Ryan Zorn - Senior Vice President of Finance and Treasurer Richard Carty - President and Chief Executive Officer William Cassidy - Chief Financial Officer Anthony Buchanon - Chief Operating Officer.

Welles Fitzpatrick - Johnson Rice Scott Hanold - RBC Capital Markets Mike Scialla - Stifel Irene Haas - Wunderlich Phillips Johnston - Capital One Brian Corales - Howard Weil Ipsit Mohanty - GMP Securities Michael Hall - Heikkinen Energy Advisors David Beard - Bonanza Creek Paul Grigel - Macquarie Andrew Coleman - Raymond James David Tameron - Wells Fargo.

Good day, ladies and gentlemen, and welcome to the Q1 2015 Bonanza Creek Energy, Incorporated Earnings Conference Call. My name is Tawanda and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session.

[Operator Instructions] I would now like to turn the conference over to Mr. Ryan Zorn, Senior Vice President of Finance and Treasurer. Please proceed, Sir..

Thanks, Tawanda, and good morning and welcome to Bonanza Creek’s first quarter 2015 earnings conference call and webcast. Yesterday afternoon we issued our earnings press release and this morning filed our 10-Q with the SEC. You can access both on our website.

Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-K and other SEC filings.

Also, during this call we’ll refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of those measures to the most directly comparable GAAP measures are contained in our earnings release.

It’s my pleasure this morning to introduce Rich Carty, Bonanza Creek’s President and Chief Executive Officer, who will provide a brief overview of first quarter results. Following his remarks, Bill Cassidy, our Chief Financial Officer, will discuss financial highlights. And finally Tony Buchanon, our Chief Operating Officer, will review operations.

As usual, we have endeavored to keep prepared remarks short to leave ample time for Q&A during this 60-minute call. With that, I’d like to turn things over to Rich..

Thank you, Ryan, and good morning, everyone. We know it’s been a long week for those of you attempting to tune into energy sector earnings calls, so we appreciate you spending some time with us this morning as we discuss the quarter and thoughts on the remainder of the year.

Upon reflection, it was a remarkable first quarter in many respects for the industry. In that period of heightened volatility and uncertainty, above all, our natural instinct was to endure. And ultimately when you are no longer able to change a situation and manage outcomes, we’re challenged to adapt and manage risk.

So rather than growth as a prime objective as in years past, our company rapidly refocused around internal operating efficiencies, external cost reduction, and establishing a margin of safety in our finances to weather a storm of unpredictable duration. Our team rose to the challenge and exited the quarter with some meaningful wins for the franchise.

While we made considerable headway in lowering our costs, with cash operating costs for LOE, production taxes, and G&A registering $15.83 per Boe, we will continue to strive for further improvements as the year progresses.

Some of our cost reductions are as a result of our team’s quick actions to co-locate this year’s drilling with existing infrastructure, thereby minimizing the amount of non-D&C CapEx. In addition, significant cost reductions are as a result of concessions from our oil service partners.

We recognize this as a particularly hard environment for them as well as utilization of the fixed assets has fallen markedly.

We have always attempted to partner with service providers that have the most robust supply chain organizations and premium crews at the ready which makes them better equipped to take out costs of their businesses and ultimately ours as well.

We continue to be focused on maximizing the productivity of capital deployed, and as such we will continue to execute our 2015 program, which is geared to keep exit rates flat with year-end 2014. To be clear, our operations engineering team has focused on delivering an activity-based development program.

So, to the extent that capital required to complete this activity program is less than our CapEx guidance of 400 million to 440 million was in January, we would expect to bank those savings rather than increase activity levels.

We’ve been very intentional in providing an accurate line of sight in our projects this year so that our industry partners and stakeholders are best able to coordinate with our activities and minimize operating risk.

For the balance of the year, we remain committed to operating excellence, financial prudence, and opportunities to create meaningful value for stockholders. We promised to keep it short, so I will yield the floor to Bill to give a quick overview of the quarter’s results. I look forward to taking your questions..

Thanks, Rich, and good morning, everyone. We reported companywide sales on volumes of 27,500 barrels of oil equivalent per day during the quarter, which is 30% greater than three stream equivalent volumes a year ago. Despite our volume growth, revenues declined 43% versus a year ago as benchmark WTI prices declined 50% and Henry Hub prices fell 44%.

