Ryan Zorn - SVP, Finance & Treasurer Rich Carty - President & CEO Bill Cassidy - EVP & CFO Tony Buchanon - EVP & COO.

Ipsit Mohanty - GMP Securities Neal Dingmann - SunTrust Robinson Humphrey Irene Haas - Wunderlich Securities Phillips Johnston - Capital One Securities Brian Corales - Howard Weil Matt Fleming - ICM David Deckelbaum - KeyBanc Capital Markets Bertrand Donnes - Johnson Rice Michael Hall - Heikkinen Energy Mike Kelly - Global Hunter Securities Andrew Coleman - Raymond James David Beard - Coker Palmer.

Welcome to the Q2 2015 Bonanza Creek Energy Earnings Conference Call. My name is Mark and I will be your operator for today. [Operator Instructions]. I would now like to turn the conference over to your host for today, Ryan Zorn, Senior Vice President of Finance and Treasurer. Please proceed, sir..

Thank you, Mark. Good morning and welcome to Bonanza Creek's second-quarter 2015 earnings conference call and webcast. We appreciate you joining us this morning on relatively short notice.

However, we felt it was important to accelerate the disclosure of our results and commentary regarding our forward outlook in order to provide you with the best information possible, as well as access to the management team in the midst of this difficult energy tape.

Yesterday afternoon we issued our earnings press release and have filed our 10-Q with the SEC. You can access both On Our website. You can also find an updated copy of our investor relations presentation as we will make reference to those materials this morning. Our website address is www.bonanzacrk.com.

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 certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to their most directly comparable GAAP measures are contained in our earnings release.

As usual, we have endeavored to keep prepared remarks short to leave ample time for Q&A during this 60-minute call. Once again, if you would like to reference our IR slides, please find the updated deck at our homepage or under the Investor Relations section at www.bonanzacrk.com.

Now it is my pleasure this morning to introduce Rich Carty, Bonanza Creek's President and Chief Executive Officer, who will provide a brief overview of the second-quarter results. Following his remarks Bill Cassidy, our Chief Financial Officer, will discuss financial highlights.

Finally, Tony Buchanan, our Chief Operating Officer, will review operations. With that I will turn things over to Rich..

Thanks, Ryan, good morning, everyone and thank you for making time to join our call today. We've been looking forward to this call for a number of weeks now to share with you many positive data points and operational milestones.

Looking back on the first quarter, it was all about recalibrating our near-term operating and financial plan in light of the dramatic turn in oil markets.

Second quarter was all about recalibrating and executing on our strategic plan in this radically new environment, executing on efficiencies and demonstrating the resilience and sustainability of our development model.

The formation of our new midstream entity, Rocky Mountain Infrastructure or RMI as we refer to it, plays a central role in the execution of our strategic plan, as we will discuss at length today. Overall Q2 was a crucial quarter for us. For instance, amongst other achievements, we had record high Wattenberg production.

Sales volumes were up 4% from Q1, 7% from Q4 and 21% year over year. We have lower Wattenberg operating costs with LOE down 2% over Q1 to $6.45 a Boe. We have record low upstream capital costs and going lower.

Standard reach lateral well CapEx down 23% from Q4 to $3.45 million with line of sight visibility to $3 million in the second half and ultimately $2.7 million projected for 2016 planning. We have very strong portfolio performance.

Our portfolio decline rates are moderating with approximately 80 standard reach equivalent wells forecast for 2016 to keep production flat, down from 96 SRL equivalents in 2015. We also have very strong Wattenberg reservoir performance.

Niobrara reservoirs have been demonstrating a widespread increase in performance with the benefit of controlled RMI service infrastructure in place with proved producing reserves supporting increased oil EURs at PUDs by 6% to 18% based on our mid-year reservoir engineering study. We have also had in Q2 a robust spring RBL redetermination.

With a strong reserve collateral base we now have $498 million of liquidity available. And importantly, with a restructured RBL covenant package that specifically excludes all $800 million of our high-yield debt from any covenant calculations.

Our Mid-Stream joint venture mandate at RMI is important by segmenting infrastructure capital into RMI where we plan to materially reduce non-DMC upstream capital or 2016 budget and create a high value sum of the parts subsidiary.

We also have strong northern acreage well results in the quarter with 100-day production data supporting 680 Mboe XRL target type curve data which helps convey our confidence in our 450 XRL locations located in the north.

And importantly, at the end we have an outstanding operator award from our state regulator, the Colorado OIL & Gas Conservation Commission and also recent recognition by Occupational Safety & Health Agency inspectors, OSHA, for excellent health and safety performance.

As is a mantra of the company, we like to say that success is no accident which refers to our ongoing commitment to health and safety, environmental and regulatory compliance and without question, our attention to detail and dedication in the execution of our plan on behalf of our stockholders.

So there have been many important deliverables by the company this quarter and our development strategy continues to accrue tangible benefits. But having pointed out many of the highlights, I would like to pass it over to Bill Cassidy and Tony Buchanan to run us through more of the particulars. I look forward to taking your questions..

Thanks, Rich and good morning, everyone. We reported company wide sales volumes of 28,000 Boe per day during the quarter which is 14% greater than three-stream equivalent volumes a year ago.

Despite our volume growth revenues declined from $151.7 million to $90.4 million for the same period or a 40% decline, as Benchmark WTI prices declined 44% and Henry Hub prices fell 42%. The company generated $74 million in adjusted EBITDAX versus the year period of $97.4 million, representing a decline of 24% year over year.

During the quarter we incurred capital costs of $164 million. We recognize that this is high on a run rate. I will go through the capital in more detail. But the bottom line is it is necessary to front end load the capital spending to prepare for the back half 2015 and beyond.

The total projected capital spend for 2015 remains at $420 million, the midpoint of our original guidance for 2015. Total for Rocky Mountain is now estimated to come in at $297.8 million with MidCon capital at $40 million.

The $420 million also included the original budgeted infrastructure of $25.2 million, as well as additional Mid-Stream infrastructure expenditure of $22.5 million.

This Mid-Stream capital is due to construction including gathering and centralized production facilities, CPFs, that will be part of our wholly-owned Rocky Mountain Infrastructure business which I will get to later. Further capital spend was also required due to unbudgeted working interest of $70 million due to non-consents in wells drilled.

