Rich Carty - President and Chief Executive Officer Bill Cassidy - Chief Financial Officer Tony Buchanon - Chief Operating Officer James - Company Speaker Unidentified Company Speaker -.

Irene Oiyin Haas - Wunderlich Securities, Inc. Neal Dingmann - SunTrust Robinson Humphrey, Inc. Phillips Johnston - Capital One Securities, Inc.

Ipsit Mohanty - GMP Brad Carpenter - Cantor Fitzgerald Michael Hall - Heikkinen Energy Advisors Mike Kelly - Seaport Global Securities LLC David Beard - Coker Palmer Institutional Welles Fitzpatrick - Johnson Rice & Co. LLC Brian Corales - Howard Weil Inc. Ryan Oatman - Cowen & Co. LLC David Meet - Morning Star.

Unidentified Analyst - Paul Grigel - Macquarie Capital (USA), Inc. Steven Karpel - Credit Suisse John Herrlin - Societe Generale. Kim Pacanovsky - Imperial Capital Marian Krishna - Nomura Asset Management. David Deckelbaum - KeyBanc Capital Markets Inc..

Good day, ladies and gentlemen. And welcome to the Bonanza Creek Fourth Quarter and Full Year 2015 Earnings and Operations Update Conference Call. At this time, all participants are in a listen only mode. Later, we will conduct a question-and-answer session and instruction will follow at that time.

[Operator Instructions] As a reminder, today's conference is being recorded. I will now like to introduce your host for today's conference call Mr. James Edwards. You may begin..

Thanks Kevin. Good morning, everyone, and welcome to Bonanza Creek's fourth quarter and full year 2015 earnings conference call and webcast. Joining me on the call this morning are Rich Carty, President and Chief Executive Officer; Bill Cassidy, Chief Financial Officer; and Tony Buchanon, Chief Operating Officer.

Yesterday afternoon, we issued our earnings press release and have filed our 10-K with the SEC; you can access both on our website. If you haven't done so already, I would encourage you to visit our website at bonanzacrk.com and 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 the call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release.

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

Now it's my pleasure this morning to introduce Rich Carty, Bonanza Creek's President and Chief Executive Officer, who will begin the call with our fourth quarter and full year results.

Rich?.

Good morning, everyone. And thank you for joining us this morning for our fourth quarter and full year 2015 earnings call and operations update. This morning on the call, we will touch on three items. First, the solid operational execution we had in 2015 despite a challenging external environment.

Second, the initiatives we have implemented in 2015 and the beginning of 2016 to optimize our base production and increase D&C capital efficiency. And third and most importantly where we stand today Bonanza Creek with regard to our balance sheet, announced transactions and outlook.

Before I dive into our operational data points, I'd like to speak to the status of the previously announced divesture of our Rocky Mountain infrastructure subsidiary or RMI as we know it.

As many of you remember, after a very competitive down select process that concluded in November, we announced that we had entered into an agreement to sell RMI to Meritage Midstream Partners, a Riverstone Holding LLC portfolio company.

Despite a dedicated process to complete the deal, the parties were ultimately unable to arrive in a mutually agreeable terms. As a result, we will not be closing as previously contemplated. In conjunction with the termination of the agreement, a termination fee of $6 million is due to Bonanza Creek.

We remain very confident that our RMI is a desirable asset to perspective Midstream Partners.

The asset that Bonanza Creek can constructed provide tangible value, underpin by approximately 1400 gross drilling locations within development distance from existing facility infrastructure and has substantial running room to grow as steel development continues.

Upon terminating the agreement, we've been released from exclusivity terms and as such are taking these assets back to market to secure a new development partner. We are focused on delivering a deal that is beneficial Bonanza Creek's stockholder for both near term consideration as well as long-term synergy.

I'd now like to start on Slide 4 to touch on a few points. Despite the challenging environment the industry was faced with in 2015, Bonanza Creek rose to the occasion with solid execution and operations.

We really began to reap the benefits of our cost cutting and rapid continuous improvement initiatives in the second half of the year which led to two consecutive quarters of guidance beats for both production volume and operating costs. We were able to exceed our expectations by continually striving to be more efficient.

In this environment it's increasingly important to drive efficiencies in everything we do. In 2015, we had initiatives in place to both optimize our base production and enhance our well design, making our field development model more productive for less capital.

We made great stride in these strategies during 2015 and plan to compound these efficiencies gains as we move into 2016 and beyond, which Tony will cover in his operational update. Thereafter Bill will walk us through our financial section and spend time on our balance sheet and the optionality that the company retain to preserve liquidity.

Moving to Slide 5, as you can see from the graphs, we've had strong execution beating guidance on both the production side and the cost side for both the fourth quarter and the full year. Importantly, I'd like to call your attention to the substantial decrease in CapEx for the back half of the year.

A testament to our ability to react quickly to be a formidable, commodity price challenges. Our total D&C CapEx for 2015 was reduced by nearly 50% from 2014 to approximately $355 million, coupled with the decrease in CapEx the company increased production volumes by approximately 15% from 2014 to 2015.

With regard to LOE and cash G&A, the company worked relentlessly to reduce these costs with both measures seen double digit declines on a per unit basis. We will continue to focus on driving this cost lower on an absolute basis in 2016.

Nevertheless, to be fair we have to acknowledge that our per unit metric begin to creep up as activity levels and production both decline in 2016 which is apparent in our first quarter guidance given our reducing activity levels. On Slide 6, here we show a bridge of proved reserves from 2014 to 2015.

It's essential to recognize the impressive positive engineering revisions we had at the company this year. Due to improved field wide performance data which displace the negative impact of slumping prices in a year when our industry experienced a reduction in SEC pricing of almost 50% year-over-year.