The company generated $69.3 million in EBITDAX versus the year ago period of 80.5 million, representing a decline of 14% year-over-year. During the first quarter, we incurred capital costs of $123.4 million, which is in line with our plan, and represents approximately 30% of our planned CapEx of 400 million to 440 million for full-year 2015.

Our rig count began the quarter at three in the Wattenberg and one in the Mid-Continent. We dropped one Wattenberg rig, which leads us running two highly efficient, fit for purpose rigs in Colorado, while we continue to run one rig in Arkansas.

Effective January 1st, we converted to three stream reporting for our sales volumes in our Rocky Mountain region. There was no change to our reporting convention in the Mid-Continent. The change in the Rocky’s was as a result of modifications to our gas processing agreements with DCP and Midstream and other processors in the area.

While this conversion should be essentially revenue-neutral, first quarter realizations in the Rocky’s have some embedded noise as typical prior period adjustments rolled through from the two stream world.

As we reach steady-state as a three stream reporter, we believe Rocky’s gas realization will be 10% to 15% off Henry Hub and NGL realizations will be 70% to 75% off the WTI. Of course, oil realizations were not impacted by this conversion to three stream and we continue to see steady compression of those differentials versus WTI.

The first quarter was approximately $10 per barrel off WTI and we expect to see that level or slightly less during the remainder of 2015. On April 30th, we formed Rocky Mountain Infrastructure, LLC, a wholly-owned subsidiary of Bonanza Creek Energy.

The entity is now home to our Pronghorn and 70 Ranch gas gathering compression systems that service a substantial part of our legacy east and West acreage. We have, over the past three years or so, invested approximately $38 million in these systems.

We will use this subsidiary to add to the overall infrastructure build out relating to our full field development over the coming years. Before I turn the call to Tony, I wanted to provide a brief update on our semiannual borrowing base re-determination.

We conducted our bank meeting on April 22nd, and our 10-member bank group is currently evaluating the materials presented to them by our team. Our credit quality continues to be attractive, especially given the positive impact of our common stock offering completed in early February. We expect to report the results of the re-determination by May 15.

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

Thanks, Bill, and good morning, everyone. Overall, I think we accomplished some significant wins in the first quarter.

With operational efficiencies and cost reductions taking shape, continued strong performance of our 40-acre down spacing test, and above all, improving midstream performance in the Rocky Mountain region, we are well-positioned to meet our annual targets for 2015.

Thinking about efficiencies, as noted in the press release, the reduction in drilling days we are seeing with fit-for-purpose rigs and multi-well pad batch drilling is very encouraging. Our spud to rig release times have dropped materially.

Our 4,000-foot standard reach lateral drill times are now at eight days compared to just over 10 days in 2014, and our 9,000-foot extended reach lateral drill times are now around 10 days versus 15 days to 17 days last year. Overall, we have reduced our drilling and completion cost by approximately 20% so far this year.

As most of you know, approximately one-third of the reduction is from internal recurring efficiencies such as our change in frac design, reducing our stage count by three on a typical 4,000-foot lateral, and our unique ability to co-locate our 2015 program alongside existing infrastructure within our legacy area.

The other two-thirds of the cost reduction is a result of external efficiencies, such as price concessions from our service partners. We remained very focused on capital cost, as they are by far the biggest lever we have at our disposal in adapting to the current commodity price environment.

Moving on to our 40-acre down spacing performance in the Wattenberg. We now have 14 Niobrara B and C wells that were completed with our 28-stage frac techniques that have approximately 180 days of production. These wells are tracking right around our 354 Mboe target type curve.

The great news is that, as our data set grows, it continues to indicate that 40-acre down spacing is not degrading well performance and provides increased confidence in the spacing assumptions that underpin our inventory of 3P locations. With regard to Midstream in the Wattenberg.

We have some good news there also as we look forward to the remainder of the year. We are happy to report that we have two new pipeline options to swing gas from our Eastern block to the West in the event of unplanned downtime at the Sullivan compressor station.

The first is DCP’s Windmill Pipeline, located on the south side of our Eastern legacy acreage, which came online in early April. This was two months ahead of schedule. The second is our online on the north side of our Eastern acreage, which came online the last week of April.