Leasing of $40 million and corporate of $3 million make up the balance of the budget plan. Beyond the plan we now project drilling and completion cost savings to be approximately $40 million. We have stated that our budget is an activity budget with cost savings to be discussed later going directly to the balance sheet.

With the formation of RMI and the clear drilling cost and operation benefits through the development of infrastructure we were prudent in deploying these cost savings in a business that we believe has accreted significant value to shareholders beyond the invested capital of $48 million as of June 30.

In summary, we're confident in the overall budget including savings and additional Mid-Stream expenditure should come in at $420 million, again, the midpoint of our original guidance range. Now I will talk further about the very positive development for the company, Rocky Mountain Infrastructure or RMI.

I would like to build on our Q1 call when we announced the formation of this important part of our full field development plans and we have entered this -- the rationale for spending the capital saves in our drilling.

Our contiguous acreage position provides RMI with the unique opportunity to efficiently deploy infrastructure capital while providing our upstream business with significant well cost reductions. RMI has enabled us to begin evaluating all term sources of capital to fund infrastructure development in the form of a joint venture.

The RMI JV should act as a funding source to catalyze the growth of our infrastructure within and beyond our legacy acreage with particular focus on the northern acreage acquired last year, especially following recent base and infrastructure development and extremely positive well results.

As I alluded to earlier, EBITDA being generated by RMI currently has demonstrated the underlying value of this entity to date and the opportunity to growth this asset in value while we drill and move to full field development through the company's contiguous acreage portfolio.

With RMI operation efficiencies and service cost reductions should reduce drilling completion cost. I will let Tony cover that in his prepared remarks later. I mentioned earlier CPFs, we're building three new CPFs in 2015 capable of servicing 30 to 40 wells and plan to build a further two CPFs in 2016.

These CPFs will be reused well beyond 2015 and 2016 in a drill to fill concept in subsequent years, maximizing the return of this investment while minimizing the surface infrastructure as we follow a more economical and environmentally optimal field development plan.

In summary RMI, using our Pronghorn and 70 Ranch gathering system and building full field infrastructure base will allow the company to leverage the development of our assets and enhance well performance and returns over the life of the field. We look forward to bringing you further updates on this important and exciting asset.

Moving on, on basis differential we see positive developments within the Wattenberg Field with oil differentials moving from $10.36 per barrel in Q1 to $9.22 per barrel in Q2. We have now seen six consecutive quarters of improvement in our Rocky Mountain oil differentials.

We continue to guide differentials for the current quarter in the $9 to $10 range. On the gas side we saw pricing around the CIG differentials widen from a Q1 average of $0.19 off to a Q2 average of $0.35 off Henry Hub. We also saw a lower accrual price due to processing fees being netted against residue price receipts.

Moving now to taxes, as a quick update on severance and ad valorem taxes, the company used a 9% blended rate against net revenue during Q1. This amount coincides with the estimated rate paid in 2014. In order to more accurately reflect the current year, a full analysis of production taxes was completed during the second quarter.

We estimate that the new rate for 2015 will be 6%. The variance in comparative production tax expense from Q2 to prior periods results from the accrual being decreased during the current quarter to reflect this new rate.

Assuming consistency in our production and a stable pricing environment, we believe the company's production tax rate should normalize going forward to roughly 7%. Before I turn the call to Tony I would like to clarify the results of our spring borrowing base redetermination completed on May 13 following the first-quarter conference call.

Bonanza Creek has a $1 billion revolving credit facility with an improved borrowing base of $550 million. As of June 30, 2015 the company had borrowings under its credit facility of $43 million, a letter of credit totaling $24 million and cash totaling $15.3 million resulting in total liquidity of $498.3 million.

Bonanza Creek has two outstanding issues of unsecured high yield notes which consist of $500 million 6.75% coupon due in 2021 and $300 million of 5.75% coupon due in 2023. As part of the spring redetermination we made a permanent change in our covenant package. I would refer you to our Q2 press release for details.

Suffice to say is that we're well within our covenant thresholds. I will now hand the mic over to Tony to go through the operational update..

Thanks, Bill and good morning, everyone. I am very pleased with the second quarter as we generated some outstanding results that we will leverage repeatedly as we continue with full field development plan of our asset base.

By way of reference we now have over 380 gross horizontal wells in the Wattenberg representing one of the most robust and mature well portfolios amongst basin operators. First, I want to talk about our northern acreage.

As we have said previously, we know that the geology of our northern acreage acquired last year is very consistent with the well's Ranch area and our legacy acreage position. We added a new slide to our investor materials to better describe this fact.

We have also mentioned that our northern acreage is ideally situated for extended reach lateral development. In Q1 we said that we were looking forward to drilling, landing, steering and completing our own wells in order to provide accurate information as to how this acreage will perform. We now have this.

Our first extended reach lateral well on this acreage was drilled and brought online in mid-April. The well was completed as a 7,300 foot lateral in the Niobrara B bench located in the north side of 6 North, 62 West in Section 4 and is very representative of our northern acreage position.

Based on 100 days of production we now estimate that the EUR on this well will be approximately 550 Mboe. When extrapolated to a 9,000 foot lateral the EUR would be about 680 Mboe which is directly in line with our extended reach lateral target type curves on our legacy acreage.

We're very pleased with this result, but it is not surprising because we have confidence that the geology is consistent. We also have a second data point from the completion of one of the acquired wellbores on this acreage.

This well is located on the east side of our northern acreage in Section 16 of 661 and was drilled in 2010 by a former owner of the asset. The former owner drilled a 3,000 foot lateral and installed sliding sleeves designed for a 15-stage frac job prior to temporarily abandoning the well before selling the asset.

But even with its limitations we went ahead and completed the well in January 2015 in order to extract helpful data to the calibration of the geology. After about six months of production data this well is tracking to a 200 Mboe EUR.

Extrapolated to 9,000 foot lateral -- extended reach lateral well with the same number of stages that we're currently using the EUR falls right around 650 Mboe, well within our range of extended reach laterals that make up our type curves.

Moreover, this EUR has not been adjusted for any optimization associated with the proper drilling and steering of the lateral to stay in zone which we believe improves productivity. The results of these two wells have encouraged us to drill a second XRL on the northern acreage, a 9,000 footer in the north part of the acreage in Section 21 of 762.

