Civitas Resources Inc (CIVI) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Bonanza Creek fourth-quarter and full-year 2015 earnings and operations update conference call.

(Operator Instructions)

I would now like to turn the conference call over to 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 Office; and Tony Buchanon, Chief Operating Officer.

Yesterday afternoon we issued our earnings press release and filed our 10K 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 10K 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 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 the 60 minute call. Once again, if you like to reference our IR slides please find the updated deck at our website on the investors section at Bonanzacrk.com.

Now, it is 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 at Bonanza Creek with regard to our balance sheet, announced transactions and outlook.

Before I dive into our operational data points I would like to speak to the status of the previously announced divestiture 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 Holdings, LLC, portfolio company.

Despite a dedicated process to complete the deal, the parties were ultimately unable to arrive at 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 RMI is a desirable asset to perspective Midstream Partners. The asset that Bonanza Creek constructed provides tangible value underpinned by approximately 1,400 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 have 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 to Bonanza Creek stockholders for both near-term consideration as well as long-term synergy.

I would 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 volumes and operating costs. We were able to exceed our expectations by continually striving to be more efficient. In this environment it is 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 strides in these strategies during 2015 and plan to compound these efficiency 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 retains to preserve liquidity.

Moving to slide 5, as you can see from the graphs we have had strong execution. Beating guidance in both the production side and the cost side for both the fourth quarter and the full year. Importantly, I would 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 the formidable commodity price challenges.

Our total D&C CapEx for 2015 was reduced by nearly 50% in 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 seeing double-digit declines on a per unit basis.

We will continue to focus on driving these costs lower on an absolute basis in 2016. Nevertheless, to be fair, we have to acknowledge that our per unit metrics begin to creep up as activity levels and production both declined in 2016 which is apparent in our first-quarter guidance given our reduced activity levels.

On slide 6 here we show a bridge of approved reserves from 2014 to 2015. It is essential to recognize the impressive positive engineering revisions we had as a company this year due to improved field wide performance data which displays 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 would like to now turn the call over to Tony for his operational update.

Thanks, Rich.

I will start my operational update on slide 8. As Rich alluded to in his opening remarks, and as stated in our press release, we plan to reduce our activity in Wattenberg at the end of this quarter and pay 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 had started this work in 2015 and have noticed significant increases to our base profile. Briefly walking through the initiatives, I will start with our SCADA telemetry and automation system. This system provides real-time data on things such as gas lift rates and system pressures. This data is then utilized by our operations teams and helps them optimize production more efficiently.

Secondly, our infrastructure expansion has gone a long way to significantly reducing downtime. With our pronghorn gathering system and DCP'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 has always been more susceptible to line pressure fluctuations you can see that the first half of the year had more volatility while second half was much more stable and predictable.

Lastly, we have been more proactive on our interventions of our existing wells. Implementing low-cost quick payout projects such as optimizing plungers and rod pump installs helps lower overall costs and offsets 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 boards and will continue to be a key focus for the company in 2016.

While our plan is to temporarily idle our field development activity we still stress the need to continually review and improve our well design. Our operations team worked 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 have laid out the three main changes to well design that we have implemented over the last nine months or so. First, is the increase to 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 conclusions is an easy decision with a short payback period of around four months on the incremental investment along with the expected increase and ultimate recoveries.

The next change is moving to Mono-bores. 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 have successfully executed seven Mono-bore wells.

Our third design change is the recent move to Plug-and-Perf. Up until 2016 we almost exclusively used 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 efficiencies with Plug-and-Perf that result in fairly similar well costs when compared to sliding sleeves. While the ultimate decision to move to Plug-and-Perf was its ability aid Mono-bore execution we have reserved uplift in early time production from the first Plug-and-Perf wells that we have executed.

The following two slides show some detail on the results that we have seen with increased sand loading and Plug-and-Perf completions. 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 through our well costs, which are shown on slide 12. Where we show a progression of costs from our last earning call to where we expect costs 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 buildout regardless of an RMI sale. The remaining reduction to well costs come through the changes to well design that I went through earlier as well as cost concessions we have received from service providers.

So with that I would 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 year-end. 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 farm acreage acquisition in 2012, which will be paid fully in July.

