an all-time Company record. Adjusted EBITDAX of $73 million and adjusted net loss of $0.07 per share were also ahead of expectations.

Total cash costs of $14 per BOE were down 16% quarter over quarter. Adjusted cash G&A was down 25% quarter over quarter. Capital costs incurred were down 46% quarter over quarter. Also, well tests with larger completions showed a 20% uplift in cumulative production rates. Standard-reach lateral well costs were down 15% quarter over quarter pro forma for the RMI closing. And our liquidity as of September 30 of $419 million, which is expected to be further bolstered by the $175 million at the closing of the RMI transaction.

I want to congratulate the team at Bonanza Creek for a job well done, both in driving efficiencies and continuing to adapt and make us a more competitive company in these challenging times. In Q1 and Q2 this year we accelerated capital spending on our RMI business. And now in Q3, only two quarters later, we can see the value we have created for shareholders in so doing. This is a tremendous success for our team. After Bill and Tony finish their comments, I will come back to discuss the proposed transaction for our RMI business.

Bill, over to you.

Thanks, Rich, and good morning, everyone. I will start my remarks on slide 4. I will start by saying we had a solid third quarter, with production volumes up and a significant sequential decrease in cash operating costs on a per-unit basis over the prior period. We are reporting companywide sales volumes of 29,000 barrels of oil equivalent per day during the quarter, which is 5% greater than 3-stream equivalent volumes of a year ago. Despite our volume growth, unhedged revenues declined from $156 million to $72 million for the same period. As Rich mentioned, the Company generated $73 million in adjusted EBITDAX versus $110 million for the same period in 2014, representing a decline of 33% year-over-year despite a 60% decrease in realized pricing during the same period.

I would like to quickly go through our production guidance for the remainder of the year. As Tony will cover in a minute, we have seen a big improvement in rig efficiencies this year, which has led us to be ahead of schedule in our spud count for the year. To stay within our budgeted activity count, we have elected to drop one of our operated rigs and currently have one rig running. Due to this operational change, some of our fourth quarter completions will be moved back further in the quarter, resulting in a slightly lower 4Q and full-year production guide.

During the third quarter, we saw a significant decrease in capital costs incurred, which decreased our second-quarter capital costs incurred of $164 million by $76 million to a third-quarter capital cost incurred of just $88 million. Total Company costs incurred for the nine months of the year are $375 million, putting us on track to meet our full-your guidance range of $420 million at the midpoint. Within the year-to-date capital incurred, $44 million is associated with assets that now reside in our Rocky Mountain Infrastructure subsidiary that is to be divested. The remainder of the year-to-date capital costs incurred are split as follows: $271 million for Rocky mountain Upstream, which is comprised of drilling and completion capital and well site equipment such as separators and meters; $44 million for Mid-Continent; $16 million for land; and $1 million for corporate and other.

On basis differential we see positive developments within the Wattenberg Field, with oil differentials moving from $9.22 per barrel in Q2 to $8.98 per barrel in Q3. This is the lowest differential to WTI that we have seen since the third quarter of 2013. Spot market crude differentials continue to compress in the Rockies and, when blended with our fixed differential on volumes that we ship on the Pony Express Pipeline, our Q4 differential is likely to be less than $4 off WTI. On the gas side, we continue to see our realizations track closely to CIG pricing. But at these low prices, revenue deducts we have related to gathering and processing have a more pronounced impact. We would expect to see residue gas realizations that are 30% to 35% off Henry Hub for the fourth quarter.

In the Mid-Continent, our differentials were generally in line with expectations overall. Relative to previous quarters, our realized oil prices ran a bit tighter to WTI but our NGL differentials as a percentage of WTI reached their widest level this year.

Moving now to production taxes, you probably noticed a lower than expected number in our production tax line item. This was the result of a refund from the state of Colorado, which I believe that we mentioned was forthcoming on our last call. Going forward, I believe you should model 6% pre-derivative revenue on a corporate basis.

Turning to G&A, we recorded unit cash G&A costs of $5.05 per BOE after adjusting for $1.2 million in severance costs related to a staff reorganization that occurred in late September. The reorganization was designed to better align our workforce with current activity levels and to eliminate contractors whose duties could be absorbed by full-time Bonanza Creek employees. As a result of this alignment, our employee base was reduced by approximately 15%. Given our year-to-date unit cash G&A of $5.74 per BOE, which excludes third-quarter severance charges, we have elected to revise lower the top end of our annual unit cash G&A guidance from $6.25 to $6 per BOE.

Before I turn the call to Tony, I would like to summarize the results of our fall borrowing base redetermination, completed on October 19. We received unanimous support from our 10-member bank group for an approved borrowing base and committed capital of $475 million. We believe this borrowing base, coupled with the anticipated proceeds from our RMI transaction, gives the Company ample flexibility to navigate the current macro environment and a range of contemplated activity levels in 2016.

I will now hand the call over to Tony, to go through the operational update.