We have wrapped up drilling and plan to complete this well in the third quarter. Finally, as I hope I have made clear, we have confidence in this area and plan to drill a minimum of one, eight well extended reach lateral pad as part of our 2016 program.

Another very good development on our northern acreage is the continued build out by DCP of its infrastructure.

As we said previously, the main limiting factor to moving ahead aggressively on our northern acreage at the beginning of 2015 was not due to the lack of confidence in the subsurface but was due to the lack of gas take away infrastructure to support it. DCP solve and compressor stations service this acreage.

But it was being kept full mostly from gas production from our Eastern legacy position. Please reference slide 19 in our investor presentation as I talk through this.

With Lucerne II coming online in combination with the 70 Ranch compressor station, other additional DCP compression and the Windmill transfer line, we now have the ability to take up to 50 million cubic feet of gas of our Eastern acreage to the West thus freeing up capacity at Sullivan to support the development in the north.

As you can see, any significant development before this expansion would have been counterproductive as the wells from the north would have been competing against existing wells in the eastern legacy acreage. Now that it is in place we can move forward with the development of our eight well pad in 2016 as I mentioned.

Now I want to take one final minute to summarize the full potential of our northern acreage. First, we have high confidence that both the Niobrara B and Niobrara C benches are present across the entire position.

The B and C geology correlates very well to that of Wells Ranch and our legacy acreage with the interesting point being that the C bench [Technical Difficulty]..

Okay, everybody, sorry for the technical difficulty there. I am going to have Tony back up in his script a little bit. He might repeat a bit, but please forgive us for that, thanks..

I'm back again, everybody and thanks for the consideration. I am going to back up on my script and I'm going to start off talking about the infrastructure on the northern acreage development that is continuing up there. So I will start at that part of my script.

Another very good development on our northern acreage is the continued build out by DCP of its infrastructure.

As we said previously, the main limiting factor to moving ahead aggressively on our northern acreage at the beginning of 2015 was not due to the lack of confidence in the subsurface, but was due to the lack of gas take away infrastructure to support it. DCP Sullivan compressor station services this acreage.

But it was being kept full mostly from gas production from our Eastern legacy position. Please reference slide 19 in our investor presentation as I talk through this.

With Lucerne II coming online in combination with the 70 Ranch compressor station, other additional DCP compression and the Windmill transfer line, we now have the ability to take up to 50 million cubic feet a day of our Eastern acreage gas to the West thus freeing up capacity at the Sullivan compressor station to support development in the north.

As you can see, any significant development before this expansion would have been counterproductive as the wells from the north would have been competing against the existing wells in Eastern legacy acreage. Now that it is in place we can move forward, as I mentioned, with our eight well pad in 2016.

Now I want to take one final minute to summarize the full potential of our northern acreage. First, we have high confidence that both the Niobrara B and C benches are present across the entire position.

The B and C geology correlates very well to that of Wells Ranch and our legacy acreage with the interesting point being that the C bench is actually thicker in parts of it. As for the Codell, it correlates also well that we can certainly expect to develop it on about 6,000 acres of the northern position.

We have two producing wells so far covering acreage from west to east and significant offset operator data that support our assumptions that extended reach lateral development is the way to come. With over 85% of this acreage open to extended reach lateral drilling, we have an inventory of approximately 450 XRLs.

Factoring in lower XRL costs which are heading towards $5 million for a 9,000 footer and a future partner to support the infrastructure build out, the economics of the northern acreage looks to compete favorably with our legacy position. Moving on to well cost improvements, please reference slide 8 in our Investor deck.

Our full field entering plan is continuing to demonstrate efficiencies and realized cost reductions. We entered the second quarter with a 4000 foot SRL costing $3.6 million. As we exited the quarter we have been able to push those costs down to the $3.4 million to $3.5 million range.

This decrease was driven mainly by continued improved drilling times with SRLs now taking six to seven days from spud to rig release and 9,000 foot XRLs taking about 10 days with a few wells in nine days. And improved water infrastructure that allows water to be piped and not trucked for the fracs.

Moving forward we're targeting D&C AFEs of approximately $3 million with the benefit of RMI developing the midstream infrastructure and achieving further cost savings by optimizing frac fluids and our supply chain process.

Looking to 2016, we have a line of sight to take costs down to $2.7 million or below by utilizing a 2-stream mono-bore well design and evolving our frac fluids to a higher mix of slick water within our hybrid gel dominated designs. Extended reach laterals are following this same trend and moving towards $5 million for a 9,000 footer.

On to our production performance for the quarter.

We posted some very solid numbers in spite of timing delays we had on a five well extended reach lateral pad mostly due to the wet weather that caused flooding and impassable road conditions in May and early June in Colorado which pushed some volumes out of 2Q into 3Q and the underperformance of one five-well pad that came online in late first quarter.

Sales for the company were 28,000 Boe per day, up from 27.5 Mboe per day in 1Q. More importantly, our estimated sales volumes through the first 20 days of July have increased to 29.4 Mboe per day. These numbers are the highest rates ever achieved by the company. In the Rocky Mountain region the story is even better.

Even with the timing delays on the five-well pad which cost us about 690 Boe per day for the quarter and the impact of the one underperforming pad which was about 745 Boe per day, Rocky Mountain production still landed at 22.7 Mboe per day, up 4% from 1Q, up 7% from 4Q and up 21% year over year.

As the remainder of the company's base production and newly completed wells in the Wattenberg Field were above expectation by approximately 1,000 Boe per day net due to a combination of well performance and increased working interest. And the growth will continue as we expect to add another 900 Boe per day in the third quarter.

Performance continues to be in line with type curves expectations and we continue to leverage as much existing infrastructure as possible to enhance economic performance. Specifically on the underperforming pad which consisted of five medium reach lateral wells.

It is located on the far southeast of our central legacy position in 4 North, 62 West in Sections 8 and 17. We're evaluating the performance issues. The good news is that, due to its location, it does not impact the viability of any of our other acreage as we have good wells in adjacent sections to the north and west.

One last item I would like to discuss before moving on from our Rocky Mountain discussion centers around 25 stage fracs versus 28 stage fracs. As I previously had mentioned, the change in frac stages was just a slight modification to our 28 stage design to become more efficient.