The addition of these connector pipelines, along with DCP’s newly operational 45 million a day, 70 Ranch compressor station located on the edge of our Western legacy acreage, the startup of the 200 million a day Lucerne 2 gas processing plant in late second quarter, and the completion of the Grand Parkway low-pressure loop by the end of the year, indicate strong midstream performance going forward.

In the first quarter, we did have some unplanned midstream downtime that hit our volumes by about 350 Boe per day. Sullivan, however, gradually lined itself out as the quarter progressed, and as we enter second quarter, we are seeing really good run time and we anticipate this good performance to continue.

Referencing our first quarter production, our teams and assets alike gained steady momentum as the quarter progressed. In the Rockies, we posted sales volumes of 21.9 MBoe per day, which were up 41% year-over-year and up 3% quarter-over-quarter on a three stream basis.

Most of you have heard us speak to the extreme cold the planes of Colorado endured in late December and early January. We woke up on January 1 to ambient temperatures of minus 32 degrees with wind chills of negative 50.

Those conditions were almost 50 degrees below the average low temperatures for Weld County in January, and certainly outside the extremes we attempt to build into our plan and hit our production for the quarter by about 350 Boe per day. Moving on to Mid-Continent, it continues to be a very solid asset for us.

Sales volumes averaged 5.6 MBoe per day for the quarter and were flat year-over-year, but down 15% compared to fourth quarter 2014.

This production swing is tied to our re-completion program, which as I have said previously, is statistical in nature and subject to upswings and downswings on a quarter-to-quarter basis, but still remains one of the most economic opportunities in the Company. On the cost front, we have really made some significant efficiency improvements.

The Mid-Continent operating costs, is under budget by almost 15% year-to-date. This is attributed to lower gas plant operating cost and turnaround expenses.

In addition, the recent commodity and geographic mix of our production in the Mid-Continent is aligned for the temporary idling of our McKamie gas plant as our Dorcheat facility is capable of handling our forecasted gas production.

Operating expenses with our McKamie plant are about 5% to 10% of Mid-Continent LOE and about 2% to 3% of corporate LOE, and we should see this cost reduction hit our financial statements in the second half of the year.

This is a great example of our ability to optimize fixed assets and run as efficiently as possible, thereby preserving our operating margins. So, to wrap up, I think we are very well positioned going forward. We are driving efficiencies throughout our organization to reduce costs.

From decreasing drilled times to optimizing our facility usage, we are achieving gains that will stay with us through any price environment. With our midstream situation lining out and new processing in compression capacity coming online, we have high confidence in our production forecast for the remainder of the year.

I’ll stop there and turn the call back over to the operator for Q&A..

Thank you. [Operator Instructions] Your first question comes from the line of Welles Fitzpatrick with Johnson Rice. Please proceed..

Hi. Good morning..

Hi, Welles.

Maybe I’m trying to read a little bit too much into the new Midstream LLC, but is there any potential desire to want to monetize all or some of that entity? Or do you want to keep that in-house for control?.

We really see this as a good way to characterize capital efficiently. At this stage there is no plan to do any monetization of the Midstream asset..

All right, perfect. And it seems like everything is going well on the broader midstream, but the recent reports of cresting rivers and potential flooding - I know you guys are a little bit more out of the way of that than some other folks in the basin.

Have you taken the steps of shutting in any wells? Do you see that as [indiscernible] a threat?.

No, Welles, not at this point. We have not taken any steps to shut in any wells and we don’t have any reports of any imminent type flooding near our acreage position..

Okay, perfect. Thanks, guys. That’s all I got..

Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed..

Thanks good morning guys.

If I could just do a really quick follow-up to the answer on the Midstream, how is that a little bit more capital-efficient, that structure? Are you looking at getting a separate RBL [ph] for that entity?.

At this stage we decided it was best to put the asset into this entity so as we can capitalize it and give ourselves more options as we look forward.

We have a lot of midstream that we want to build out over the next number of years as we develop the field, and we’ll be able to more closely identify the capital spend for Midstream and the potential financing of that at a later stage. But at this stage we have no plans..

Okay, understood. And then just again, keeping on the Midstream topic or just Arkansas maybe in general. What’s the current view on that asset? I know at one point in time, a year or two ago, you were all looking at potentially monetizing that, or at least that was a consideration.