Thanks, Bill, and good morning, everyone. I want to start by reiterating the strong quarter we had. As Bill mentioned earlier, our total production was 29,000 BOE per day, beating our quarterly guidance. In the DJ, our daily production volumes grew by approximately 1,000 BOE per day or 4% from second quarter to 23,700 VOE per day. Solid operational execution, along with significantly improved midstream performance, helped drive this result.

In our Mid-Continent region, production was 5,300 BOE per day, flat to second quarter but about 300 BOE per day above expectations as a good run of recompletions offset field decline. Field efficiencies across our operation are beginning to take deep root and are resulting in improved production and cost performance. Our operational staff has worked very hard this year to safely reduce costs where we can and enhance field performance. I am happy to report that we have been successful on both ends of the equation, maintaining Bonanza Creek as a leading operator in the Basin.

With regard to some of the performance enhancements we have realized in the field, slide 5 shows test results we have on increased sand loading in wells that we drilled in the third quarter of last year on our Eastern acreage. Typically, we have been using about 1,000 pounds of sand per lateral foot for our wells. But in this particular test, we completed the wells with 50% more sand or 1,500 pounds per lateral foot. As you can see in the slide, over the past 10 months the wells have exhibited a significant increase in cumulative production over that time frame when compared to similar wells fracked with typical sand loadings nearby.

While we haven't estimated an EUR uplift for these test wells, we have noted that the well payback periods have been cut in half just from the accelerated production the wells exhibit, assuming no EUR uplift. Reducing payback periods is critical to maintaining the strength of our balance sheet in times of depressed commodity price. So as we look to 2016, our program, we contemplate a large portion of it to include these larger fracs.

Moving on to slide 6, we highlight some of the effects we have seen from improved infrastructure. In the Wattenberg, we faced fewer unplanned instances of midstream downtime due to additional infrastructure that was commissioned toward the end of the second quarter, eliminating many of the infrastructure bottlenecks we had experienced in the past. As you can see on the slide, the measured volatility in production profile was reduced by approximately 50% as these additional gas takeaway routes came online. Lower volatility, of course, begets greater forward visibility and lower inherent risk in our production profiles.

Next I will go through some of the cost-saving measures we have realized. With regard to LOE, our performance for the quarter was better than planned by $1.6 million. Roughly two-thirds of the variance was captured by Mid-Continent, as the benefits of our gas plant optimization were realized for the entire quarter. In addition, our supply chain organization has been hard at work with a main focus on further improving the efficiencies we have realized across a number of LOE categories, such as compression, chemicals, water disposal and contract labor. These initiatives have resulted in a year-to-date LOE in the lower end of our guidance at $7.85 per BOE. We have elected to bring down the midpoint of our annual unit LOE guidance range to a midpoint of $7.87.

Moving on to capital investment, we have made significant strides in completed well costs this year. On slide 7, the waterfall graph shows the downward trajectories related to well costs we have realized so far this year, as well as additional savings we expect to realize over the next few quarters. I think it is important to note that the remainder of the expected future well cost savings are independent of service cost deflation. SRL wells in the third quarter were drilled, completed and tied into sales for $3.3 million to $3.4 million, while XRL well costs dropped to approximately $5.1 million.

Given the comments we hear from neighboring operators and non-operated AFEs that are proposed to us, we believe we continue to be very competitive, if not slightly ahead of the curve, in drilling our operated wells for the lowest cost possible. A point I want to emphasize is that achieving our target well costs will return us back to early 2014 payback levels even in this price environment. All lines of service continue to see downward pressure on costs. But our rig fleet in 2015 has really shined in terms of the ability to execute our schedules well ahead of plan.

Moving on to slide 8, you can see our drill times from the beginning of the year have dropped by 25% for SRLs and an impressive 40% for XRLs. Due to this decrease in spud to rig release times, we were able to get ahead of schedule on our spud count for 2015. As we are not inclined to increase activity this year given the pricing environment, we made the decision to release one of our rigs and remain on target to spud the same number of wells as budgeted, but now with a lower rig count.

With that, I will turn the call back over to Rich to talk through the RMI transaction.

Thank you, Tony. As most of you know, we have long held the belief that our contiguous leasehold, which spans approximately 70,000 net acres in the heart of the Wattenberg oil window, represented a unique opportunity for a multifaceted midstream buildout that would help us facilitate a pad style industrial-scale development of our captured resource. Bonanza Creek began this infrastructure buildout with the construction of field-level gas gathering and compression facilities on our legacy Western acreage in 2014. We also built out our first central production facility, CPF, in 2014, a centralized liquids handling and gas lift infrastructure for 15 original wells located on our super section.

Today, that same facility is the facility's destination hubs for 40 wells. Our buildout continued this year as we completed field-level gas gathering and compression for our Eastern legacy acreage. And, as of today, we have a total of four CPFs in operation. Our purpose in doing this work was simple: provide optimal service conditions for our reservoirs to produce while reducing our footprint on the surface via fewer physical facilities and reduced, if not wholly eliminated, liquids hauling by truck in the field.