Since year-end we have not drawn further on our revolving credit facility and remain with $79 million drawn and $20 million of cash on the balance sheet as of close of business yesterday. The current borrowing basis of $475 million as part of the revolving credit facility gives us liquidity as of December 31 of $405 million which is the same today.

As you can see in the bottom left chart we are clearly within the credit facility covenants for Q4 2015 with secured debt to trailing 12 months EBITDAX of 0.3 times, trailing 12 months EBITBDAX interest of 4.8 times and the current ratio of 3.5 times all well within the respective covenants levels of 2.5 times, 2.5 times and 1 times. It is also appropriate to emphasize that we have no unsecured debt maturities until 2021, with the weighted average coupon of our high-end notes of approximately 6 and 3/8%.

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 a 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 differentials, we expect our Rocky Mountain oil differentials to be WTI less $1.50 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 in the Rockies and NGLs company wide. Going forward for gas we expect to continue to see 75% of Henry Hub in the Rocky Mountains and approximately Henry Hub in the mid-Con.

For NGLs we expect to see 25% and 35% of WTI in the Rockies and mid-Con respectively. With regard to the financials it is probably not surprising to most that we had a sizable 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 plan for the year is to finish our operated drilling program of 12 wells in the first quarter and then idle our drilling and completion program until a time when we have either executed a transaction for our Mid-stream asset or see material changes in the macro environment.

While the operation teams 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 returns in North America on conventionals with the significant growth opportunity provided by the space and infrastructure will play a key role. Over the pet past few years we've invested in growing this Midstream asset base and announcing the benefits by improved performance and EURs across our field.

The current environment has directed us to a sale where in the past we would hold build and control the asset further into the overall field development. With this economic growth opportunity we are confident that we will be able to find a partner for the RMI assets at a price that will benefit both Bonanza Creek and the acquiring party. In addition to our RMI asset sale we will continue to work a process with mid-Continental.

With that I will pass the mic back to Rich for closing remarks.

Thanks, Bill.

In closing I would like to reiterate the strong operational execution we had throughout 2015 and into 2016 to become a low cost operator of the Wattenberg. While pushing technical innovation to get the most from our reservoirs. Though 2015 was a commendable year and a very tough environment, we need to look forward to 2016 to position the company to survive in what looks to be an increasingly difficult year ahead.

While we have been faced with a 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 will turn the call over to questions. Thank you very much.

(Operator Instructions)

Irene Haas with Wunderlich.

Yes. Hi, good morning, everybody. My question for you is probably not going to be easy to answer, but would you have a feeling as to how long you can reactivate this whole Midstream sale business and be able to wrap up? Are we talking about three months, six months or just a little feeling on the timing, and similarly for the mid-Con assets, because that's quite crucial to the Company now?

Hi, Irene.

As you'd expect reactivating the RMI process is not difficult for us at this point. We have been through considerable work on 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 have already accomplished. We feel pretty good about that process. Likewise with the mid-Continent process, although we can't talk about things that are occurring at this moment in time, we also have some confident that we will see that through in the near future for the benefit of the stockholders.

Could you give us a little visibility on timing? Are we thinking about three months, six months, just so we have some visibility?

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

Great, thank you.

Thanks, Irene.

Neal Dingmann, SunTrust.

Good morning. Rich, just wondering, short of getting the RMI deal done in the near-term, thoughts on macro environment, what you would have to see to think about bringing at least maybe first of all completions -- start back with some completions 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 the asset is critical. We've got $33.00 oil in the near-term and $39.00 or $40.00 as soon as December. So, if we are looking to maximize value for stockholders we would prefer to produce volumes in December than we would to produce them in March.

Timing is focused on maximizing shareholder value, really. And to the extent we have visibility on prices and costs where we can make a case for reestablishing activity, we will be very rational about so doing.

And when you come back -- make sure I have this right -- just the number of DUCs that you will have, is it in addition to just the 12 that you will drill, will you have I assume some others that you will be able to come back to quickly if you would like.

Neil, this is Tony.

We will have seven basically seven DUCs ready to go. When we finish up our drilling program we will have seven wells that will be left uncompleted.