I'd like to now turn the call over to Tony for his operational update..

Thanks, Rich. I'll start my operational update on Slide 8. As Rich alluded to in his opening remarks and stated in our press release, we plan to reduce our activity in Wattenberg at the end of this quarter and lay down our last operated drilling rig.

As our activity moves away from drilling and completing wells, our focus will shift even more to optimizing base production. This type of work while not flashy is well designed is critical to our business in this environment.

It will help flatten our corporate decline rates and allow us to more easily inflect growth when we get back to drilling wells and developing this field. As you can see on the slide, we've started this work in 2015 and have noticed significant increases to our base profile.

Briefly walking through the initiatives, I'll start with our SCADA telemetry and automation system. This system provides real time data on things such as gas lift prate and system pressures. This data is the utilized by our operations team and helps them optimize production more efficiently.

Secondly, our infrastructure expansion has gone long way to significantly reducing downtime. With our Pronghorn gathering system and BCP's Windmill line, we have the ability to move gas from east to west giving us much more flexibility resulting in more reliable line pressures.

As you look on the slide at the production graph of our Eastern acreage which is always than more susceptible to line pressure fluctuations, you can see that the first half of the year had more volatility while the second half was much, much stable and predictable. Lastly, we've been more proactive on our interventions of our existing wells.

Implementing low cost, quick pay up projects such as optimizing plungers and rod pump install helps well overall cost and offset natural decline. In all these initiatives resulted in a performance uplift of around 15% on our Eastern acreage from our expectations at the beginning of the year.

These relatively low dollar investments to our field will help us recover the most out of our existing well bores and will continue to be a key focus for the company in 2016. While our plan is to temporarily idle development activity, we still stress the need to continually review and improve our well design.

Our operations team work diligently through 2015 and into 2016 trying to get the most out of our rock for the least amount of capital. On Slide 9, we've laid out the three main changes to well design that we've implemented over the last nine months or so.

First is the increase the sand loading? We showed some initial data during the third quarter call in 2015 showing production uplift from this increased sand and I am happy to say that we continue to see this trend increase as we go out over 480 days of data.

Even in this pricing environment, adding sand to our conclusion is an easy decision with the short payback period of around four months on the incremental investment along with the expected increase in ultimate recovery. The next change is moving to Mono-bore.

While this change doesn’t necessarily help performance of the well, it reduces the amount of drill time and cost of casing. All while retaining the same integrity and safety of the well bore. As of this morning, we've successfully executed seven Mono-bore wells. Our third design change is the recent move to Plug-and-Perf.

Up until 2016, we almost exclusively use sliding sleeves but as we moved our design to Mono-bore we found that Plug-and-Perf was a better suited completion technique. As we are drilling all of our wells on pads, we are able to gain some efficiency with Plug-and-Perf that result in fairly similar well cost when compared to sliding sleeves.

While the ultimate decision to move the Plug-and-Perf was its ability to aid Mono-bore execution, we've reserved uplift in early time production from the first Plug-and-Perf wells that we executed. The following two slides show some details on the results that we've seen with increased sand loading and Plug-and-Perf completion.

But -- while I don't plan to spend time walking through each of these slides, I am happy to answer any questions you may have regarding these during the Q&A session at the end of our prepared remarks.

Before I finish I want to walk thorough our well cost which are shown on slide 12 where we show our progression of cost from our last earnings call to where we expect cost to go in 2016. The largest jump from 3Q to our current cost is due to infrastructure.

Currently, the assets we have operating within RMI can accommodate 1,400 additional legacy area locations, which means our 2016 program and programs for the following years following 2016 will not need any additional field level infrastructure build up regardless of an RMI sale.

The remaining reduction to well cost come through the changes to well design that I went through earlier as well as cost concessions we've received from service providers. So with that I'd like to now turn the call over to Bill..

Thanks, Tony. Good morning, everyone. To get going, I will direct you to Slide 13 to cover our financial position at yearend. At the end of 2015 we had $79 million drawn on our revolving credit facility with cash on hand of $21.3 million.

We have a letter-of-credit of $12 million to the State of Colorado as part of our Hog Farms acreage acquisition in 2012, which will be paid fully in July. Since yearend, we have not drawn further on our revolving credit facility and remaining with $79 million drawn and $20 million of cash on the balance sheet as of close of business yesterday.

The current borrowing base of $475 million as part of the revolving credit facility gives us liquidity as of December 31 of $405 million which is a same today.

As you can see in the bottom left chart, we were clearly within the credit facility covenant of Q4, 2015 with secured debt to trailing 12 months EBITDAX of 0.3x, trailing 12 months EBITDAX interest of 4.8x and the current ratio of 3.5x, all well within the respective covenant levels of 2.5x and one time.

It is also appropriate to emphasize that we have now unsecured debt maturities under 2021. With the weighted average coupon of high end notes approximately 6.38%. A few other accounting items of note. Our effective tax rate for 2015 was 18%, much lower than the prior year raise of 38%.

This large downward variance was due to full valuation allowance that was placed against our net deferred tax assets which accounted for the 20 percentage point reduction in our current year effective tax rate.

On differential, we expect the Rocky Mountain oil differentials to be WTI less $8.50 range while we continue to receive approximately WTI less $1 pricing per barrel for our Mid-Con oil. We had some noise in Q4, 2015 numbers for gas and the Rockies and NGLs Company wise.

Going forward for gas we expect to continue to see 75% of Henry Hub in the Rocky Mountain and approximately Henry Hub in the Mid-Con. For NGL, we expect to see 25% and 35% of WTI in the Rockies and Mid-Con respectively.