We were successful in building the formative components of the infrastructure backbone that will service our upstream assets for years to come. Today, we are excited to announce that we have signed a purchase agreement with Meritage Midstream to sell our RMI business. On slide 9, we have listed the main terms of the transaction, which has a purchase price of up to $255 million. Of the $255 million, $175 million is payable upon closing, which is expected by the end of the year, and the remainder consists of deferred payments predicated on reaching drilling and completion milestones.

We expect that this monetization and its associated proceeds will allow us to enter 2016 with an undrawn credit facility and projected liquidity of almost $600 million. In addition, this transaction helps to add clarity on what you can assume for a minimum level of activity in 2016 and 2017, given the drilling incentive fees that would be payable to Bonanza Creek provided that we meet those threshold activity levels.

Importantly, we believe that the proceeds resulting from this transaction will allow the Company to stay undrawn on its credit facility into 2017. While the financial impacts of this transaction are transformative and deserve significant attention, we are equally as excited about our new partnership with the team at Meritage. Our respective companies identify each other 15 months ago as potential partners as we contemplated different paths in accelerating and optimizing our infrastructure needs.

We have developed the utmost confidence in the Meritage team and the Riverstone private equity group, their demonstrated abilities to construct and operate facilities for gas, oil and water, their approach to customer service, and their ambition for future asset build out in the DJ Basin.

Thank you again for spending part of your morning with us. We are pleased with the progress that our entire enterprise has made during the third quarter relative to not just our own expectations but those of the analyst community as well. The anticipated sale of RMI is the culmination of efforts made by many in positioning the Company to attract such a highly qualified acquirer and future midstream partner.

With that, let's hand the call back to the operator for Q&A.

(Operator Instructions). Irene Haas, Wunderlich.

Congratulations on this asset sale. And my question is, do you have any other assets in your back pocket that you might think about divesting, or this is good for the time being?

As you may have seen, we put our Mid-Continent assets as assets held for sale. We received some bids over the -- or some interest over the quarter (technical difficulty) into the held for sale. We've engaged someone to take a look at that and we will see how that progresses. But clearly, we are not in any hurry to move forward with anything unless we have a really attractive deal.

So I think that would be one of the other things that we would talk about as we go through comments. Day in, day out, generally 99% of them are regarding the Wattenberg Field and not a lot of focus is put on our really high-quality Mid-Continent assets. So I think that would be the one that we would say is another lever we could pull from a liquidity perspective, if needs be, in the future.

That's great, thank you.

Phillips Johnston, Capital One.

Thanks and congrats. Just to follow up on Irene's question, in the past I think you've talked about the possibility of pursuing a joint venture on your northern acreage to potentially bring cash in the door and help derisk that acreage. Does the RMI sale now change your thoughts or your appetite for a deal like that?

I don't believe we have ever made any comments, actually, in the public domain about JV'ing any of our acreage. Of course, it's always something we could consider down the road, but we've never conveyed that or represented that as a likely path forward. So I wouldn't steer you that way.

Okay. And just regarding your plans in the North, what's contemplated now that you've got cash in the door? In the past, you've talked about drilling an eight-well pad on the North at some point next year. I think that was dependent on what happened with RMI, but I just wanted to get an update on that.

That actually really does help us out. The RMI agreement and with Meritage now stepping in -- the key limiting factor to us was actually having a central production facility in that area for us to hub off of, if you will. So our plans -- 2016 again, we haven't officially come through with our budget yet, but that has really enhanced the opportunity for us to go out there. They will build us a CPF on the northern acreage and we are planning to drill that seven- to eight-well extended reach lateral pad next to that CPF. So that would definitely enable us to move that way, and we are excited about doing it.

Great. Thanks, guys.

Neal Dingmann with SunTrust.

Say, Rich, it looks like on the completion optimization you all continue to have success. You really highlighted about the sand enhancements. Just your thoughts about going to more plug-and-perfs, doing more just extended laterals. Is that across the board? Is this just something that will become more commonplace in most of these wells going forward, as you mentioned? The sand enhancements would be in the majority?

Yes. Listen, we are pretty confident that we are in very early stages in this field for increasing productivity and having this reservoir continue to improve on a regular basis. I'll pass over the questions on the specific designs for next year to Tony. But clearly, very small investments in capital are providing very large increases in productivity, which is the number-one contribution variable to increasing the asset value over time. Tony, do you want to speak specifically about that?

Yes, you bet. Again, in this lower-price environment, just return of capital and well payback times is really paramount to us. So, the increased sand volumes and the results we've gotten from the 1,500 pounds per lateral foot has demonstrated that we can provide that for us. So you will see us using that in a majority of our program in 2016. As for plug-and-perf, we have talked about we have a three-well extended reach lateral pad, a plug-and-perf that is currently producing on flowback right now. We are looking at the results of those wells, comparing those to five wells that were extended reach laterals that were completed with our standard sliding sleeve technique in the same section to minimize the geological variabilities and really, truly compare the plug-and-perf and sliding sleeve techniques. So we are looking at that.