Got it. And then, Tony, just one follow on my last question, is just now with the plug-and-perf, your thoughts now about doing -- going forward, Tony, would be mostly just the XRO type wells, or how do you think about the extended reach versus some of the others that you previously were doing?

Neal, we like the extended reach lateral wells, and as we move forward with 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.

Leveraging that infrastructure really does reduce costs and wells most focused on our western part of our legacy acreage where we started our standard reach lateral development several years back, obviously that's where we would still have some standard reach lateral development. But again those economics are very strong, because it would be leveraging the infrastructure.

And one last one, Rich. Was there a cover bid you can come back to, or are you going to have to 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. This wasn't one priority picked out of the air. This was a very robust process, and we have a lot of confidence we could we catalyze effective immediately.

Okay. Very good.

It's Bill here. We had probably 20+ interested parties in this transaction when we went through it in the summer. We narrowed that down to six parties, which we worked on NDAs and brought them in and did management presentations. As you can imagine it's a pretty involved process getting field visits done, et cetera. So I am -- we have already been fielding calls overnight on interested parties coming back and some of the parties that were there before and some new parties.

Got it. Thanks for the additional details.

Phillips Johnston, Capital One.

Got it. Thanks for the additional details.

Phillips Johnston, Capital One.

Hey. Thank you.

Just looking at the first quarter production guidance, it implies about a 17% sequential decline from the fourth quarter, which seems pretty light considering you are planning on 12 net well completions in Wattenberg, which I think is pretty flat versus Q4. Is that a function of weather impacts or Midstream issues or any other transitory issues that have happened so far in the quarter?

Hey, Phillips, no probably the biggest portion is that is the pad timing itself. In fourth quarter we had two seven well pads come online early in fourth quarter that drove production for fourth quarter. They peak 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 order.

And then the pad timing for first quarter of 2016, our first pad in 2016 which was a five-well SRL pad did not 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 in mid-Marchish.

The timing of that we basically had a two-month hiatus 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 their steeper portion of the decline rate of their curves impacting that in first quarter.

Okay. Yes. That makes sense.

And then just on your reserve adds last year you booked 12 million barrels of extensions and discoveries. It seems a little light relative to the $350 million of upstream CapEx. Implies around $30 a barrel of drill bit F&D costs.

My question is, can you provide us with the average EURs that Netherlands gave you credit for in the Wattenberg, and were there any significant differences between those EUR bookings for your PDP reserve adds versus your PUD reserve adds?

We did not have any significant difference between our PDP and our PUD. If you consider our positive engineering revisions, there are some PUDs that actually roll into that category. So we only added about 17 PUDs in the 12 million boe's that you're looking at for capital adds. So that was 63 wells that we drilled and completed during 2015 and just 17 PUDs. So a lot of the positive changes in our reserves actually fall into the engineering revision category. So we have actually slightly increased our PUD reserves and we have a very small variance to our third-party auditor.

Okay. And those positive performance revisions, that's the 10.8 million barrels that is listed in the presentation?

That rose into the 10.8 million boe, and it is also a factor in what we referred to as a revision associated with drop in CapEx. Because we had both a drop in CapEx and increased performance, the two of which together pulled most of our PUDs back into the proof reserve category.

Okay. Right. Okay. Got it. Thank you.

You're welcome.

Our next question comes from Ipsit Mohanty with GMP Securities.

Yes. Hey, good morning.

Tony, just speaking of from where you left in terms of the timing of completions in 4Q, but more specifically in the 1Q, it looks to me that you're still bringing on a pad towards the end of the quarter, and if you just stop drilling, then you could probably see steep declines going forward at least in Q2. So thinking over the rest of the year, presuming for now that you see drilling and trying to understand that the phrase 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're not doing that right now from a 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 rates. I can't really guide to second quarter, but you can see the timing as we brought those pads on a late January, middle February, middle March, we have a nice even distribution moving in to the quarter. But we will just have to see what those decline rates as they fall off, when they go into their tight curve declines and we will see what that looks like. But again we're not going to guide to a full-year.

Okay.

And then switching over to the mid-Con. In my understanding it seems like you averaged 5,000 barrels per day for 4Q, but the 1Q guidance again looks as if that has gone through a steep decline, as well. If you can care to comment on that?

This is James.