Where are we at with that right now?.

As you know, the Midstream - the integrated midstream business we have in the Mid-Continent has been a great asset for the company over the years. It continues to be a very attractive asset. We don’t have any current plans to dispose of it.

And at this point we’re focused on driving operating efficiencies, improving margins, and making that as productive as we can for stockholders..

Okay. Okay, understood.

And then an operational one for Tony and when you look at - you are cutting out a few fracs on some of these wells that is obviously saving a little bit of money, is there any change in the well productivity when you do that? Or are you able to do that and see no degradation in the well results?.

Yes, Scott, so far we’re not seeing any degradation in the well results. And again, all we’ve done is add - as you remember with our 28 stage fracs, we were spaced at about 145 foot per stage - with our 25 stage fracs we’re spaced at about 160 foot per stage. So all we’re doing is adding about 15 foot per stage.

We don’t think that 15 foot should affect us on productivity, and we haven’t seen that so far. But obviously, we’ve been pumping those 25 stage fracs here in the first quarter, but initially no - we have not seen any impact..

And in the total aggregate volume you’re putting away in the lateral, is that the same or is it pro rata reduced for those three stages?.

No, we are putting away about the same. We’re still averaging about £1,000 per lateral foot..

Okay. All right. Got that. Thank you..

The next question comes from the line of Mike Scialla, Stifel. Please proceed.

Yeah, hi, guys. Obviously some pretty good results on your 40-acre test. I think, Tony, even on the last call you said you are pretty convinced that’s going to work.

I’m just wondering, of your 70,000 net acres, can you say that it’s going to work over all of that at this point? Or how much of that do you think is prospective for that kind of spacing at this point, or can you tell?.

Yeah, Mike, I guess the way I look at that right now is I’d look at how we have it kind of lined out on our 3P assumptions. We have that 40-acre spacing lined out on our 3P assumptions throughout our existing 35,000 acreage legacy position, which is kind of our middle position.

Right now in our 3P on the northern acreage and the southern acreage that we have, which makes up the other 35,000 acres of our total position, we have that spaced out at 80-acre spacing in the B and C for right now.

And then we have basically 160-acre spacing in the Codell across about 30,000 acres of the total 70,000 acre position, is how we see it right now..

Any plans to, given the success there, test, if not tighter, maybe some other zones? Like would you be able to stack the Codell in there as well on that kind of spacing?.

Mike, looking at the Codell, obviously we’ve got it at 160 right now. Our first step out into the thinner Codell is how we would pursue the initial catalyst in the Codell, but we are going to take a look at spacing the Codell at 80-acre spacing.

That would be our next step, but I don’t have any results or anything on that lines right now, but I think that would be the next step in the Codell..

Okay. And in terms of your type curves, these newer wells seem to be meeting that.

Is that representative of your acreage now? Or do you have enough data to put out different type curves for different parts of your acreage at this point, or is the 350 a good number for all your - at least your legacy acreage?.

Yeah, I think, Mike, the way we look at that on the type curve, we use that as a kind of uniform type curve across our entire acreage position. Obviously, there’s variability above and below it as you have, as you get a number of wells, but we’re using that basically across our acreage position as a general rule..

Okay. And then last one for me. I think, Rich, you had mentioned at the top that co-locating some of the drilling, saving this year.

Was that any change to the - is that just part of the original plan, or any change to where you are drilling wells this year? And also kind of hinting that the budget may come in - or your spending might come in under budget.

Is that due to any of those changes, or is that pretty much just from the concessions you are seeing from your vendors and the efficiencies you are seeing?.

To be clear, we organized and planned the 2015 program to leverage our fixed assets and infrastructure in place. And so collating was part of that original plan, so there’s no change to that.

And on the second part of the question with respect to costs, when we posited our $400 million to $440 million budget program in January, that was based on January costs at that point in time, which were - as you know in March we reduced our cost targets for AFEs in those wells.

So if we’re able to achieve those then the activity plan would come at a cheaper price, obviously..

Can you venture to say where that - how much lower you might come in at, based on where you are seeing your costs today?.

We’ve disclosed that the original plan was built on 4 million bucks for a 4,000-foot standard reach well in January. Those are now AFE at 3.6 million. And the extended reach wells originally were 6.5 million in January and those are AFE at 5.9 million..