Obviously, if we see plug-and-perf continuing to provide or providing benefit for us, we would consider that if the economics makes sense. As you know, plug-and-perfs cost a little bit more than the sliding sleeves. Our sliding sleeve wells are coming in between $5 million and $5.1 million today and our plug-and-perf wells were at about $5.7 million. So there is a cost factor to that. So we will keep that in consideration, but we are looking at all that for 2016.

Okay. And then just my follow-up, Rich. Just as far as when you look at the plan and budget for next year, again, how sensitive to the -- obviously, the commodities continue to be quite volatile. Is it -- would you let that rig go? Would you add a second rig? How is this tied into the commodity price, or is it more just about what you want to achieve on the plan? And then my follow-up on that is, including going a little bit further north and maybe doing a bit more expiration up there?

Neal, we haven't completed our 2016 budget yet, but I think you can rest assured by today's numbers that we run a very low cash cost business; it's a highly efficient asset. We have a very competitive organization. And so, we are in a good position to weather the storm. And we have been demonstrating our resilience and sustainability as an organization in this environment. So we want -- our objectives are not around increasing production. We will be very clear about that. Our objectives these days are around creating value for stockholders, and we hope that today's demonstration with RMI is a case in point.

For activity levels next year, the RMI transaction does encourage us to produce 56 wells, drill 56 standard reach wells. So that would be a lower threshold for us. And then the upper threshold will be determined around the economics of accelerating activity. So you can think of it that way, but we've really lowered substantially the amount of maintenance CapEx in this business by the RMI transaction.

With 2016 and 2017, there are significant well-level incentives for drilling. And our balance sheet has been really substantiated in the past 60 days or so. So we are in a really good position to accelerate when the time provides and otherwise continue to build stockholders in a down environment, otherwise.

I agree, Rich. I get it; flexibility is obviously much better and continues to improve. Would that enable you to maybe try to go up north a little bit and start to delineate that a little bit more? Or is that just, as you mentioned, you are waiting on the plan to decide how you want to tackle that in addition to the core?

Right now we are highly confident that we have a large number of locations for many, many, many years. We'll be developing this field for probably longer than I will be in this business. But ultimately we have -- our focus is on capital productivity. And so, we are going to drill wells that have the highest marginal impact to our stockholders for recycled rates on cash, paybacks on cash. And those are not likely to be ones that require a huge amount of risk or infrastructure association with developing those. That wouldn't be included in the RMI transaction.

So we are staying close to home. We are [doing] highly predictable work on the operations side. We're going to continue to push wellbore productivities up, and continue to try to lock in capital costs that have been declining to where they are today.

I'd like to just comment on the northern acreage again. We have several wells up there already giving us confidence in the northern acreage. And so, we have a lot of running room on the northern acreage right now with what we have, without having to do a lot of further delineation. So, those pads and things that we're targeting for 2016, we feel very confident in where we are drilling and we have running room up there. So I just wanted to make sure that I was clear on that.

No, that's a great add. Thanks, Tony. And thanks for the comments, Rich.

Welles Fitzpatrick, Johnson Rice.

Congrats on what looks to be a great transaction. Is there any prescribed location for the 112 SRLs over the next two years?

Yes. Well, the 112 wells will be targeted around the four existing central processing facilities that we have for CPS that are located, right now, on our legacy position. And the two new CPFs will be constructed by Meritage, one on the northern acreage, as we talked about, that will be the hub for our extended reach laterals; and one additional on the southern legacy position. Again, these 56 wells are standard-reach lateral equivalents. I want to be clear on that. So we can mix in extended-reach laterals and all those kind of things. So it doesn't limit us at all on our well selection. So again, we will be targeting those wells around those four existing CPFs and the two new ones.

Okay, perfect. And the equivalency -- that's calculated just on a simple lateral ratio, I guess?

Yes. Typically, Welles, what you can look at is an extended-reach lateral will count as two, a medium-reach lateral will count as one and a half, and a standard-reach lateral will count as one.

Okay, perfect. And then any update on the mono-bores that you all have done? Does the $2.4 million in 2016 -- or the stretch go a little bit lower than that? Does that include that new technique?

If you look at us, we are at the $3.1 million or $3 million for a standard-reach lateral. When you factor in the incentive that we will receive, that takes you down to the $2.4 million, $2.5 million range for our standard-reach lateral equivalent wells. The mono-bore would then take you further down than that to the $2.1 million to $2.2 million range. The mono-bore and then adjusting our fracs with a little bit more slickwater -- we still do the hybrid fracs, but going with a much more slickwater portion in that hybrid frac.

So the mono-bores, where we are, we have done one internally already but we feel our confidence level is very high to proceed into 2016 and do more mono-bores. We're looking at that right now, but wouldn't be surprised that our initial wells going into 2016 would use the mono-bore technique right out of the gate.

That's great, thank you.