We did not break out the Rockies versus the mid-Con piece, but if you think to -- in the K we show a 40% PDP decline rate for 2016 with that 12 wells of growth in the beginning, so we are not explicitly guiding full-year 2016. That should hopefully guide you in the right direction.

Okay. My last one for Rich and the other guys, when you think about putting make on assets on the block, how do you feel about putting a declining asset on sale? Any color you can provide and then what is helping you to think that you can get a good value.

Well, some of the benefits of the mid-Con asset, Ipsit, include the fact that it's an integrated business it's a monopoly processor in that jurisdiction. Any offset operators with associated gas production have to go through the plant. The gathering system we have is also very valuable.

And the asset itself has a lot of PDMP recompletes which from a capital perspective at these prices are still very valid in terms of capital deployment. So it 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. It is an attractive asset with type differential to WTI.

Got you. Okay. Thank you.

Brad Carpenter with Cantor Fitzgerald.

Good morning everyone. Just a few quick ones for me. Curious if D&C operations are halted after these 12 completions in the first quarter, what is a good quarterly run rate for CapEx that we should be using?

I think we have given you the first quarter CapEx at about $40 million as guidance. So we're 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 divestiture, and then also on the macro environment, we will come back and give further updates on where capital will go through the year.

Okay fair enough. And then in the DJ, you noted that the improved line pressures resulted in an increase of about 15% in cumulative first-year production of 15 vintage versus 14 vintage wells. I'm curious if you're seeing any variation in the GOR between those two wells. And obviously what I'm training get at, is there -- is basically that 15% improvement mostly on the gas side, or is it pretty much one-for-one gas to oil and NGLs, as well?

Yes. No. I tell you what -- it's pretty much equivalent to what our normal production makeup is. We're not seeing a big break out in gas versus oil. It's very similar to what our normal breakout is.

Okay. Great. Thanks for your time this morning.

You bet.

Michael Hall with Heikkinen Energy Advisors.

Thanks, good morning. I was along similar lines as Brad, just curious around any leasehold maintenance considerations to keep in mind as we move through the rest of 2016, and beyond the first quarter's activity?

Yes, Michael, no. This is Tony. No, very minimal leasehold. Basically almost our entire acreage position is HVP and so we have no issues with leaseholders. We don't have to spend very much money very little at all on any kind of leasehold.

Okay. That includes the northern acreage that was somewhat recently purchased?

Yes, that is correct. Northern acreage, southern acreage, and, of course, our legacy position, all-inclusive.

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

The location of the wells are in our legacy position. They are both in the western and eastern part of our legacy position. And the makeup of the wells, we have five SRL well pad that just came online in January.

We had a four well MRL pad, so that's about a 7,500 foot lateral link 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.

I saw the 40% decline in the 10K. It's helpful annual disclosure you all provide. Can you quantify how this base production optimization might be able to impact that 40%, or is any of that optimization already contemplated in that 40% figure?

I think base optimization is starting to flow through in our reserves. As we have moved our PUD reserve curves on our eastern legacy position, which is where a majority of that work is taking place and we have been able to move those reserves upward for the past few years. We are seeing that, I think, going forward. Continued base optimization will continue to flow through the reserves base 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 a impact as we make our way through the end of the year and you would flatten the 2017 profile as opposed to 2016? Am I hearing that right?

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

Okay. Then last on my end is -- just curious have you all had any discussions around revolver redetermination with the bank group as time moves forward. The ratios will clearly change around the covenants, and I'm just curious what sort of discussions have been had in that context or around the committed amount?

Hey, Michael, it's Bill here. We have ongoing discussions with our agent bank on a regular basis, as well as the other banks. We will just move to our normal timing, April May timing. And, obviously, lower price stack, lower volumes we are going to see a cut in the overall availability. But we don't see any reason to accelerate that given where we are today. So we will continue to have those discussions as normal.

Okay. Fair enough. We will keep our ear out. Thanks.

Thanks, Michael.

Mike Kelly was Seaport Global.

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

Thanks.

Hey, Mike.

Were not authorized to speak on behalf of Meritage or Riverstone. I will just say their actions speak for themselves.