With regard to the financials is probably not surprising to most that we had a sizeable impairment in the fourth quarter which was a result of lower pricing. Moving on, I want to go through our outlook for 2016 which I laid out on slide 14. Our current plans for the year are to finish our operated drilling program of 12 wells in the first quarter.

And then idle our drilling and completion program until the time we have either executed transaction for our Midstream asset or see material changes in the macro environment. While the operations team will be focused on optimizing our base production, our business development team is focused on remarketing the RMI assets as soon as we can.

We are now able to reopen talks with other interested parties. The DJ basin has some of the most attractive return to North American unconventional with the significant growth opportunity provided by this basin, infrastructure will play a key role.

Over the past few years, we've invested in growing this Midstream asset base and are now seeing the benefit by improved performance and EURs across our field. The current environment has directed us to sale where in the past we would hold bill and control the asset further into the overall field development.

With this economic growth opportunity, we are confident that we would be able to find a partner for the RMI assets at a price that would benefit both Bonanza Creek and the acquiring party. In addition to RMI asset sale, we will continue to work our process with the Mid-Continental. With that I'll pass the mike back to Rich for closing remarks. .

Thanks, Bill. In closing, I'd like to reiterate the strong operational execution we have throughout 2015 and into 2016 to become a low cost operator in the Wattenberg, while pushing technical innovation to get the most from our reservoirs.

Though 2015 was a commendable year in a very tough environment, we need to look forward to 2016 to position the company to survive and what looks to be an increasingly difficult year ahead.

While we've been faced with the challenging set of circumstances and our decision to idle activity was not an easy one, it is the correct decision for the company right now in this pricing environment as we look to preserve liquidity and optionality.

I assure you that this management team will leave no stone unturned to see this through and emerge on the other side of this downturn doing what is best for the long-term shareholder, to enhance and preserve our shareholder value. With that I'll turn the call over to questions. Thank you very much. .

[Operator Instructions] Our first question comes from Irene Oiyin Haas with Wunderlich..

Yes. Hi, good morning, everybody. My question for you is it is probably not going to be easy to answer but would you have a feeling as to how long you can reactivate this home sell business and be able to wrap up.

Are we talking about three months, six months so just a little feeling on the timing and similarly for the Mid-Con asset because that's quite crucial to the company now?.

Hi, Irene. As you expect reactivating the RMI process is not difficult for us at this point. We've been through considerable work in that over the past four months. So effective this morning, you can treat that as a live process. And the completion of which we think should be facilitated by a lot of the historical work we've already accomplished.

So we feel pretty good about that process. Likewise with the Mid-Continent process, although we can't talk about these things that are occurring at this moment in time, we also have some confidence that we will see that through in the near future for the benefit of the stockholders..

Are we -- could you give us a little visibility on timing, are we thinking about three months, six months just so that we have a some visibility?.

Yes. I think we could say with confidence that we should have visibility in both of these in the second quarter. .

Our next question comes from Neal Dingmann with SunTrust..

Good morning, guys. Say Rich just wanted sort of getting our own idle done in the near term just thoughts on macro environment what you would have to see that think about bringing at least maybe first of all completions that start back with implementation and then secondly with the drilling operations. .

Good morning, Neal. Thanks for the question. Ultimately when we look at the asset, the timing of development of asset is critical. We've got $33 oil in the near term and$39 and $40 oil as soon as December. So if we are looking to maximize value for stockholders we prefer to put these volumes in December than we would to produce them in March.

So timing is focused on maximizing shareholder value really. And to the extent that we have visibility on prices and cost where we can make a case for reestablishing activity will be very rational what's they are doing..

And when you come back is it makes sure I have this right, just a number of ducks that you'll have is it in addition to just the 12 that you will drill, and will you have seen some other that you build to come back too quickly if you like. .

Yes. Hi, Neal. This is Tony. We'll have seven basically seven ducks ready to go when we finish up our drilling program. We'll have seven wells that would be left uncompleted. .

Got it .And then Tony just one follow on my last question is just now with the deployment and your thoughts now about doing going forward Tony would be mostly just XRL type wells or how do you think about the extended reach versus some of the others two previously we were doing..

Yes. Neal, we like the extended reach lateral wells and as we move forward our drilling program, we continue to focus on maximizing extended reach lateral wells as part of that program. Again probably the only driver that puts us back in the standard reach lateral world is again leveraging that infrastructure.

Now leveraging that infrastructure really does reduce cost and wells most focused on our western part of legacy acreage where we started our standard reach lateral development several years back. Obviously, that's where we still have some standard reach lateral development.

But again those economics are very strong because it would be leveraging the infrastructure. .

And I guess sorry one last one Rich.

Is there a cover bed you can come back to or is just or you are going to have just completely remarket this?.

Well, if you recall Neal we had a really competitive process for this asset throughout the summer which culminated in the transaction announcement with Meritage Riverstone in early November. So this wasn't one party picked out of the air. This was a very robust process. We've a lot of confidence, we could re-catalyze affected immediately. .

Okay. .

Neal, its Bill here. And we had probably 20 plus interested parties in this transaction when we went through it in the summer.

We know that going to six parties which we worked on NDA and bottom ended management presentation as you can imagine its pretty involved process, getting visits done et cetera so I am, we've already been feeling calls over night on interested parties coming back and some of the parties that were there before and some new parties. .

Got it, guys. Thanks for the additional details. .

Our next question comes from Phillips Johnston with Capital One..

Hey, guys. Thank you. Just looking at the first quarter production guidance, it implies about a 17% sequential decline from the fourth quarter or seems pretty late considering you're planning on 12 net wells completion in Wattenberg which I think is a pretty flat versus Q4.

Is that a function of weather impacts or Midstream issues or any sort of other transitory issues that have happened so far in the quarter?.