Ipsit Mohanty, GMP.

Congrats on getting the deal done. Did I hear you right? The $20 million deferred payment is based on 56 wells, irrespective of the lateral length?

The $20 million is in two installments. So you should look at -- as Tony said, it's a standard-reach lateral equivalent. So if we have an extended-reach lateral that would count as two Standard reach laterals. So that $20 million is in two installments. One would be on the completion of 40 wells. That payment will be made at the end of the year 2016. And the second payment will be made on achieving 56 wells drilled. Again, that payment should be made, given 56 as a base level, should be made by the end of 2016 as well. And that would (multiple speakers) full $20 million.

And given that you decided to drop a rig, preferably after this deal, tells me that those 56 wells should be your primary target or primary goal for 2016 on a one rig program?

That's correct. I think that's a correct assumption.

Okay. And then --.

And just on the dropping the rig, I think we have been very consistent throughout the year that we had an activity-based budget. And given Tony and the team on the operations side, and their ability to get these wells drilled in a lower time frame, we effectively dropped the second rig because we just got ahead of ourselves on the drilling side.

So that doesn't necessarily translate into -- I know you haven't given us 2016, necessarily, but I'm curious. What does it take for you, now that you are flush with liquidity, your balance sheet, your debt ratios have drawn back, what does it take to add a rig in 2016? Back to two?

Look, I think it gets to some of Rich's comments earlier. It's the commodity price environment, it's retaining a strong balance sheet. And obviously with an eye to what we are doing on the RMI side to make sure we achieve that 56. You could see that as lower boundary. I think one rig active for the full year should drill at least 56 wells. And we will then look to where the market is, look to where the environment is as to whether we would add another rig. But I think we have been very consistent on balance sheet.

We realize we have a very strong asset, we have a lot of wells to drill. However, if we don't have a strong balance sheet we are never going to get to these wells. So, we are going to be consistently looking at the balance sheet into 2016 and beyond.

And my last -- I think quite a few have been already touched. But when I look at that reduction from $2.4 million to $2.1 million, and especially on the completion side, are you depending much on even third-party -- sorry, are you depending on third-party even more? Or are these more organic enhancements?

Ipsit, those are going to be organic enhancements. Again, the $2.4 million to the $2.1 million comes in two pieces. The drilling side is going to the mono-bore drilling, which eliminates that intermediate string of casing; that's the biggest piece of the savings there. So that's obviously organic.

And then the other pieces on the frac design. We used a hybrid design, which is a slickwater up front, tailed in with gelled fluid system to carry the sand concentrations that we need. Enhancing that design, really increasing the portion of slickwater in that design and decreasing the portion of the gel system in that design. So that's probably, if anything is more -- I don't want to call it a wildcard. But that's the one we haven't done yet. The mono-bore we have, and that has been demonstrated.

Obviously, other folks in the basin are having really some successes. We are hearing, obviously, just going with total slickwater. So we feel pretty good about increasing the slickwater content and reducing the gel system side of the frac. But we haven't done that one yet. So that little piece on slide 7, if you look at it, would probably be the one that -- we just need to work on that. Because what we don't want to do is jeopardize the EURs of the wells. So that $2.4 million down to $2.1 million -- I think the mono-bore is pretty solid, and then you've got that other piece we need to work on.

Okay, Tony. And no issues in translating that upside frac job from an SRL to an XRL?

I'm sorry, Ipsit. Could you repeat that question, please?

Do you have any issues in translating that upsize frac jobs from an SRL to an XRL, from standard to extended?

No, absolutely not. You can go with the 1,500 pounds per lateral foot in an XRL with no problem. So it is easily translatable.

Thank you, guys. Good show.

Ryan Oatman, Cowen.

I think you guys have been fairly consistent about what is a good level for us to think about in terms of at least the minimum for capital spending next year. When I think about that program, I wanted to see, given the efficiency gains that you guys are talking about and the costs that have shifted to RMI, wanted to see what a good production outlook was for us. Is that a mid-single-digit decline? Just any sort of color you can provide there.

At this point we haven't substantiated and finished our budget planning for 2016. So we are not really prepared to talk about where production would land in 2016 after we determine what activity levels we would elect to commit to. So that's probably a discussion for a month ahead, at this point.

Just to also add, obviously we have the 56 in order to gain all the RMI -- on the RMI transaction. We have also spoken about 80 wells, standard reach laterals equivalent to keep flat. So that provides you with book ends. If you say, okay, we are flat right throughout 2015, if we want to be flat again for 2016, that would be, given the decline change from last year to the year ahead, it would be 80 standard reach equivalent. So you could think of that. But again, we haven't come up with any guidance. We are still working on that and we will take that to the Board and get approval as we move forward.

That's helpful. Thanks for those book ends there. And then I just wanted to make sure I understood your prepared remarks on differentials. Looking at 3Q, I have corporate oil differentials at about $8. What is a good number for us to think about for 4Q and into 2016?