So in terms of the overall budget where that might come in?.

Yes, so if you just take those AFEs and look at the wells we will drill throughout the balance of the year, those are our AFE targets. And so the difference will be effectively savings. Mike, it may not be at 10% across all year because we spent the first quarter more at those January levels.

And it’s a progression down to that 3.6 million, for instance..

Yes, that’s what I was getting at. I was trying to - but I can do the math there. Thank you..

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

Yes, so I’m curious as to - it’s good to see your crude differential coming down. My question is that what is the mix of your geographic mix of where your crude is being sold? And importantly, are you still selling stuff to the West Coast and what kind of differentials do you see? That’s all..

We are still selling crude to the West Coast. We have seen the differentials come in, and I guess the majority of our production is coming from the Rocky Mountains. We have differentials in Mid-con about - thereabout on parity on WTI, the target and on the oil.

On NGLs, about 50% off WTI is our target, and that’s about 16% of our Mid-con production, and then, the gas’s parity with Henry Hub, which is about 34% of our Mid-con production. And then on the Rockies, we are $10 off WTI. We have about 62% oil in the Rockies, 16% NGLs, which is targeted 70%, 75% off WTI.

And then on the gas side, Irene, 22% production in the Rockies and natural gas, which is about 10% to 15% off Henry Hub. That’s the target..

Okay. Thank you..

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

Yes. Thanks. You referenced that the pace of completions in the first quarter was heavily weighted towards February and March.

I recognize that you guys don’t give quarterly production guidance, and you’ve talked about flat volumes exit to exit, but my question is, should we assume Q2 volumes should be up sequentially given the pace of completions in the first quarter?.

Hey, Phillips. Yes, looking at our quarter-to-quarter, you know, we expect to be on plan and meet our production guidance range, as dictated for the year. But as we talked about quarter-to-quarter, you know, you do have lumpiness in production data pad drilling coming online.

So you will see lumpiness in our production, so - but again, we intend to be flat exit rate to exit rate, and we intend to deliver on our guidance range..

Okay. And then just in the Codell, for the first well that tested, the center region that’s been online for almost a year.

Can you remind us if that was completed with 18 or 28 stages? And for the follow-up well that’s currently flowing back, was that 28 stages or 25 and what are your expectations for that well?.

Yes. The Codell well that was first completed about a year ago it was completed with 18 stages, and we are continuing obviously to produce that well and are very pleased with that initial result. The second well was also completed with 18 stages.

Just to clarify, the spacing going down to 25 stages or increasing to 25 and 28 stages last year was more indicative of down spacing our Niobrara Bs and Cs to 40-acre spacing. That’s the reason we did that. The Codell being spaced at 160-acre spacing didn’t require us to do so.

So our plans are to continue to test that Codell well and see how she does..

Okay. Makes sense. Thank you..

Your next question comes from the line of Brian Corales with Howard Weil. Please proceed.

Hey, guys. Just maybe a couple follow-ups. I guess, the wells look good on the 40-acre spaced - those wells.

Are - is that now standard so the majority when you go through drill a pad - is a standard lateral going to be spaced at 40 acres?.

Hey, Brian. Yes, 40-acre spacing is part of our program going forward in 2015, especially as you look at our standard reach laterals. But when you look at our extended reach laterals, they are still spaced at 80-acre spacing.

That’s the one thing that we haven’t gotten to yet with our extended reach lateral development, is getting them down to 40-acre spacing. So, obviously with 30% of our program in 2015 being XRLs, those will be spaced on 80s. And then the standard reach laterals, we do have some mix on 80s but we do have some mixed on 40s there as we move forward..

Okay. And then you mentioned the capital budget. I guess we’ve seen a lot of E&P companies this earnings season come in under budget and they’re doing various things, whether accelerating or keeping the capital.

Is there something you are waiting to see to put more capital back to work, whether it’s oil price or more cost savings, say, the second half of the year or towards the end of the year or 2016 to maybe increase activity?.

Hey, Brian, it’s Rich. At this point, we are continuing with our 2015 plan. There is no plans to increase activity. I would say for future capital deployment deliberations, we’d be focused on understanding service cost stability and pricing stability so that we can have confidence in our prospective margins for deploying capital.