Ultimately, we went to contract. We had robust process in August, September, October with a number of parties and then down select, full disclosure of materials, data room access, engineering data, etc., which culminated in us going to contract with them. And ultimately, I can't speak for their investment committee, but they elected not to come to agreeable terms in the end, and so we have terminated that contract.

Okay. Just looking at it at a high level though, is this -- can you point to the commodity price really being a big driver there? What I'm trying to get is, as you remarket this maybe to the lower crude environment, lower gas prices, how should we think about how the value of that asset has changed? You got a pretty good deal with these guys, how close can you come to it ultimately to repackage it and do it a 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 conviction. This is a very, very valuable asset. If you look back on our 10K, just the raw materials that we use to construct this asset in 2015 have a cost of book value of $106 million. So that's stuff like tank batteries, separators, gathering systems, pipes, tubulars, flanges, right down to nuts and bolts.

That $106 million in raw materials is superimposed upon a project level leasehold that covers an upstream resource with 1,400 gross locations in a highly contiguous acreage position that represents over $3.5 billion in future upstream development capital associated with that asset and the asset is 100% held HBP. It is very well understood and delineated.

We have over 400 horizontal producer wells in that area helping to derisk the asset. And then the economics of the contract are supported by a life of field monopoly incumbency. So the leasehold dedications and service contracts are effectively an incumbency that persists as a covenant running with the land.

So this is not a corporate level security interest, it's a land release level security interest and is a very very attractive asset for Midstream parties. So, I think we will leave it at that, and we will look forward to engaging with new parties in this process as we catalyze that today.

Okay. Maybe I could ask one direct question on that. Is there anything in your mind that's happened since November that is materially imperative to that $255 million price that you originally got?

We have conviction that as time moves on the value of the asset goes up. Now what's happening in externalities and capital market, the MLP space, the infrastructure space, the Midstream business industry. You know, those are things we cannot control obviously and so we are subject to vagaries in that area.

Unless you think oil is $30 for the next 20 years, this is a highly valuable monopoly position and a highly productive basin where there's only two other incumbents, which is Anadarko, Western Gas Resources, and the Old Duke Conoco Phillips DCP. So it's a valuable position for somebody.

Okay. Great. Thanks.

David Beard with Coker and Palmer.

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

Again, I think that 40% decline rate is what we've got our 10K. I would stay with that. There's nothing to change from that, and I think I have walked through our completion schedule. We will have those pads online and that last pad coming online in the middle of March will be our last pad for the foreseeable future until we pick back up activity. As we will have those, as I mentioned earlier, those seven DUCs, we'll have waiting for completion, but that will be pending when we make the decision to bring those online.

Okay. Yes, 40%. I stand corrected. Thank you. Appreciate the time.

Welles Fitzpatrick with Johnson Rice.

Hey. Good morning. This might've been asked, but obviously a big drop in SRL costs quarter over quarter. Can you give breakout of infrastructure versus design, versus the cost components in those savings?

Hey, Welles, the big driver on the costs again is the infrastructure piece. I think we stepped you through -- coming from -- let's see what slide are we on here. Slide 12. I apologize for that. Slide 12.

So looking at those costs, where we came out in 3Q 2015. We were at that $3.4 million. Then 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 reductions that we were seeing from our service providers. So that's the driver there.

Going into 2016 we started to execute the Mono-bores and so that is -- we are already realizing that so that's getting you down to that $2.5 million. So that's from the Mono-bore execution.

Okay. That's perfect. Thank you. And then just one more.

I'm also by no means an expert on pipelines, but if the contract is running with the land. Does then the bank group -- do they get to have any say as to what is executed since essentially it will go with the asset regardless?

As it stands, those assets are part of our Company's assets and the collateral pool existing in the business and all that collateral, subsurface collateral, the service facilities, all that would effectively become a lien or accessible by a first lien creditor. In terms of how that would manifest after a sale is specific to any perspective sales. But it is a lease level covenant running with the land. So it is not a corporate liability or asset, it's a lease level asset.

Okay that's perfect. Thank you.

Brian Corales with Howard Weil.

Good morning. On the mid-Con asset, how much of the revolver -- is it a big portion of the revolver?

Hey, Brian. We have not broken that out. So, we will be mute on that at the moment.

Okay.