We generally guide to the quarter ahead, where we see in the Wattenberg. I think $9 is a pretty good one, kind of low nines, maybe a smidgen below us. But going into 2016, clearly we have our Pony Express commitment we need to make. But we have seen a lot of availability and other means to take oil out of the Basin. And hence the reason we got below that $9 level this quarter. So we are seeing those numbers come down. So we would hope the trajectory continues to go lower, but we'll really just guide for $9 for the quarter ahead.

Great, that's helpful. A similar sort of question on cash G&A. It does look like it dipped pretty significantly. We've seen that low in 1Q, higher in 2Q, lower in 3Q. What's a good number for us to think about for 4Q and on into 2016 here?

Again, I think it's to look at the guidance ranges. I think we just brought the top of the range lower. We were at $5.75 to $6.25, so we have that top of the range now at $6. So I think $5.75 to $6 per BOE is a good range on a BOE level. So, obviously we continue -- given the environment we have -- continue to move that as low as possible. But I think tightening the range was appropriate, given we are heading into the last quarter.

Got you. And then just to follow up on an earlier comment, just want to clarify. The 80 SRL equivalent wells; that's a book end for 2016? Or that's in reference to 2015? And that's it for me. Thanks.

No, it's really -- folks asked us earlier, probably last quarter, what would it take to keep the production flat for 2016. And based on our internal work it looks like 80 would keep it flat. Last year it was 96 SRLs to keep it flat. This year into 2016 it would be 80. And that's reflective of the reduction in the decline and the maturing of our well base.

Thank you.

Michael Hall, Heikkinen.

Congratulations and good morning. Just curious, what would you put the payback at on the strip, on an SRL well currently, inclusive of the RMI drilling incentive?

The payback on the wells with the RMI incentive in place, pro forma, 2016?

Yes.

We think the XRL wells will be between three and four years payback.

Okay. Great. And then on that transaction, what -- you highlighted that Meritage is committed to building out two more CPFs. Are there any other commitments that are structured into the transaction to ensure Bonanza Creek gets full service on the asset? Just curious what else has been discussed on that.

Michael, it's Bill. Clearly, doing a transaction like this you always have one eye on the fact that your partner is going to be there every time you drill a well. And we have certainly got commitments from Meritage. And I think the other thing is line pressures. As we all know, we've spoken ad nauseam over the last two years about line pressure issues that we've had in the Basin. I think Tony spoke earlier about some really good line pressure that we've seen, especially with the Windmill line coming in. But we want to make sure as we move forward with a partner that we don't have any of these line pressure issues going forward. So, that's being worked into the contract or will be worked into the contract going forward.

So it's clear. Doing a midstream deal, we want to make sure that it doesn't affect our production. Meritage has done a really good job up in the Powder River Basin for a bunch of very large operators. They've got some work up in Canada as well that they are doing, so we feel very confident that they can deliver for Bonanza Creek. We've spent a lot of time with them over the last 15 months or so.

Okay, great. That's helpful color. And then, just curious, what sort of maintenance level or minimum level of capital spend do you think the Mid-Continent requires going forward?

Yes, for Mid-Con, to keep reduction flat it would be about $30 million to keep that production flat where it is.

Okay. That's all I have. Thank you.

Steve Berman, Canaccord Genuity.

Most of my questions have been asked, just one. Does the RMI transaction have any impact on your borrowing base?

Rich Carty

It has no impact on the borrowing base, no.

Okay, that was easy. Thank you very much.

Paul Grigel, Macquarie.

There has been a lot more focus on payback periods here rather than IRRs, that have been traditionally talked about. Is that just a near-term change, given the pricing environment, or something that can last a little bit longer as you guys look throughout the cycles?

I think it's the reality of the price environment, Paul. That ultimately, arithmetically, when you look at paybacks, you are getting your cash flow back sooner. And so the sooner we can get cash back on investment of capital, the better off we are going to be in this kind of an environment. Whereas an IRR effectively, obviously, measures returns over longer periods of time. So I think you will likely see operators throughout the industry focus more on payback in this kind of prolonged price environments.

Okay, great. And then just following up on Michael's question on the commitments on the RMI deal, is there anything from the Bonanza Creek side other than, obviously, to receive the payments here longer-term that needs to be addressed or that's in there?

Sorry; can you repeat the question? I didn't catch that. Sorry, Paul.

In terms of longer-term commitments beyond the near-term, two years to get the incentives from Bonanza Creek's side in terms of minimum volume or anything else that is part of the RMI contract?

We don't have any minimum volume commitments. I think we've detailed what we have over the next two years to our commitment to the guys at Meritage, etc. So we don't have any other volume commitments beyond that.

Okay. And then turning a little bit more on the corporate level, do you guys have debt targets or anything in this environment? Realizing EBITDA still moves around quite a bit with Mid-Con potentially being for sale, on where you want to ultimately have to balance sheet at or a target that you are balancing towards?