We have added a new slide to the appendix of our Investor presentation on page 29, that shows 25 stage fracs are consistent with our older 28 stage design. The data shown presents wells that were completed in the same land section to ensure geological consistency and provides verification that we have consistent performance.

Moving on to Mid-Continent, it continues to be a very dependable asset for us. Sales volumes averaged 5.3 Mboe per day for the quarter, down about 300 Boe per day from 1Q which is primarily due to our Q1 recompletion program that we have discussed previously.

To reiterate, the recompletion program is statistical in nature and subject to upswings and downswings on a quarter-to-quarter basis, But remains one of the most economic opportunities in the company. The good news for MidCon is that we exited second quarter, production rates have stabilized and we now expect to produce about 5,000 Boe per day in 3Q.

On the cost front we continue to realize gains for efficiency improvements. The MidCon operating cost is under budget by a little over $2 million year to date. This is attributed to lower gas plant operating costs and turnaround expenses.

In addition, we idled our McKamie gas plant and have diverted production from that area to our Dorcheat facility which is capable of handling our forecasted gas production.

Operating expenses associated with our McKamie plant are 5% to 10% of Mid-Continent LOE and we should see this cost reduction hit our financial statements in the second half of the year. Last but not least, we continue to focus on safety and environmental compliance as part of our everyday business.

We have two key accomplishments to demonstrate the results of these efforts. First, as a company we have now worked over 1.4 million man-hours without a lost time incident for one of our employees.

Nothing is more important to us than making sure that all the employees and contractors that work for Bonanza Creek are working in an environment that puts safety above all else.

Second, on the environmental and regulatory compliance front, Bonanza Creek is being presented with an outstanding operator award by our state regulator, the Colorado Oil & Gas Conservation Commission, for innovations on our flow back operations that have led to decreased emissions while optimizing well productivity.

So to wrap up, some really great things occurred in 2Q.

From strong results on our northern acreage that support our development planning to sustainable well cost reductions and continued production growth especially in the Wattenberg, we're well-positioned to move through the rest of 2015 and into 2016 with a high-quality asset base that has demonstrated success time and time again.

I will now turn the call over to the operator for questions..

[Operator Instructions]. Your first question comes from the line of Ipsit Mohanty. Please proceed. .

Tony, if I could ask you a little bit more color on the underperforming pad in terms of where it's located, what was the reason for the underperformance and what you take from it going forward?.

Yes, you bet, Ipsit. Referencing the five-well pad that underperformed, Ipsit, I would probably refer you to our slide deck. And if I could direct you to slide 12 in our slide deck.

The pad that I am referencing is -- I'll tell you what, Ipsit, let me take you to slide 14 first, actually a little bit easier to see on 14, but I will back you up to slide 12.

But on slide 14, if you could turn to that, Section 8 of Township, if you can see that 4-62 Section 8, there is a five-well pad that goes into Section 17 on the far South, east of our central position. That is the pad that I am referencing.

And if I move you back now to slide 12, that kind of blows it back out to an aerial extent of the entire acreage position. You can kind of go where you see that pad. Again, the underperformance is undervaluation by us.

But due to the location of it being on the far southeast, as we know the Niobrara B and C, as it moves to the south and to the east in that direction there is fewer and fewer data point and it gets a little sketchier as you move off of our acreage position. And when you look at where we're on our acreage position it is on the far southeast.

So therefore it doesn't impact anything basically to the north, to the west, to the South and anything obviously in our eastern legacy position. So there is really no impact to our existing acreage position other than that section that it is on.

Everything else stands to be very much in the same color as we have had before from a valuation standpoint, knowing that the B, the C and the Codell are present across most of those positions. So, again, that position is where that well is and we feel very confident in the rest..

Any color on why -- any reason yet behind underperformance?.

Ipsit, we're still evaluating that. Again, we drilled medium reach laterals there and we're still under evaluation of whether or not it was whether we were in zone, operational performance in that area -- those are the kinds of things we're looking at. But again, that evaluation is ongoing..

Thanks, Tony.

And if I could ask you about your thoughts on the activity in the northern acreage going forward for the remainder of 2015 and what is in plan for 2016?.

Yes. Ipsit, for 2015 we have the one additional extended reach lateral that I mentioned in my script. That well is being drilled on the north side. It is a 9,000 footer. We have finished drilling that and we'll complete that here in third quarter.

And then for 2016 we're planning at least one eight-well pad up on the northern acreage that will move out there and it could possibly be more than that in 2016. But again, we're putting our 2016 plans together as we speak. But at least one, eight-well pad for sure..

Okay and my last, talking about 2016 and you have given some very slight sort of outlook. Appreciate your doing that.

But when you think about RMI, what kind of capital do you plan and what kind of capital out of that 420 midpoint CapEx [indiscernible] have you planned for 2015? And do you assume a similar flat rate for 2016?.

Well, Ipsit, the capital we have for RMI for 2015 is the budgeted $25.2 million and then we have the additional RMI capital of $22.5 million. So that will all go into 2015. We're working on the two CPFs that I mentioned in my script earlier and that will be additional capital in 2016.

But we're not putting out that guidance on the capital amounts for 2016 as of yet..

Your next question comes from the line of Neil Dingmann from SunTrust. Please proceed..

Just a couple questions, I guess more on the extension that you were just kind of referencing. As you continue to do some of the step out, I am just wondering more about the well designs in those.

Could you talk about a couple things around this? Do I have this right, those will all be the plug and perf on those? And if you could address the expected costs for the remainder of the year of those..

Yes, on the extended reach lateral drill wells that we're planning right now, the 9,000 footers, we're now bringing those costs down. As I mentioned, they are targeting down towards $5 million per a 9000 footer. But that is for a sliding sleeve completion. And that is about 50 stages..

Okay. So I guess that was my question.

So you can slide -- if you got that far you can do sliding sleeve on those?.

Yes, you can. We have actually executed that. Yes we have..

Okay. And then your thought out there just I guess M&A or sort of block on acreage, are you doing some of that here I guess in that area? And then just sort of a question for Rich overall just on M&A here, your thoughts in this environment..

Yes, I think as we have discussed before, the M&A environment is attractive for doing things like backing into non-consent AFEs for wellbores which we have done opportunistically throughout Q1 and Q2 with some positive results in Q2. That is kind of really low hanging fruit for us.