Hey, Philips. No, probably the biggest portion of is that the pad timing itself. In fourth quarter we had two seven wells pad come online early in fourth quarter that drove production for fourth quarter.

They peaked during fourth quarter and those two seven well pads are now entering in that steeper portion of their decline curves as they come off their peak rate. So that was rolling into first quarter. And then the pad timing for first quarter of 2016, our first pad in 2016 which was a five wells SLR well pad didn't come online until late January.

Our second pad which is a four well MRL pad came online here in mid to late February. And then the third pad comes on mid March-ish. So the timing of that -- we basically had a two months highs on production from new wells basically through December and January actually late November through January with no new well production.

And then again those two seven well pads being in there steep and portion of decline rate of their curves impacting that in first quarter. .

Okay. That make sense then just on your reserve at last year you booked 12 million barrels of extensions and discoveries, seemed to little late relative to $350 million of upstream CapEx sort of implies around $30 a barrel of drill with F&D cost.

My question is can you provide us with the average -- that -so gave credit for in the Wattenberg, and were there any significant differences between those EUR booking for your PDP reserve as versus your PUD reserve?.

We didn't have any significant difference between our PDP and our pad. If you consider our positive engineering revision, there are some PUDS that actually roll into that category. So we only added about 17 PUDS in the 12 million Boe that you are looking at for capital adds.

So that with 63 wells that we drilled and completed during 2015 in just 17 PUDS. So a lot of the positive changes in our reserves are actually fall into the engineering revision category. So we had actually slightly increased our PUD reserves and we have a very small variance to our third party auditor. .

Okay. And those positive performance origins were the -- that's the 10.8 million barrels that lists in the presentation. .

That rolled into the 10.8 and it is also a factor in what we've referred to as a revision associated with drop in CapEx because we had both drop in CapEx and increased performance, the two of which together pulled most of our PUDS back into the group reserve capital..

Our next question comes from Ipsit Mohanty with GMP Securities. .

Hi, good morning, guys. Tony just picking up from where you left in terms of the timing of completions in 4Q but most specifically in the 1Q, it looks to me that you are still bringing on a pad towards the end of the month, end of the quarter and if you just stop drilling then you could probably see steep decline going forward at least in Q2.

So just thinking over the rest of the year that assuming for now that you just see drilling and trying to understand the trace of optimizing base production. If you can provide some color please. .

Hey, Ipsit. Appreciate the question. As for guiding for the rest of the year, obviously we are not doing that right now from full year guidance. We do have some new pads coming online in first quarter and we expect those wells to perform similarly so if they come off we will see some decline rate.

So I can't really guide a second quarter but you can see with the timing as we brought those pads online late January, middle February, middle March. We can have a nice even distribution moving into the quarter but we have to see what those decline rates as they fall of when they go into their tight curve declines.

And we will see what that looks like. But again we are not guide to full year. .

Okay. And then switching over to the Mid-Con, in my understanding it seems like you averaged 5,000 barrels but if our 4Q but the 1Q guidance again looks as if that's going through a steep decline as well. If you can care to comment on that. .

Ipsit, I think it's James. We didn't breakout the Rockies versus the Mid-Con piece if you think to in the K we show a 40% PDP decline rate for 2016 with that 12 wells that growth in the beginning. So we are not exclusively guiding full year 2016 that should hopefully guide you in the right direction. .

Okay. And my last one for Rich and other guys.

When you think about putting Mid-Con assets on the block, how do you feel about putting declining assets on sale? Any color you can provide and then just what's helping you to think that you can get a good value?.

Well, some of the benefits at the Mid-Con asset Ipsit include the fact that it is an integrated business. So it is a monopoly processor in that jurisdiction so any offset operator with the gas production has to go through the plant. The gathering system we have is also very valuable.

And the asset itself had lot of PD&P re-complete which from a capital perspective at these prices are still very valid in terms of a capital deployment.

So does have an effective way of conveying preservation of the value because of the incumbency and the jurisdiction plus a way to deploy capital even if it's a modest way through the down part of the cycle. So it is an attractive asset with tight differential to WTI..

Our next question comes from Brad Carpenter with Cantor Fitzgerald..

Hi, good morning, everyone. Just a few quick ones for me. Just curious if D&C operations are halted after these 12 completions from the first quarter.

What's a good quarterly run rate for CapEx that we should be using?.

I think we've given you the first quarter CapEx at about $40 million as guidance so we are not guiding anything else beyond the first quarter.

So I think we should probably hold off as we get more clarity as we said on the Midstream divesture and then also on the macro environment, we will come back and give further updates and kind of our capital goal through the year. .

Okay. Alright. Fair enough.

And in the DJ you noted that the improve line pressures resulted in increase of about 15% in cumulative first year production of 2015 vintage versus 2014, I was curious if you are seeing any variation in the GOR between those two wells and obviously what I am trying to get out is, is that 15% improvement mostly on the gas side or is it pretty much one for one gas to oil and NGL I guess as well..

Yes. No, I'll tell you what it is pretty much equivalent to what our normal production make up is. We are not seeing like a big breakout in gas versus oil. It's very similar to what our normal breakout is. .

Our next question comes from Michael Hall with Heikkinen Energy Advisors..

Thanks. Good morning.

So kind of maybe along the similar line as Brad just curious around any leasehold maintenance consideration to keep in mind as we move through the rest of 2016 beyond first quarter's activity?.

Yes. Michael, no, this is Tony. No, very minimal leasehold basically almost our entire acreage position is HBB so we have no issues with leasehold, we don't have to spend pretty much money, very little at all on that in kind of leasehold. .

Okay.

And that includes the northern acreage that someone recently purchased?.

Yes. That's correct. Northern acreage, southern acreage and of course our legacy position, all inclusive. .

Okay.