Ultimately, we are lucky in that our balance sheet doesn't have any maturities before 2021. So there is debt leverage. But we also complement that with a lot of liquidity, Paul. So right now, that $800 million in debt has $500 million maturity in 2021, a $300 million maturity in 2023. And with almost $600 million in near-term liquidity in 2016 pro forma with this transaction closing, we are in a very good position to see you through this down side of the cycle. That's really our balance sheet strategy for now.

Okay. So there's no specific either debt to EBITDA or other ratios that you guys would target and use as a lever both on capital spending and asset sales?

No; I think we are pretty [steady], as Rich said. Again, the focus would always be on the balance sheet and how we can balance that with the operational rhythm going forward. I just want to address something that we got a comment on earlier, just on the effect on the borrowing base for RMI. It will have a minor effect; probably about 5% effect on total Company unproved reserves. So we are in discussions at a later stage, of course, in the next quarter and next year with our borrowing base banks. But it's not significant overall, given the size of the reserve adjustment as a result of the RMI transaction.

(Multiple speakers) No, that's good to know. And then one last one for me. Can you guys provide an update on your latest thoughts on the corporate decline rate as you head into 2016?

No. The corporate decline rate year in, year out for 2015 is per our 10-K, which is 45%. But we haven't given any update on what it will look like. Clearly, when you are drilling less wells and you've got more mature wells in your overall base, that corporate decline rate should tend to be lower. We will come out with that in the next-quarter conference call. We'll see how that works.

Thanks for the time.

John Herrlin with Societe Generale.

Most things have been asked. I was just curious with the RMI deal, how long does it take to reach fruition? And did you talk to other lenders? Did you initially go into it structuring it so you would have incented drilling, or are you just trying to do an outright sale? Could you elaborate a little more?

We started this process really in the middle of last year as we looked out to full field development. We saw that, given the well costs at the time and the number of wells in the reserve base, that we were going to try and develop. You were looking at $6 billion to $7 billion of development capital over a 10, 20 year period. If you take 10% of that in the capital side, for infrastructure you would look at $600 million to $700 million.

It was clear we had spent a bunch of money up in the Pronghorn and 70 Ranch area. We were looking at all these CPFs we were going to put in place. And given the valuations on the midstream side and the amount of money we would have to spend over the next number of years, it was clear that categorizing that into a different entity was important. When we started the process, as we said, we had been talking to Meritage for about 15 months. They were very early in the process.

We probably spoke over time to about 40 different midstream operators. We narrowed it down to about six. And I think after our second-quarter conference call, when we discussed that we were going to look at various options on that entity, so we got six bids in and Meritage came to the top, along with one other interested party. So it was a very long, arduous process, very detailed. There was a lot of people involved internally and I think we got to the right result.

Regarding structure, initially we had looked at potentially joint venture structure. But really, if you're going to be in the midstream business you need to have control on your midstream assets. And I think we've put in place structures to work with Meritage to effectively give us comfort that we can run our E&P business effectively going forward. And the capital provided by Meritage as well as some of the incentives we have over the next couple years, we felt, was the best thing to do for shareholders at this stage. Hopefully, that --.

Thank you.

Mike Kelly, Seaport Global.

Congrats on the deal. A question on the [RKI] deal. I just really want to understand what you guys are on the hook for here. You've talked about, obviously, the drilling commitments. But in terms of the cost and the expectation for LOEs to go up $2 to $2.25, is that on just the Wattenberg volumes? Or is that on the Company volumes as a whole? And then moving forward, just curious on how that is structured, how we could expect that kind of range to trend. And if there is a split between fixed- and variable-cost components of this. Just a little bit more details on how that's structured. Thanks.

As we would have built out our own midstream business internally, we would have had that LOE tend to trend up as we drilled wells and put them into the midstream business. So we are effectively characterizing that now over to the RMI entity and over to Meritage. So it will be about $2 to $2.25 per BOE going forward.

I think if you look at that and the production volumes over the next number of years and you look at the cash that we are getting upfront, I think you would characterize it as a very attractive deal overall to the Company at this stage of our Genesis. So we feel pretty confident in that.

There is no other real variables involved here. Obviously we have oil and gas and gas lift and water arrangements, etc. But they will all be revealed in the document that we will file probably next week that we signed with the team at Meritage. So you will get all the detail behind each of those at fee levels, etc.

Perfect. Thanks, guys. Congrats again.

Ravi Kamath, Seaport Group.

A couple of questions. One on the RMI deal. I guess I'm going to try it another way. The $2, if you apply it to your 29,000 BOE per day, turns out to be about $21 million. So it looks like it might be -- you are selling it for 11 times EBITDA. Is that the correct math?

No, I think you need to adjust that and probably adjust it down. Let me see. I'm not sure I want to go through a whole math problem on the phone, so maybe we should get on the phone off-line and we will go through it in a bit more detail.

Sure, sure. And then secondly, given the SandRidge-EE3 deal that was announced, just wondering -- I know you have some acreage in the North Park Basin. Can you give us an update as to what's going on there and any plans over there?