We have an ongoing land leasing business where we're accumulating acreage here and there where we can. I think from a perspective of larger M&A, there's a lot of talk about larger M&A in the business, but so far there has only been two or three observations in the industry and we will take a wait and see outlook on that..

Okay. And then just lastly, activity wise or rig wise your thoughts on what you would have to see out your way in realized prices to potentially add and ramp activity..

Ultimately our decision to ramp activity would be a function of two things, realized prices and also the realized cost structure. So as those two variables come into closer focus we can make more determinations on that front.

But I would say at these prices we're not confident that increasing activity is the right thing to do and it is our opinion that people that are increasing activity are probably doing so for non-economic reasons..

Your next question comes from Irene Haas of Wunderlich. Please proceed. .

My question is really on RMI. You made a few mentions to a possible JV.

Could we have a little color on that perhaps?.

Clearly we have spent additional capital in this quarter or certainly in the budget, that $22.5 million. We're very focused on optimizing the capital to be deployed across the asset base. And if we can move capital away from drilling completion and into RMI we will do that.

We have had a lot of the inquiry on folks wanting to come into the basin and to develop an infrastructure business and work with us to do that. And we're in discussions with those folks and as those discussions develop we will come back and update everyone..

Do you have any timeline roughly? Just could we expect some announcements before the end of this year?.

You know, we would like to get it done by the end of the year, I think that would make sense as we move into 2016, but I don't want to show my hand in any negotiations. So we will wait and see how that develops..

Your next question comes from Phillips Johnston of Capital One. Please proceed. .

Can you give us an update on the latest thinking around the Arkansas asset and what the long-term strategy is there in terms of possibly monetizing it at some point in the future?.

Listen, the Mid-Continent asset has been an important part of this business throughout the development of the company. From the free cash flow that asset has provided us the ability to bring the Wattenberg Field from an exploration asset to an appraisal asset to now a full field development asset.

So it is been a very profitable business for us, it remains a very attractive integrated business. As you know, we own all the processing, we own all the gathering systems in the area. We integrate the upstream business into that.

We're the monopoly processor, so any offset operators with associated gas have to come to us which makes us a natural consolidator. And we're the largest producer of oil in the state of Arkansas which has a very flat differential to WTI. So it's an attractive asset, the recompletions in the business are very attractive to the company.

The challenge for us is that the Wattenberg is becoming such a large proportional amount of what we do that we just don't talk about the Arkansas asset as much anymore. But we don't have any current plans to dispose of it..

And then just on the housekeeping front just on CapEx, I was hoping you could maybe get a little bit more color on the $22.5 million of additional CapEx associated with RMI that was previously allocated to nonworking interest partners.

I guess my question is what is really changed there and what drove that change?.

Well, I guess we had cost savings of $30 million from our overall drilling program. And then we moved $22.5 million into the development of our RMI system and CPS that were constructing at the moment -- we're constructing three CPS in our legacy acreage and that is effectively where the most of that has gone and on the gathering system..

Okay, so I guess the non-D&C CapEx for the year effectively has increased is that the way to think about it?.

Well, we basically moved the D&C to $30 million we moved into the RMI. And then of course we have the increased working interest. So if you look at that $22 million -- working interest that gets you to the $40 million that we saved on the drilling side..

Your next question comes from Brian Corales from Howard Weil. Please proceed. .

Just a question on the cost per well going from $3.5 million to $2.7 million.

Have you all drilled using a two-stream design and have you all tested those -- I guess the new frac design you are talking about to get to those $2.7 million?.

As for the mono bore two-stream design we have drilled one of those. We have attempted one and completed one. So we have actually done that. And so, we're going to continue to high-grade that and see if we can execute that design over and over again as part of our 2016 program to drive costs down.

As for the slick water part that you mentioned, no, we have not done that part yet. That is part of the engineering that we're doing on right now moving some of our gel systems, we do a hybrid frac and actually including more and more slick water into that to reduce those costs.

So our engineering teams are evaluating that as we speak and we'll be looking at that, implementing that in 2016. But those are the two key steps to take you down to the $2.7 million..

Okay. And then to get to the $3 million I guess at year end, a lot of that is the water facilities.

Is that already in place so we can assume that $3.4 million, $3.5 million goes to $3.2 million or somewhere close to that pretty easily?.

I guess the part that is in place stepping down from the $3.45 million down to the $3 million, like we have identified in the slide deck, the part on the flow back -- that $107,000 on completion, I think that is going to be something that we will be implementing obviously in the second part of the year, that is around flow back trucking.

We have got better bids in and continued modifications, slight modifications to our completion fluids and things like that. As for RMI infrastructure, that RMI infrastructure is in place. And so, yes, you can take that out..

You all talked in the release about 80 wells in the Wattenberg keeping production flat. Can we assume that that is the plan for 2016 maybe where we stand today.

And that -- I mean if we say $3 million well cost that is $240 million of capital?.

Our goal here in trying to convey the 80 wells to keep production flat kind of bogey is not to convey that as a specific plan, but to give you a frame of reference to understand how the economics are maturing as the -- our well portfolio vintages over time.

So that is not a specific conveyance on a budget, we wouldn't do that until we have something approved by the Board. But did give you a bogey that you can set bookmarks on effectively..

Can we assume -- what other costs besides Wattenberg -- would you still plan on spending a little bit in the MidCon as well for next year?.

Well, we have traditional other cost structures in our business. We have the MidCon, as you know, that is voluntary capital. There is things like science, there is leasing, there could be any other kind of land acquisition we would want to do on an opportunistic basis.

But we haven't gotten to the point of making the determinations on what to spend on those areas..

And Brian, one of the positives, of course, if we set up this RMI and a joint venture we'll be able to move that capital and potentially get it covered by an RMI joint venture partner given the amount of capital we would have spent on that into the over the last number of years..

Okay.

So assuming something in the neighborhood of $250 million to $300 million in capital next year to run flat would be a fair assumption?.

We haven't provided guidance, Brian, but if you want to focus just on the Wattenberg Field the number would be lower..

Your next question comes from Matt Fleming from ICM. Please proceed..