And I guess I caught some of it but what is the composition of the 12 wells in terms of I guess lateral length and location across the acreage and reservoir?.

Well, the locations of the wells are in our legacy position. So they are both in the western and eastern part of our legacy position and the make up of the wells we have five SLR oil pads that just came online. In January, we had a four well MRL so that's about 7,500 foot lateral length pad that came online in about the middle of February.

And we have a three well standard reach lateral pad that will come online in mid March..

Okay. I saw the 40% decline in the 10-K, it's helpful and in your disclosure you provide, can you quantify how this base production optimization might be able to impact that 40% or is any of that optimization already contemplated at that 40% figure. .

I think the base optimization is starting to flow through in our reserve as we have moved our PUD reserve curves on our eastern legacy position which is -- where a majority of that work is taken place. We've been able to move those reserves upward for the past few years. So we are seeing that.

I think going forward continued base optimization will continue to flow through the reserve basin and hopefully we can continue to move those curves in the upward direction when we look at it from an SEC standpoint. .

Okay. So maybe more of impact as we make our way through the end of the year and you flat into 2017 profile as opposed to 2016. Am I hearing that right or --.

Yes. I mean that's definitely a possibility. Obviously we have to have the data flow through the year and when we look at it but we continue to see the results we are seeing from the base production, maintenance, the consistent line pressures, I mean that is a definite possibility. I can't give you number right now.

We got to get date into to measure that but it's a definite possibility for sure. .

Okay. I guess then a last on my end is just curious have you all had any discussions around revolver re-determination with the bank as time it is forward, ratio -- clearly change around the covenants and just curious what sort of discussions you have been had in that context around the committed amount. .

Hi, Michael. It's Bill here. We have ongoing discussions with already with our agent bank kind of on a regular basis as well as other banks.

And we will just move to our normal end timing kind of April, May timing and moving obviously lower price stock lower volumes, you are going to see a cut in the overall availability but we don't see any other reason to accelerate that given where we are today. So we will just continue to have that discussion as normal..

Our next question comes from Mike Kelly with Seaport Global..

Hi, guys. Good morning. Rich I was just kind of hoping to get some more color what went south and the negotiations with Meritage. And I am not Midstream expert but obviously commodity prices haven't been in your favor but what specifically kind of spooked these guys and made them want to back out. Thanks. .

Hi, Mike. Listen we are not authorized to speak on behalf of Meritage or Riverstone, but I'll just say that their actions speak for themselves.

But ultimately we won the contract, we had robust process in August, September, October with a number of parties in a down select full disclosure material, data reviewing access, engineering dataset for which culminated and that's going to contract with them.

And ultimately I can't speak for the investment community but they elected not to come to agreeable terms in the end so we've terminated that contract. .

Just looking at the high level those just can you point to the commodity price really been is a big driver there. I guess I am trying to get at is remarket this and maybe it's in lower crude environment, lowered gas prices, how we should we think about the -- how the value that asset is changed.

You got a pretty good deal with these guys and how close can you come to and ultimately if you repackage it during the second time. Thanks. .

Again I can't speak on their behalf but let's just review RMI for a second. We have a lot of convictions. This is a very, very valuable asset.

So if you look back in our 10-K just the raw materials that we used to construct this asset in 2015 have across book value of $106 million bucks that stuff like tank battery separators, cabin systems, pipes, tubular, flanges, right down as nuts and bolt.

That $106 million bucks and raw material us superimposed upon in our project level leasehold that covers an upstream resource with 1,400 gross locations in a highly contagious acreage position. That represents over $35 billion in future upstream development capital associated with that asset.

And the assets are 100% held HPB, is a very well understood and delineated. We have over 400 horizontal producer wells in that area helping to de-risk the asset. And then the economics of the contract are supported by a life field monopoly incumbency.

So the leasehold dedication and service contracts are effectively an incumbency that persist that as covenance running with the land. So this is not a corporate level security interest, it's a land or lease level security interest. And is a very, very attractive asset for Midstream parties.

I think we leave it at that and we'll look forward to engaging with new parties in the process as we catalyze out today. .

Okay. Maybe I could just ask kind of one direct question on that. I mean is there anything in your mind that happened Since November that materially impairs that $255 million price that you originally got. .

Well, we have conviction that as time moves on the value of asset goes up. Now what's happening in externalities and capital market the NLP space, the infrastructure space, the midstream business industry, those are things we can't control obviously.

And so we are subject to vagaries in that area but unless you think oil is 30 bucks for the next 20 years this is a highly valuable monopoly position in a highly productive basin where there is only two other incumbents which is Anadarko, western gas resources and the Old Duke Conoco Phillips DCP, so it's valuable position for somebody. .

Our next question comes from David Beard with Coker Palmer..

Hey, good morning, guys. I know you talked about corporate decline rate of 30%, I am obviously coming at the same issue about the production guidance and where we might end up. Is that still valid when we think about what are you doing in the first quarter and how should we think of that number now in context with the completion you have onboard. .

Again, I think that 40% decline rate is what we've got in our 10-K, I would stay with that. There is nothing that changed from that. I think I walk through our completion schedule.

We have those pads online and that last pad coming online in middle of March would be our pad for the foreseeable future until we picked up back up activity as we will have those as I mentioned earlier the seven ducks will have waiting for completion but that will be pending when we make the decision of bringing those online. .

Okay, yes, 40%, that stands corrected, thank you guys. Appreciate the time.

Our next question comes from Welles Fitzpatrick with Johnson Rice..

Hey, good morning. Most of have been asked but obviously big drop in SRL cost quarter-over-quarter.

Can you breakout of infrastructure verse design versus the cost components in those savings?.