I think if you look at our North Park acreage, we actually wrote down that acreage in the second quarter. I'm not sure exactly how close it is to the EE3 acreage. But we've looked on -- at that transaction. It looks very good for the seller. We will see how SandRidge get on. Not really our case to look at that. We obviously did see that transaction as it went through, but hopefully everything works out well. So, not a whole lot to comment on, for that one.

Okay, great. Thanks, guys.

David Deckelbaum, KeyBanc.

I did want to ask -- the structure of the RMI deal. Are you able to receive that second tranche of bonus payments in 2016 as well? Or is it restricted to 2017 drilling?

The sooner we develop the wells, the better for everybody. So the sooner we develop, the quicker we get those bonus payments, David. It's Rich.

Okay, so you could realize a full $80 million bonus payment in 2016 if you chose to go as quickly?

That's correct.

Correct. If we drill 112 --.

Well, it would be the $60 million of bonus payments that we have per well. But we have the two $20 million tranches, which, clearly if we drilled 112 standard reach lateral equivalents in 2016, we would have reached the 40 minimum for the first $10 million and then the 56 to gain the second $10 million payment. We would have reached it then as well, so you would be able to reach that by the end of 2016.

Got it. And then I know in the past -- I know that you guys are still working on the 2016 program. But in terms of mix of XRL versus standard reach, I think last time you talked it was 50% or so. It seems like this deal with RMI would incentivize you to drill as many extended laterals as possible. Is that the bias right now? Or can you move that 50% mix higher?

Our program -- we are going to try to drill as many extended-reach laterals in our program as possible. Probably, again, the only limiting factor that we have is when we drill on the western side of our legacy position, as we've talked about before, where we have 4,000-foot laterals already started. That may force us to drill some 4,000-foot standard-reach laterals in our program. I think that 50% number is still probably pretty accurate for what we would be looking for, for 2016.

But again, our emphasis is to drill as many XRLs as we can. But we do have to tie into those CPFs, so some of those CPFs are on that western side, so that could be limiting. But bear in mind, those wells are still very economic, those SRLs. And when you factor in the incentive that we are getting for that, it makes it very attractive for us to do those also.

Just to make an additional comment, Tony mentioned earlier we are going to have a CPF constructed by Meritage in the course of 2016 up in our northern acreage. And we've spoken a lot about the contiguous nature of our acreage up in that area and the fact that a lot of our acreage up there is basically ready for XRLs. So we are pretty excited now about having a CPF up there which will allow us to start bringing a lot more extended-reach laterals online as we go beyond that two-pad that Tony -- seven-or eight-well pad that Tony spoke about earlier.

Okay, I appreciate the color. And just one point of clarification. The $200,000 uplift for the increased sand loading, that was a cost it looks like on the slide deck that happens back in -- that was a difference back in 2014. Is it fair to say -- do you know what that difference is now? (Multiple speakers) I would think that would be less than that.

Yes, absolutely, David. It's probably going to be around $100,000 or so for that increase on that, for today's pricing.

That's all for me. Great execution on the deal, guys, and nice job.

Brian Corales, Howard Weil.

I know the call is getting long, but I just have one question. On the Mid-Con, can you maybe just talk about what we can expect over the next six months? I think, Bill, you said it wasn't a rush to sell. Is there going to be a data room open? Can you maybe just talk towards that?

As I mentioned, it's held for sale. We had a couple of folks come in, throw some numbers in. We will go through a thorough process and if we get an attractive price we will execute on that. I think, as I said earlier, the focus of 99% of our questions, whether we are on this call or whether we are on the road, is related to our Wattenberg Field. And we want to make sure that if we are not getting the value recognition in our Mid-Con asset in our stock price, then maybe it's better held with someone else. Again, we've got to make sure we get the right price as we look at that asset. So, just stay tuned and we will update you as things progress.

So this is not a very near-term event, then, in your estimation?

You know what? With the way deals move nowadays it could be a couple months and it could be six months. Or maybe we get to the middle of next year and we decide that it's not attractive, prices are looking a lot better, we continue to see some good recompletes in some of the work that has been done. As you saw, the production was up, from Tony's remarks earlier, in the Mid-Con area. So we will make a decision as facts present themselves over the next few months and into next year.

Fair enough. Thanks, guys.

Irene Haas, Wunderlich.

My questions -- most of them have been asked. Can you remind me how much you actually have invested in your Rocky Mountain Midstream assets in the last, say, 12 months?

I would probably characterize it over the last -- since we've put that business together, we have about an asset value of about $100 million in that entity. So I think that's the best way to look at it, Irene.

Great, it's a nice return. Thank you.

That does conclude the Q&A session. I will now turn the call back over to Richard Carty for closing remarks.

Well, thank you for all your engagement today. I would look forward to your Q&A and any follow-up questions that we could be helpful with. And from that point on we will sign off from here. Thank you very much.

Thank you, ladies and gentlemen, that does conclude today's conference. You may all disconnect. Everyone have a great day.