Rich, if I look at your enterprise value which I am applying your shares out times your current share price, I add your debt onto that and then I deduct the $1.2 billion -- excuse me, the $1.1 billion PV10 that you listed at the yearend 2014.

If I ascribe no value to any of the MidCon assets or gathering assets you talked about, that leaves me with a remainder of about $138 million. If I divide that just by the Wattenberg acres, that implies a value of about $2,000 an acre for the Wattenberg. Yet my understanding is a private market value is more like $5,000.

And if I look at Synergy, whom I consider to be your closest peer, the number would be closer to $9,000. So my question to you is, am I missing something? And then if not, what is your plan to create shareholder value and decrease this gap that appears to be in the market right now? Thank you very much..

Thanks for the question, Matt. I could reference you to page 25 in our August deck. We've added a new slide in there which calculates the production adjusted acreage value for the company at the current prices actually as a negative histogram bar.

So you’re right in pointing out the fact the company is cheap on an enterprise value basis, it is cheap on an inferred basis of acreage through production multiples. You can triangle that a bunch of different ways. So I don't think you are missing anything, I think other people might be missing something.

But we're very focused on trying to maximize value for stockholders. What the company has done through its history has been organic well -- drill bit wellhead value building in the business and we haven't engaged in any kind of M&A or large-scale corporate acquisitions.

So you can assume that we're going to be predictable, repeatable and true to our form in the future, unless circumstances provide opportunistic. But, the stock is very cheap, it is not quite as cheap as we can produce production on by doing it ourselves, but it is very cheap versus peers..

Your next question comes from David Deckelbaum from KeyBanc. Please proceed. .

I'm curious, you shifted the extended reach lateral outlook and I think we can understand the economics behind that going the 50% in 2016.

With more infrastructure investments how do you see that sort of progressing in longer-term development plans as a percentage of your overall drill plans?.

Yes, we expect extended reach lateral drilling to continue to be more and more of our drilling plans going forward. As you know, I mentioned the northern acreage, over 85% is available for XRL. When you take our entire acreage position in concert to gather up to 75% is available for XRL drilling.

Probably the only limiting factor that you have is making sure that the infrastructure gets out ahead of it so that when you drill these four and five, six well, eight well pads that have eight extended reach laterals on it that you have the infrastructure capacity there available to bring that production on line.

So, with this midstream JV partner that we're looking at, as we have talked about, that coupled with our acreage position being available for the XRL development, it will continue to grow throughout our programs as we go forward..

And I guess a lot of people have asked about Arkansas today. And you said you haven't really come up with the capital out there. It is like you said, Rich, it has gotten the full field development mode.

When is the right time I guess? You looked at this year of spending almost $40 million there to kind of keep production flat-ish, but yet it is statistical in nature. You go into next year, if you put capital to work there it is still going to be statistical in nature.

Obviously, oil prices aren't the best right now, but when is the right time to sort of start looking at monetizing that asset and get a better appreciation for the Wattenberg portfolio?.

We look at optimizing our portfolio whenever we can, we're trying to continually optimize the productivity of our capital we deploy in the business. So again you should thing that we would be repeatable and predictable that way down the road and at this point we don't have any plans to dispose of it, but it is a very attractive business.

The only thing that has changed for us over time is that it is proportionally smaller to the company today than it was in the past. The company used to be back in 2010/2011, 80% an Arkansas asset and 20% a Wattenberg asset. Now it is 82% Wattenberg and 18% Arkansas.

So that the tables have turned there, but doesn't reflect negatively on the asset at all..

Sure. And I guess, Bill, just on the RMI JV.

You talked about timing but is this sort of a 50-50 type of set up? And I suppose that this would only include infrastructure within the Rockies, is that fair?.

I'm not sure I want to tell anyone what my eventual structure for RMI is going to be, especially on a conference call. It will probably hamper any negotiation that we will have as a company with partners. We look at the optimal way to structure this. Clearly the reason for doing RMI is control, right.

We need to control the build out of the infrastructure. We have had issues in the past on control, to make sure that the lines were there, the gathering systems were there.

And as we look at a joint venture partner we look to make sure we have control going down the road not just in the initial joint venture structure, but beyond -- because as these go on people want to monetize, people want ICO, etcetera. We will have to think about all those going forward.

So 50-50, maybe it could get down to a lot less percentage for Bonanza Creek or maybe we decide that depending on oil prices we hold onto the lion's share of it.

But if we were in a much higher oil price environment and the balance sheet was in a better situation we would like to hold onto this 100%, especially given the multiples that you can sell this at a later stage or IPO it, etcetera. So you get a very strong valuation for these midstream assets, as I alluded to in my earlier remarks.

So, hopefully that is helpful..

Your next question comes from Bertrand Donnes from Johnson Rice. Please proceed. .

Looking at 2016 would it be kind of safe to assume that it would be a back end loaded completion program kind of because your completed well costs are dropping so fast maybe they capture more of the infrastructure savings? Or is it really more of kind of that flat stable production you were talking about earlier?.

I think that is pretty speculative at this point. We haven't made any plans what definitively 2016 would look like let alone how that would be apportioned throughout the year. So there's nothing really to comment on that..

Problem. Just thought I would take a shot. Maybe back to the RMI, just to kind of clarify.

Not the structure of the 50-50 but was bringing in a capital partner to allow for the acceleration or just to kind of split off the currently planned capital that you have built in?.

When we set up RMI earlier this year, it is interesting as you start to push your gathering systems and the cost of your gathering system into a different entity, you realize that the cost benefits, the savings that you can have. You also realize the fact that you have got additional capacity in your system that you can take additional gas through.

So I think that's how we eventually structure RMI will be [Technical Difficulty] the discussions have with these midstream -- potential midstream partners.

I am not sure is that helpful or --?.

Yes, no, that is fine. And then maybe two kind of housekeeping ones.

Do you have a timeframe or a plan for when you might have some of the southern from the non-legacy -- the acquired acreage results?.

Right now we're looking at 2016 before we do any work down [Technical Difficulty]. Obviously we had mentioned before that there is some consolidation acreage work that we're working on down there to optimize development plans. So 2016 would be the earliest..

Okay.

And then not to try to get a firm 2016 answer, but for the MidCon what was the -- to keep production flat there instead of just the Wattenberg, was the $20 million a quarter or does it need to be less than that or--?.