Hi, Welles. Big driver on the cost again is the infrastructure piece. I think we step you through coming from -- see what we got near, slide 12, I apologize for that slide 12.

So looking at those cost what we came out 3Q, 2015, you are aware that $3.4 million that we moved down to our current well cost of $2.6 million, a great majority of that probably I am going to say more than half of that's going to be around utilization of the infrastructure.

And then the other pieces of that are going to be in the cost reduction that we were seeing from our service providers. So that's kind of the driver there going into 2016, we started to execute the mono-bores and so that's kind we've already realizing that so that get you that about $2.5 million. So that's from the mono-bore execution..

Okay, that's perfect. Thank you. And just one more and I am also by no mean an expert on pipelines. But the contract is running with the land does then bank group -- do they get to have any say as to what's executed sense essentially will go with the asset regardless. .

Welles, as it stands those assets are part of our company's assets in a collateral pool existing in a business and all that collateral is sub service collateral, the service facilities all that would effectively become a lean or accessible by a firs lean creditor in terms of how that would manifest after a sale specific to any prospective sales.

But it is lease level covenant running with the land. So it's not a corporate liability or asset, it is lease level asset. .

Our next question comes from Brian Corales with Howard Weil..

Good morning, guys.

On the Mid-Con asset, how much of the revolver is that -- or is it a big portion of the revolver?.

Brian, we haven't broken that out so and we are just kind of we will kind of be mute on that at the moment. Obviously it is proportional to the size of the production overall so yes.

That's fair. Okay. Thank you. That's helpful. The northern acreage that well I guess the delineation well, is it just the bad well or is your thoughts change on the acreage, can you maybe expand on that. .

Hey, Brian. That first well we drawn on northern acreage delineation much further than north up there in 762, when we drove that well it's 9,000 footer but we had three seismic up there but as with any debilitation well you go and drill it. We crossed the fall but halfway through and put that well into eight mile, we went and complete the well.

Actually we are pretty encouraged with the results based on that half of the wells eight mile which is really not productive. At the end of the day, we are going to take that data. And we can now come back and correlate after the seismic that we have and tie that back in.

And we can improve our landing point and make sure we don't get into the eight mile when we drill up there again so.

At the end of the day, I think we are forecasting a little over 400 MBoe equivalent recoveries when you taken to the fact that we have not -- that we didn't complete eight mile part or we did but we are not getting any production from that.

When you factor in that we can come up there and do larger frac, the 1,500 pound, this well is not completed but the larger fracs and also with Plug-and-Perf, at the end of the day I think it's a great starting point for the northern acreage, as we did on our eastern acreage the first wells when we step that on eastern legacy couple of years ago, those first wells we stepped up.

We have lower performers if you will, but we figure it out and improved performance significantly. I think we are at a good starting point at further northern acreage and for I would say I am still very encouraged by the acreage and I am looking forward to getting back up there and drilling and put in some larger frac.

Obviously the question is going to be around timing of that as we look at our 2016 program kind of ramping down temporarily. .

Okay. And then maybe just one final one.

You covered this a lot but I guess if you get some resolution or some kind of announcement you call to second quarter sometime, we call mid year, if there is cash from the door is it merely put back, are you going to put a rig back to work or do you also need to see higher commodity prices or is it just kind of we will see how it stands in the market.

What's your thought?.

Brian, so let me just rephrase the question if I may just what's going to drive our decision on increasing activities, is that the question. .

If you get the asset sales done, yes, I mean --.

I think it's pretty clear that in the case of RMI for example that our partnership with a Midstream our infrastructure player would encourage us to restart activity and to develop the feel and conjunction with that Midstream transactions. So that would be an important data point for us.

And like wise better prices would encourage us to restart activities as well. So we are poised and ready so if that these prices as ever one concede not an attractive environment to deploy capital. .

Our next question comes from Ryan Oatman with Cowen & Co..

Hi, good morning. A few quick questions for me. I just wanted to make sure my estimates are apples-to-apples.

On the guidance it is on line item for midstream expenses of about $2.30 a barrel, in the event the Rocky Mountains infrastructure asset is not sold, would those charges still be incurred?.

Yes. And -- yes, they will surely encourage. .

Okay.

And then just to clarify on the 1Q production guidance that does or does not include the Mid-Continent asset?.

It does include the Mid-Continent asset. .

Our next question comes from David Meet [ph] with Morning Star..

Hey guys. Most of my questions have been answered. Just a quick one thinking longer term in a better commodity price environment and with less capital constraints, is there any reason to go back away from the new model board design you are talking about and back to where what you were previously doing. .

No. The answer to that would be no. We think the model board design; those cost savings would be something we would take with us in current price environment or even a higher price environment. And we think if you continue to successfully execute those they provide a lot of flexibility going forward upward construction.

So we would not go with Mono-bore design. .

Our next question comes from [indiscernible] Oppenheimer. .

Hi, thank you for fitting me in.

Bill or Rich, maybe it is follow up it is one of the other questions here but if you were to assume no midstream sale in the strip plays out can you kind of talk about how you think about spending priorities, I guess one would you think about or what price would you need to see in order to bring back a rig in the Wattenberg and if you kind of assume that the strip does play out, how do you think about free cash flow and what do you use that for?.

Yes. I think the thought process on bringing a rig back in the Wattenberg would really kind of depend on our task goal is as prices as the curve kind of starts to moving back up. Until we have better visibility on our RMI and our Mid-Con I think it's really capital preservation and preserving liquidity.

And so we can have more visibility on those transactions. So really don't have kind of a timeframe for you, we just need to see how these transactions progress over the next three to six months so..

Okay. So that's fair. So I guess in the interim -- if there is kind of any free cash flow out there it would be fair to assume you using that to pay down like credit facility. .