Obviously it is proportional to the size of the production overall.

Okay. That's fair. Thank you. That's helpful. The northern acreage, the delineation well, is it just a bad well, has your thoughts changed on the acreage, can you maybe expand on that?

Hey, Brian.

That first well we drilled on northern acreage delineation much further north up there in 762. When we drilled that well, it's a 9,000 footer, but we have 3D seismic up there. But as with any delineation well you go in and drill it. We crossed the fault about halfway through it and put that well into the Amoro. We went ahead and completed the well. Actually we are pretty encouraged with the results based on that half the well is in the Amoro, which is really not productive.

At the end of the day we're going to take that data and we can now come back and correlate that to 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 that Amoro when we drill up there again.

So at the end of the day I think we were forecasting a little over 400 MBoe equivalent recovery, when you take into the fact that we didn't complete the Amoro part of it. Or we did but were not getting any production from that.

When you factor in that we can come up there and do larger fracs, the 1,500 pounds, this well was not completed with the larger fracs. And also with the plug-and-perf, you know 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 stepped out to our eastern legacy position a couple years ago, those first wells we stepped out were lower performers, if you will. But we figured it out and improved performance significantly.

I think we're at a good starting point, and further northern acreage, and I would say I'm very encouraged by the acreage, and I'm looking forward to getting back up there and drilling and putting some more of the fracs. Obviously the question is going to be around timing of that as we look at our 2016 program, ramping down temporarily.

Okay, and then maybe just one final one. You covered this a lot, but if you get some resolution or announcements, we'll call it the second quarter or some time, we'll call it midyear, if there is cash behind the door, is it immediately put back, are you going to put the rig back to work, or do you also need to see higher commodity prices, or is it we'll see how it stands in the market? What's the thought?

Brian, let me just rephrase the question, if I may? What's going to drive our decision on increasing activity? Is that the question?

If you get the asset sales done. Yes.

It's pretty clear that in the case of RMI for example that a partnership with a midstream or infrastructure player would encourage us to restart activity, and to develop the field in conjunction with that midstream transaction. So that would be an important data point for us. And likewise, better prices would encourage us to restart activity as well. So we're poised and ready. It's just that at these prices, as everyone can see, it's not an attractive environment to deploy capital.

Okay. That's helpful. Thank you.

Ryan Oatman with Cowen and Company.

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

On the guidance there's a line item for midstream expenses of about $2.30 a barrel. In the event of Rocky Mountain, infrastructure asset is not sold, would those charges still be incurred?

Yes. They would still be incurred. Yes, you are correct.

Okay. Just to clarify, on the 1Q production guidance that does or does not include the Mid-Continent assets?

It does include the Mid-Continent assets.

Okay, that's it for me. I'll follow-up off-line. Thanks

David Meats with Morningstar.

Hello. Most of my questions have been answered. So just one 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 mono-bore design you were talking about back to what you were previously doing?

No, the answer to that would be no. We think the mono-bore design, those cost savings would be something we would take with us in a current price environment or even a higher price environment. And we think if you continue to successfully execute those, they'd provide a lot of flexibility going forward for wellbore construction. So we would not go with the mono-bore design.

Okay, that's perfect. That's all I've got, thank you.

[Stevens] with Oppenheimer.

Hi, thank you for fitting me in. Bill or Rich, maybe it's a follow-up to one of the other questions here, but if you were to assume no midstream sale and the strip plays out, can you talk about how you think about spending priorities? When 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 assume that the strip does play out, how do you think about free cash flow and what you would use that for?

The thought process on bringing a rig back in the Wattenberg would really kind of depend on where costs go as the curve starts moving back up. Until we have better visibility on RMI and on Mid-Con, I think it's really capital preservation and preserving liquidity, so we can get more visibility on those transactions. We don't really have a time frame for you. We just need to see how these transactions progress over the next three to six months.

Okay, that's fair. In the interim, if there is any free cash flow out there, it would be fair to assume you'd be using that pay down your credit facility?

Again, it's just to maintain liquidity.

Okay. Makes sense. Just thinking about, if you were to get an RMI deal done with a 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 the [20th year].

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

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

We've 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 where the bonds are at then.

Sure, that's fair enough. Thank you.