And there’s still considerable volatility as you can understand in the oil market, and the service market is still settling in. So we would want to see some substantive stability in those things before making decisions..

Okay. Now I understand. Thanks, guys..

Your next question comes from the line of Ipsit Mohanty with GMP Securities. Please proceed..

Good morning guys. Just missing from your release are those couple of wells that you completed on your new acquired acreage from BJ.

Now, understanding the desire probably very, very early preliminary science wells, just curious on the extent of color that you can provide on these and what you saw in them, what you learnt from them?.

Hey, Ipsit. Right now we are in the very early stages of delineation of the acreage to the north, so we don’t have any results obviously to report right now.

But I do want to emphasize that with the slowdown of our activity level, for us to get to a sufficient number of wells and data points to sufficiently describe the delineation of that northern acreage position, it’s going to take us some time. And we were planning to run two rigs up there to drill 40 wells initially to delineate.

We have just started into that process and we’re only going to do a handful of work this year. So as soon as we get the opportunity to where we have enough data points to give the sufficient answer to accurately describe that acreage, we will get that out as soon as possible..

Fair enough. Just wanted to see on your - seems like from the any things like a lot of the wells were brought online through the back end of the quarter, so that’s going to impact second quarter and then going forward.

What’s the extent of - what’s the percentage of extended laterals that you’re going to bring online through the year?.

Yeah, Ipsit, let me just delve upon - on the acreage position on your previous question. I do want to reemphasize to you that we have not changed our geological assessment of that we are still very confident in the geology on the acreage that we have acquired. So I didn’t want to leave any doubt on that.

Back to answering your question now on the volumes as we move through the quarter. Again, as we talked about, pad development making our production lumpy through the year. That’s expected. We’re going to have 14 pads contributing to that. We have XRLs mixed throughout our year, as we develop this year.

The XRLs that came on in first quarter this year did not contribute, because they came on later in the quarter. But again, we expect to exit the year, flat exit rate to 2014. We expect to be within our guidance range as we talked about, but there will be some lumpiness in the quarter-to-quarter production.

But I think if you draw a line from the end of the year to the end of 2015, you can kind of see where that’s heading..

Okay, thanks for the color, Tony..

Your next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed..

Thanks, good morning.

I guess not to belabor the question around the cadence through the year, but on that comment on lumpiness, any color around what’s anticipated to be higher or lower points throughout the year?.

Hey Michael, it’s Rich. The reality is, as we’ve discussed in our capital program and we’ve brought it forward in January, we effectively have 14 projects over 12 months. So if you think of each pad as a project, we have 14 assignments over 12 months.

That just inherently is going to create some variability over timing periods, some of those timing periods being over quarters. So, that just is what it is..

Okay. Fair enough. And then, as we think about the Mid-Con, I don’t know if I was reading into it right from the release, but you’d seen, I think, 15% quarter-on-quarter declines. No change to the expected investment plan relative to this quarter for the rest of the year, it sounds like.

So how should we think about decline profile of that asset throughout the course of the year? Yeah. I think the - there’s really no change in our production plans for Mid-Continent for the year on our projections. Again, when you look at the recompletion program, it’s a small, small capital commitment.

The average recompletion runs us about $60,000 to $65,000 per job. As I said, it’s statistical in nature. You have - you need a large data set of wells to get to the average performance. So as you carve that down to smaller and smaller data sets, you get larger variability. And so that’s kind of what we saw at fourth quarter versus first quarter.

But again, the statistical play nature of that program is a very economic program and one of the best opportunities we have in our portfolio..

Okay. Fair enough.

And then, I guess, any commentary on, I guess, locking up acreage within the acquired assets from last year, particularly that checkerboard in the South? I know that’s been an area of focus, any progress around that front?.

Hey Michael, it’s Rich. Yeah. We have a very active organic leasing program. You should expect us to be making progress in that all the time. We have nothing to report right now, but we would hope throughout the year that we have a productive period for that land department. So if, as and when, we’ll make sure we convey it to you..

Okay.

And then, the last one on my end is just the comment earlier about capital investment on - substantial capital investment on the Midstream over the coming years, maybe housing RMI, any quantification on how much potential capital we are talking about over the next few years as you guys see it?.