Bertrand, we haven't really disclosed the MidCon in and of itself. So we'd have to get back to you on a question like that..

No problem. And then just the very last one.

On that slide where you are showing your targeted completed well cost in the fourth quarter, are there service costs baked into the completion drops? Or is that purely just the change you said on the fluids or maybe another part of the design?.

We're always continuing to work on our costs, but, yes, as I described for what we have there, it was around the trucking and the changes to our completion design, slight improvements on that, nothing significant that is modeled into that right now..

Your next question comes from Michael Hall from Heikkenen Energy. Please proceed..

I guess a little bit of a dovetail from that last question. You guys have had a lot of -- I'm trying to understand the sustainability of cost improvement versus cyclicality of cost improvements. And you guys had a number of design changes and it sounds like more in the works.

Can you just kind of walk us down from the beginning of the year well cost through to the $2.7 million targeted well cost for a standard length lateral in 2016 and the pieces of or the buckets of savings be it cyclical or more of a structural well-design type change?.

Yes, let me go ahead and reference you to slide 8 on our slide deck that we had and I will step you down. Just to kind of back up real quick, we entered the year at $4 million. That 20% production to $3.6 million was the additional cost improvement we received from our service pump pressure pumpers at that point to take us down to the $3.6 million.

But moving forward from that, basically the costs that we're taking out right now, those are all sustainable in basically almost all of the cases that we will be talking about going forward. As I step you down from $3.6 billion to the $3.5 million, we talked about drilling efficiencies, just fewer days, more efficient rigs, batch drilling.

I mentioned about the water costs and of course we have improved some of the things from our facility design. So that took us down to the $3.5 million gaining as another $100,000 or so. And then as you move forward, I talked about the trucking in the flow back, moving that around and being more efficient at that.

That is sustainable and as we talked about any slight changes that we make internally to optimize completion design that is sustainable. So that is built into that $3.5 million partaking as down to $3 million. So again sustainable cost reductions.

RMI thing that piece of that, other piece taking as down to $3 million, obviously that is very sustainable. So I think obviously a great majority if not all of the cost taking us from that $3.6 million downward are sustainable efficiency driven parts of being part of our full field development..

And then on the -- I guess the slight change in well-designed proposed to get you to the $2.7 million for 2016, is there anything about that that would not be applicable to an extended reach lateral? Or can we just kind of scale those cost per foot to a 9000 foot type lateral with some efficiency or some savings just for vertical wellbore being spread out on a lateral?.

Yes, we think those changes would be applicable to a 9,000 foot lateral. So the mono bore drilling and of course the completion designs, optimizations we would make maybe using more slick what, those kind of things would absolutely be applicable..

And are there any risks associated with slick water completions that has kept you from using those in the past?.

Absolutely and that is one of the reasons that we're looking at it now. As I mentioned earlier, our engineering teams are evaluating that. We may not go to total slick water jobs, but add more slick water to our gelled systems to make sure that we do not jeopardize the EURs of the well. That is paramount to us.

We wouldn't make a completion design change that would jeopardize the EUR. So that is why our engineering teams are looking at that and that is why we don't think we would be applying that until 2016.

But if our teams do design it and it does work, that is a significant cost reduction and we're targeting to get there with a design that would achieve both ends..

Okay. And on completion design, I think you had looked at investing in some plug and perf wells late last year. I guess any updated thinking around the relative pros and cons of plug and perf versus sliding sleeves? I know some of the others in the basin here have been having some good success with plug and perf.

Just curious on your updated thoughts there..

No, you bet. We have our eye on plug in perf technology being applied in the basin. I will say we need to make sure the different parts of the basin where the successes are. But we did our initial two tests that we did last year and honestly the verdict on those were inconsequential difference between sliding sleeves.

However, we weren't going to just walk away from that. We actually have three extended reach lateral wells right now that we will be going doing a plug and perf. We also [Technical Difficulty] applying the BioVert, the Halliburton product that helps improve fracs.

So we have those wells and we will commencing fracking on those wells here in the third quarter to give us a true test.

We also made sure we isolated those wells in the same section of other extended reach laterals so that we could take out the geological variabilities, minimizing all other variabilities so that we could compare the actual completion techniques versus each other. So we're doing that and we're moving forward with testing that..

Okay.

I'm sorry, were all those plug and perfs and the BioVerts being tested in the third quarter or was that just the BioVerts you were referring to?.

It is a three well pad, plug and perf with BioVert included..

And then last one on my end, can you just kind of walk around through cycle times as we think about kind of rough guideposts you put on the 2016 activity levels? What sort of rig count would be needed to support that given the improvements in drilling days you have talked about?.

Just looking at approximate 80 standard reach lateral equivalents what we're looking at would probably be somewhere between one to two rigs throughout the year to drill something like that. I mean, if you look at our well counts right now two rigs delivering about 77 wells pretty much this year..

Your next question comes from [indiscernible] from Cowen and Company. Please proceed..

Most have been asked and answered at this point. Just a couple of housekeeping ones for me. Both G&A and DD&A a little bit higher than my expectations this quarter.

Rich, I know you have a sharp technical team there, but with much of the legacy asset delineated I am curious whether you believe G&A should decrease on an absolute basis from here?.

A lot of the G&A that we have invested in this year has been associated with environmental and regulatory compliance which is kind of a nondiscretionary G&A item. We've made some very good investments there and they are actually providing some important rewards back to the business. So we're proud of that part of the company.

It shouldn't be recurring nature of the business, it's one time in nature. So there should be some ability to scale G&A proportionally with growing the business over time..

Yes and also, Brian, for G&A we had an [indiscernible] accrual which caused a $0.59 per BOE impact on over Q1 2015. So that is the reason you saw the G&A kind of go up there. So that will all kind of level out as we go through the year..

And I can see that guidance that helps to kind of understand that. And then looking at the well cost, obviously a nice point here, I mean down from $4.5 million in 2014 to $3.4 million $3.5 million currently.

Curious what the 2016 target would look like sort of excluding the shift of certain capital expenditures to RMI, what is sort of like the D&C sort of organic improvement? I guess there is probably something on slide 8 to help me get to that as well..