Paul Grigel with Macquarie.

Hi, good morning, just one quick one since most have been asked. You have spoken to the 1,400 locations around the RMI area. Is there the 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 volumes at RMI?

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

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

I don't think we have published returns on the strip currently. What I can say is that we do still have economic wells to develop. The issue for us, Paul, is not the IRR on the wells, but obviously the cash payback on the wells. Just to throw a number up in the air, say you have a 15% return on a well, that still requires you to put money up front in order to earn that 15% of return over a period 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 better returns for stockholders.

That's understood. Is there a cash recycle rate, or a payback period that you look to as a critical level?

We don't have bright line for that, no. It is a case-by-case decision as we move on.

And I think you've got to take everything into account here including the overall liquidity, right? So it's not just returns, it's liquidity and long-term where are you going to be coming out of 2016 and 2017, etcetera.

Thank you.

Steven Karpel with Credit Suisse.

Good morning. I want to understand again, maybe to more clarity around the HBP issues and your need to, on two sides, to provide capital to some of your existing base, what's the ability for those that you, if you have to provide some capital to renegotiate some leases, whether it's continuous drilling or continuous production, given the realizations your seeing on the gas side. And then secondly, how much non-op drilling did you have in 2015? And then, what's that number in 2016.

I'll go ahead and start off, Steven, with the acreage position the HBP. Again, a great majority of our position is already HBPd, and in 2016 and 2017 we have very small requirements to maintain that leasehold position. So we're talking less than $5 million total, probably, for 2016 and 2017 to keep that acreage position 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 that 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 them as I remembered as you asked them, is what kind of non-op activity are we expecting in 2016? Quite frankly we are getting non-op proposals in, but as I look around the basin and I see rig counts dropping, I'm not sure how much activity is 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 spuds in 2015, so fairly minimal activity. And that resulted in 1.8 net. Well, net on that. So I don't know if I caught all your questions, but that's at least a start.

All right, and then probably for Bill, just to understand, harping 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 side, if presumably the banks granted you the same borrowing base?

Yes, look, I think we all expect the borrowing base will be reduced in the spring redetermination and whatever is provided by that redetermination, I'm sure that'll be available. And what we have seen in the market was some of the redeterminations and some of the request for covenant relief, etcetera, is being anti-cash hoarding. So folks would not have the ability to draw everything down. But we will work with the banks as we start moving forward in the next determination season and business as usual on that side.

And just to clarify, understanding of course what the banks do, on the bond side, anything in the bonds that would limit the size as your PV-10 value is adjusted?

No, we've been pretty covenant light in bond indenture, so we shouldn't really have an issue on that. [Multiple speakers] We have a $300 million, greater of $300 million, or 35% of bank [note]. At the moment it's about $750 million, something like that. Right? So it's about $300 million.

And the $300 million compares to your current, I think, $475 million, if my number is correct? Should we be concerned that if the banks provide a borrowing base greater than $300 million that you wouldn't have access then, or am I misreading your comments that you're making?

Can you go through that question again, sorry?

I thought I heard your question was, or your answer was, that the, you said the great -- 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 2017? I didn't want to mischaracterize your comments, I was a little confused by what you said --

We'll have full access to our borrowing base as it gets redetermined by the banks.

So the $300 million guidepost, we shouldn't be concerned about in the bond indentures that you were referring to?

No, that's over and above. We shouldn't be concerned 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.

Thank you.

John Herrlin with Societe Generale.

Just one quick one on RMI. Would you sell it just straight up and not go for carry, or is carry one of the sticking points?

Hey John, it's Rich.

There's no carry involved. It was $255 million, $175 million up front with $80 million in the sign-ups in the back end, as originally structured back in November. Listen, we're happy to work with New Midstream Partners in contexts that makes sense for them. So we're open to suggestions on 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 a JV. And that JV transitioned toward an outright sale of the asset. And so, we'll see how that develops over the course of the second quarter here.

Okay, thanks.

Kim Pacanovsky with Imperial Capital.

Just one quick question on the evolution of the well cost here. I noted in your slide deck from November, the XRL well costs including the incentives for RMI were $3.5 million. And then you had them at $3 million in the December slide deck, and now without RMI, your goal is $4.3 million. So, that just seems like a very big gap between the last published $3 million, which included the incentive. Was the incentive that great, that much greater for an XRL than for an SRL?