Yes. So again it's just to maintain liquidity. .

Okay. Make sense and then maybe just thinking about if you were to get an RMI deal done with decent amount of cash proceeds. In your mind is there anything within the credit facility as it stands today that would prohibit you from using some of the cash proceeds to repurchase the unsecured debt in --.

Yes. If you look at there is restrictions on repurchasing debt in the K. So we would keep that cash on our balance sheet or pay back to the banks. Paid on or revolver. .

Okay. And if you were to fully pay off the revolver with proceeds after that do you think you could use that money to prepay or repurchase debt. .

I guess we got optionality as to what we would do with the capital and it would depend on the price environment. The commodity price environment at the time. And it's kind of where the bonds are I think so..

Our next question comes from Paul Grigel with Macquarie..

Hi. Good morning. Just a one quick since most have been asked. You guys have spoken to the 1,400 locations around the RMI area. Is there any ability to add additional volumes to the RMI asset given the current commodity price outlook or would you need a better commodity price in order to grow the volume at RMI. .

Hey, Paul. Listen the RMI is effectively a dedication to all of our non dedicated acreage in the Wattenberg. So it would be considered a life field our development partner from Midstream infrastructure perspective. So to the extent that we increase activity those benefits would accrue to that midstream asset. So I think they are defined that way..

Okay.

Is there any rate of return that you guys could project on what maybe legacy acreage either short, medium or extended reach lateral would provide at either strip or $40 deck?.

I don't think we've published returns on the strip currently. What I can say is that we do still have economic well to develop. The issue for us Paul is not the IRR on the wells but obviously the cash payback in the well, so do you have just to throw a number up in there.

So you have a 15% return on a well that still requires you to put money upfront in order to earn that 50% return over a period of time. So it's still a leveraging decision. And at this point in time, we would like to preserve our ability to develop locations at a point in time when prices are offered by the returns for our stockholders. .

It is understood.

Is there a cash recycle rate or payback period that you guys looked to as a critical level?.

We have drawn a bright line for that no, it's a case by case decision as we move on. .

And I think you got to take everything into account here and into the overall liquidity, right, so it's not just returns, it is liquidity in long term or you are going to be coming out at 2016 and into 2017 et cetera so--.

Our next question comes from Steven Karpel with Credit Suisse. 0:55:14.3.

Good morning.

I want to understand again maybe some more clarity around the HVP issues in your -- on two sides to provide capital to some of your existing base, what's the ability to give for those that you maybe have provide some capital to renegotiate some leases whether it's continuous drilling or continuous production given the realization you are seeing on the gas side.

And then secondly how much non optic drilling that you have in 2015 and then put that number in 2016..

I'll go ahead and start off Steven with the acreage position the HVP. And again a great majority of our position is already HVP and in 2016 and 2017 we have very small requirements to maintain that leasehold position. So we are talking less than $5 million total probably for 2016 and 2017 to keep tha acreage positioned together.

And so we don't have an acreage situation that we have anything getting away from us and so we don't have to drill any wells to maintain any acreage. So I hope that answers back pack part of the question. The next part of the question I will answer.

I may not get these in the right batting order but I'll take him as I remember as you have them is what kind of non op activity are we expecting in 2016.Quite frankly, we are getting non op proposals in but as look around the basin and I see rig counts dropping, I am not sure how much activities actually going to really take place.

So I would expect a minimal number of non op actual projects that will come forward in 2016. And looking back in 2015, non-op activity that we had as we participated in seven PUDS in 2015, so fairly minimal activity. And that resulted in 1.8 net--ell net on that. So I don't know if I caught all your questions but that’s at least start. .

Alight. And then probably through Bill jut to understand kind of hopping a little bit on the revolver point.

Can you talk about how big you need and then more specifically the way your covenants are written in the other documents, does it provide for full access in 2016 and 2017 for your current borrowing base size if presumably the banks granted you the same borrowing?.

Yes, look I think we all expect the borrowing base will be reduced and there has been re-determination and whatever is provided by that re-determination I am sure that will be available and what we have seen in the market with some of the re-determinations and some other quest for covenant really for et cetera has been anti cash hoarding so if folks would not have the ability to drawn everything in down but we will work with the banks as we start moving forward and the next re-determination season and business as usual on that side.

.

And just to clarify I understanding of course on the -- with the banks too on the bond side.

Anything in the bond that would limit the size as your PV10 value is adjusted?.

No. We have a pretty covenant license and bond indenture So we should really have it --we have about $300 million, greater of $300 million, 35% of bank note. Right now the moment is like about I think its $750 million something like that right. So it's above $300 million. .

And the $300 million compares to your current I think 475 if my numbers are correct. So should we be concerned that if the banks provide a borrowing base greater than $300 million that you wouldn't have access then nor may I misreading your comments that you are making..

Can you go through that question? I am sorry. .

I thought I heard your question was that or your answer to was that you said good rate it was $300 million and the borrowing base is greater than $300 million today. So does that mean if that continues to be the case that you wouldn't have full access to the borrowing base in 2016. I don't want to mischaracterize your comments. [Multiple Speakers].

Will have a full access to our borrowing base as it gets re-determined by the banks..

So the $300 million guide post we shouldn't be concerned about in the bond and interest that you are referring to. .

No. That's we are going to -- we should make concern about that, that's over and above what we would be allowed on the borrowing base. Additional $300 million is what we would be allowed above the borrowing base..

Our next question comes from John Herrlin with Societe Generale..

Just one quick one on RMI which you sell it just straight up and not go for carry or was a carry one for sticking points. .

Hi, John. It's Rich. There is no carrying involved, it was $255 million bucks, $175 million upfront with $80 million bucks incentive in the back end as Ridley instructed back in November. Listen, we are happy to work with new mainstream partners and contact that make sense for them.