Well, I think it is kind of the other way around, Brian. Historically D&C has included a lot of non-D&C stuff. So we're cleaning that up in providing a dedicated method and vehicle and operations mandate to scale the infrastructure business in a lead time context to complement a potential acceleration of development when we see that fit.

So we're not -- yes, it is kind of -- it has been over capitalized in the past and so we're curing a prior deficiency and cleaning that up for future proper calculation..

Your next question comes from Mike Kelly from Global Hunter Securities. Please proceed. .

Rich, you stated that at current prices you're not incentivized to grow activity levels. But I am interested if this kind of lower for longer scenario that people are kind of speculating on plays out how you envision managing the company. Thanks..

Well, that is a great question, Mike. I mean ultimately we're blessed by the fact that we have some really productive rocks in the company, right. We have a big portfolio, we have demonstrated both the repeatability and predictability of the subsurface complemented by best of class operatorship in the basin throughout the past five years.

There is lots of data to support that and third-party contacts. So we have an advantage there. The basin also has the lowest variability of the lower 48 basin so that is very good for large-scale development.

And as you can see, we're pushing the envelope on capital productivity by reducing the cost structure development profile and creating a very pure upstream capital dollar for everyone to be able to measure an attribute our success in that light. So I think we're better positioned than most, it is a top quartile asset for sure.

And so, we're positioning ourselves to be as sustainable and repeatable and preserve the option to cultivate these 500 million barrels of oil when conditions so merit..

Bill, I want to ask you any comments you have on revolver re-determination season this fall, there has been a lot of speculation on that. Just would love to hear your comments there, specifically how Bonanza is positioned to face maybe some harsher bank re-determinations. Thanks..

And I was waiting for that question; I thought we were going to miss out. We're beginning to have preliminary conversations with the banks. There has been a bunch of analyst research out which puts us at kind of down 10% as kind of what people are estimating.

It is early stage; we will start really heading into that the end of this month or the end of August into September. But we're obviously very focused on that. It will be a key differentiator in the market as we go forward. So we don't have any comments to make on that or comments from the banks as to how they are going to approach it.

And we I think did pretty well in the last borrowing base re-determination relative to some of our peers. I think some of the well costs that we're seeing will be very positive as we go through the re-determination. You know they look at kind of where we're [indiscernible] at the moment as we look forward into an [indiscernible] analysis.

So I think that is going to [indiscernible] be helpful given the work we have done there..

And, Mike, I can just follow up on that a little bit. From an RBL perspective, they're obviously focused on triangulating the subsurface collateral of the asset. So I would refer you to the investor deck which gives some data points on our measured reserve booking methodology.

And obviously in the industry one of the key things that is going to happen is the relative kind of impact of one company versus another. So we have had a long repeated track record of increasing volumes, our reserve replacement ratios are very high.

We have conveyed that our subsurface productivity is increasing with the benefit of full field infrastructure and RMI's dedication in place. And so, some of these things argue in our favor in that we're pretty proud of some of those characteristics..

Your next question comes from Andrew Coleman of Raymond James. Please proceed..

Again, I think Brian Corales covered some of the stuff I was interested in.

But I guess to delve a little further on that, could you let me know what that base decline on the PDEs are currently looking like in your model? And do you see much of a change as all the facilities, debottlenecking and CPFs and all that come online?.

No, we haven't updated any disclosures on proved reserve base declines. We did give you a midyear kind of reserve insight in our prepared remarks as to how the proved reserves are performing which is very encouraging. And that our decline curve is moderating. But we haven't disclosed specific numbers in that and don't plan to before 2016's K is filed..

And the second question is kind of building a little bit off of what Brian just asked there. Looking at -- you guys removed the covenant test for four times debt to EBITDA, but in the -- sorry about that, the lower for longer outlook.

I guess do you guys have a target debt to EBITDA level that you are comfortable with such that if we see the model getting that we should be getting closer to maintenance capital in the out years?.

When we went and did our re-determination in the spring we kind of went ahead of -- it wasn't really necessary for us to go and change our covenants which we did. And they weren't given to us with a limitation. So we have those covenants permanently.

Clearly we're well inside if you look at our prepared or I guess our press release, we're well inside of those covenants and we plan on being well inside them for a long time going forward.

Clearly as we look at our business plan and we look at what we're going to do for the bottom end of this year and into 2016, the balance sheet has got to be maintained. Our company can't survive without a strong balance sheet. We can have strong assets but if we don't have a strong balance sheet that is not going to get us a whole lot.

And so, we're very focused on that, we don't have a target. Back in the day we had a target of two times debt to EBITDAX. We don't have a target but we do realize without a strong balance sheet we can't sustain the business. So that is front and center of our planning..

Your next question comes from the line of [indiscernible] from RBC Capital Markets. Please proceed..

My questions were answered. I just had one little tiny follow-up on the borrowing base.

When the banks do their calculations how far back do you think they look at the well costs? Obviously you're not going to get credit for next year's improvements, but what do you think we're looking at?.

They really look at current AFEs, so clearly when you are looking at some of your other SEC numbers and all the way back to I think the rating agencies look at the previous K which doesn't really give any credit for what has happened over the last year, but the banks look at your current AFEs..

Your next question comes from David Beard from Coke Palmer. Please proceed. .

It is David Beard from Coker Palmer. Most of my questions have been asked and answered. Maybe you could give a little bit of color relative to some midstream maintenance spending to keep production flat. It seems it would be a fairly modest number, but any color there would help..

Sure, David. We had always described in the past midstream would be anywhere from 7% to maybe even 15% of your overall capital spend. And we have no reason for that to change for the moment. Clearly we're an E&P company not a midstream company.

So the cost of us putting in midstream infrastructures, etc., is probably maybe not as good as the ability for a midstream pure player to do [indiscernible] notwithstanding all the great efforts our team have done on the operations side with the Pronghorn and 70 Ranch gathering systems and the CPFs that we're doing now.

So I think we will continue to talk about that 7% to 15% type range on the overall capital for midstream. But I think that we'll probably come down with an expert in there building out that midstream infrastructure. Hopefully that is helpful..

I would now like to hand back over to Rich Carty for closing remarks. Please proceed..

Thank you, everyone, for once again spending your morning with us. We appreciate the support you provide our franchise. And I look forward to the next opportunity to update you on progress at Bonanza Creek. Have a good day..

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