Yes, those incentives that we were talking about, Kim, it was over $1 million for an XRL incentive, so that's the biggest driver of that was the $1 million. And then the remainder of the cost going down to the $3 million which would be now equivalent of $4 million is really around, we were 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've taken you right down to a $4 million well cost, and then take off that million dollars with the incentive brings you down to the $3 million well cost.

Perfect. That's all I needed. Thanks.

Maryana Kushnir with Nomura Asset Management.

Hi. I just wanted to go back to the credit facilities discussion and I understand a lot of questions have been asked. But if you're showing compliance currently, but as we run some projection scenarios and show you out of compliance, so why not just initiate that discussion a bit early with the banks more actively, rather than waiting till like the normal season to talk to the bank.

We're in constant discussion, as I said, with the banks, and they're fully aware as to where our covenants will go. And we took action in the spring redetermination last year to move from a total debt to EBITDA to senior debt to EBITDA, and we will take action as we move forward with the banks on whatever covenant relief we need in the spring redetermination. And we're in active discussions on that.

Okay, and is there also interest coverage test, correct?

Yes, that's right, two and a half--

Right, okay. And then we've seen across the industry a number of borrowing base cuts within 25%, 30%, I guess that was a common percentage. If you compare bank price deck 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'll just work with the banks and work with reserve engineers, and we'll see where we come out. We've had a very open, straightforward dialogue with the banks over the years, and we'll continue to do that going forward. So I can't really speculate as to what percentage cut it's 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. So I guess, the bond indenture provides for the secured basket carveout, which is a percentage of ACNTA percentage.

[35?]

Right -- so as that declines because PV-10 value declined substantially, so would you be able to access your credit facility fully at whatever number it's redetermined, according to the covenants in the bond indenture?

Yes, we'll have full access to our credit facility as it gets redetermination. Banks will be fully aware of what 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 redetermined.

Okay. Thanks.

Gabe Daoud with JPMorgan.

Hello. I'm all set thanks.

David Deckelbaum with KeyBanc.

Morning. Rich, Tony, and Bill, thanks for taking my questions. My condolences on the RMI process so far. But hopefully some better days ahead. Back to the PDP decline rate. Is that an internally generated number? Is it risked? And could you comment on how you all performed in 2015 vis-a-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 year-end. So it's not either conservative or optimistic. It's just based on SEC guidelines.

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

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

Fair enough. Tony, on the 1,400 location you talked about, that was in and around existing infrastructure. How inclusive are those 1,400 locations of XRLs, or how amenable are those locations to XRL development?

David, we haven't provided a total count on that. When we look at our 3P that we provided everybody, it's on an SRL equivalent. But what I can say is that, obviously, the eastern acreage is more conducive to extend the reach lateral because it's less developed. The western acreage is less conducive because of the starting of the 4,000 foot laterals there.

But we can still fit XRLs in there. But to give you a percentage right now, I probably can't do that. But again, the 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 built outs to the north and then further to the south would be almost exclusively XRL development.

I can appreciate that. Just curious, I thought in your comments earlier, you had said that XRLs would be the priority if there was capital available to go out there and redeploy. Now, if you're drilling --

Yes, David, I'm sorry, yes, that is absolutely correct. I did say that, and that would be, if we go back to drilling, we will maximize the XR development of our program. I do want to emphasize that SRLs on the western part of our position going into the infrastructure that we have there are very competitive to XRLs because, again, we have strong performance and the infrastructure piece is still a major driver in the economics going forward compared to what you get out of the wells themselves. So we would leverage that both, but again we would still have room to put SRLs in there that would compete very favorably.

Thanks for the answer, Tony. 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've hit the nail on the head. It's going to be quarterly as we move towards the end, or until we see visibility on commodity prices for the year. So I don't think it's right for us to give the quarterly guidance when there's uncertainty in where we are. So we'll work on the asset sales, and we'll give more guidance as we get through that.

Okay, thanks for the color, Bill. Take care.

And I'm 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 in to our call today. We look forward to following up with you if you have any follow-up questions, and we wish you the 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.