So we are open to suggestions and how to think about asset as you know when we started the process in Q2 or Q3 of last year, we were originally focused on JV, that JV transition toward an outright sale of the asset. And so we'll see how that develops over the course of the second quarter. .

Our next question comes from Kim Pacanovsky with Imperial Capital..

Yes. Just one quick question on the evolution of the well cost here. I noted in your slide deck from November the XRL well cost including the incentive for RMI were$3.5 million. And then you had them $3 million in December slide deck and now with our RMI your goal is $4.3 million.

So that it just seems like a very big gap between the last published $3 million which included the incentive. Was the incentive fact rate that much greater for an XRL and then for SRL.

Yes. Those incentives that we are talking about Kim, it was with over $1 million for an XRL incentive.

So that's the biggest driver, that was the $ 1 million and then the remainder of the cost going down to the $3 million which will be now equivalent of $4 million is really around we are going to make an adjustment to our frac design, going to larger slick water and less gel in our hybrid frac.

And so that would have taking you right down to $4 million revolver cost and then take off that million dollars with the incentive brings you down to the $3 million well cost. .

Our next question comes from Marian Krishna with Nomura Asset Management..

Hi. I guess I just wanted to go back to the credit facility discussions and I understand the lot of questions has been asked.

But I guess if you are showing compliance currently but as we can run some projections scenarios and show you auto compliance so why not just initiate that discussion a bit early when was the bank more actively rather than waiting till like the normal season to talk to the bank. .

Yes. We are in constant discussion as there with the banks and they are fully aware as to where covenants will go on.

And we took action in the spring re-determination last year to move from a total debt to EBITDA to a senior debt to EBITDA, and we will take action as we move forward with the banks on whatever covenant relief we need in this spring re-determination and we are in active discussion on that..

Okay.

And is there also interest coverage test correct?.

Yes. That's right. .

Right. Okay and then we've seen kind of across the industry a number of like borrowing base cuts within 25 -30, I guess that was the common kind of percentage.

If you kind of compare bank price tag and the reserve report is that consistent or is it low or high number to use in our modeling?.

Look, I think at this stage of the process it's tough to speculate on that. We will just work for the banks and work with our reserve engineers and then we will see where we come out. We've a very open straight forward dialogue with banks over the years and we will continue to do that going forward.

So I can't really speculate as what percentage it is going to be at this stage. .

Okay. Okay and then just to go back to Steven's question because I think there was something lost in translation there. I guess the bond and debenture provides for the secured basket carved out which is percentage of ACNTA,.

35.

Right. So as that decline because PV10 value decline substantially so would you be able to access your credit facility fully at whatever number it's re-determined according to their covenants in the bond indenture.

Yes. We'll have access to our credit facility as against re-determination, thankfully with our bond indentures are. The bond indentures provide for additional capital above and beyond what we have on our secured bank facility. So we don't expect any issue with accessing our bank borrowing base when we get that re-determined..

Our next question comes from David Deckelbaum with KeyBanc..

Good morning. Rich, Tony and Bill thanks for taking my questions. Good and my condolences on the RMI process so far but hopefully some better days ahead.

Just back to the PDP decline rate, is that an internally generated number is it risked and could you comment on how you are performed in 2015 vis-à-vis your original PDP decline projection for 2015?.

That PDP decline rate is internal and it's based upon our forecast of PDP in our SEC work for yearend. So it's not either conservative or optimistic. It's just based upon SEC guideline. .

And do you know how your PDP performance compared to what your estimate was 2015?.

Of the top of my head I couldn't answer that but we can certainly get back to you on that. .

Fair enough. Turning on the 1,400 locations you talked about that.

Was in and around existing infrastructure? How inclusive are those 1,400 locations of XRL? Or how amenable are those locations XRL development?.

Yes, David. We haven't provided a total count on that. When we look at our PPP that we provided everybody, it's on SRL equivalent.

But what I can't say is that obviously the Eastern acreage got more -- it's more conducive to external reach lateral because it's less developed, the western acreage is less conducive because of the starting of the 4,000 laterals there.

But we can still fit XRL in there but to give you percentage right now probably can't do that but again eastern acreage is much more wide open on that. And that would be going into the existing core CPS that we have. Obviously any other builds out to the north and then further to the south would be almost exclusively XRL development. .

I can appreciate that. I think I was just curious I thought your comments earlier you had said that XRL would be the priority I guess. If there was capital available to go out there and redeploy, no, if you are drilling -- yes, Tony.

Yes, David. I am sorry. That is absolutely correct. I did say that and that would be, if we go back to drilling we will maximize the XRL development of our program.

I do want to emphasize that SRLs are on the western part of our position going into the infrastructure that we have there are very competitive to XRL because again we have sound performance and the infrastructure piece is still a major driver in the economies going forward compared to what you get out of them sale and so you will leverage FO but again we would still have room to put SRLs in there and that would compete there favorably.

.

Thanks for the answer Tony. Just the last one for me is on the 2016 guidance. Do you all intend to give out full year guidance or is it basically going to be quarterly until one of the asset sales is consummated or commodity prices improve. .

David I think you hit the nail on the head. It's going to be quarterly as we move towards we see further visibility, commodity prices for the year. So I think its right for us to give the quarterly guidance when there is uncertainty in it where we are. So we will work on the asset sales and we will give more guidance as we get through there. .

And I am not showing any further questions at this time. I'd like to turn the call back over to our host. .

On behalf of the company thank you very much for dialing to our call today. Look forward to following up if you have any follow up questions. And we wish you best of luck in this market environment. Thank you very much. .

Ladies and gentlemen, that concludes today's presentation. You may now disconnect. And have a wonderful day..