Hey Michael, its Bill. I think rule of thumb, as you look forward, is always about 10% of your overall capital budget. So depending on where capital budgets go and depending on where pricing goes, I think rules of thumb that would be 10%.

As we look back in September in more normalized price environment, clearly there was a whole lot more infrastructure going to be built over the next few years. And we started working on this and put this entity together.

So, I really don’t have any comment on how much infrastructure we’re going to build from a dollar amount going forward, but I think 10% of the capital is a good investment..

Okay. Great. That’s helpful. Thanks, guys..

Your next question comes from the line of David Beard with Bonanza Creek. Please proceed..

Hi. Sorry about that. We must have had a little confusion on the conference call..

Welcome aboard..

I just wanted to ask a couple of philosophical questions in ‘16. The first really will be related to how much outspend you’d be willing to tolerate and just kind of review that. CapEx versus cash flow; obviously we don’t know where pricing is going to be.

And then, maybe in conjunction with that, how do you look at hedging going forward and how you - might you structure your hedges?.

Well, on ‘16 we haven’t disclosed anything and really our thoughts for ‘16 on our capital budget this year as we reduce costs that will obviously go to continue to improve the balance sheet. And on the hedging side, we continue to review that, and clearly we want to get a better handle on costs and where costs are going. And then we’ll take action.

We haven’t put any hedges in as of March 31, but we continue to review that..

Okay, good. Thanks, guys..

Your next question comes from the line of Paul Grigel with Macquarie. Please proceed..

Hi, good mooring. Rich, at the start of the call you indicated potentially banking the savings for the - later in the year. You guys also noted the pace of spud activity is coming on faster than expected.

How should we kind of plan the confluence of those two elements together into year end?.

In our 2015 capital plan information disclosed to the public, we show all of the locations for the wells. We haven’t disclosed the timing of those locations, and some of that is open to some variability, so you just have to keep track of what we’re looking at doing looking forward.

Obviously wells in the January and February period will be costed in January and February costs, and wells moving forward from April-May-June will benefit from the AFEs. But we won’t discriminate between those for the time being..

As you guys head into year end, if wells are being drilled faster, it seems like the plan would be to slow activity at year end at that point in time, or is that a determination that needs to be made, depending upon outlook at that point in time on service cost and commodity prices?.

Well, if we drill wells faster then we have fewer dayrates to be booked against service providers, so that goes to the balance sheet. And our activity budget is the activity budget. So we have well locations, we have plans; we have supply chain logistics, all organized around delivering on those 14 pads. So that isn’t likely to change..

Okay. And then one for Tony, just on the extended reach laterals.

Any plan to move to test on 40-acre spacing going forward either in 2015 or into 2016?.

I would say not in 2015, for sure. Our plans are on 80-acre spacing, but I would suspect that as we move into 2016 that that would be the appropriate time to go down and test the 40-acre spacing on the extended reach laterals..

Thank you..

You bet..

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

Hey, good morning folks and thanks for taking my questions. And also unlike the production profile has been pretty well covered, so I just was thinking about the NGL sort of pricing, kind of converting to three streams.

Have you all disclosed or could you, I guess, refresh my memory what the rough mix of the NGL barrel that you all are selling up in the Rockies versus down in the Cotton Valley?.

We have not disclosed the NGL barrel mix, but we - on the Rockies, the breakup is 62% oil and 16% NGLs and 22% gas of the overall production mix, but we haven’t....

Okay..

...disclosed the actual barrel mix [indiscernible].

Do you have a rough feel for what the BTU content is of the raw gas stream?.

On the raw gas stream?.

Yes..

Rockies.

In the Rockies or in the Mid-Con?.

Rockies, please..

We don’t have the exact number for you, Andrew. I mean, generally we’re rejecting ethane in the Rockies, so it’s probably a little bit higher than the traditional 1,000 BTU. But don’t have the exact number for you..

Okay. All right, fair enough. And then, I guess looking at kind of just the capacity mix. With Sullivan up and running, how much of your takeaway, I guess, is firm versus interruptible? On the gas processing side, we are - most of our gas goes up through Sullivan from our Eastern acreage legacy position, as you know.

But with those two lines that we have now connecting the Eastern acreage to the Western side, we can now shift gas - and we have done so - shifted gas to our Western side and exited out through the 70 Ranch compressor station, and moved it to the West.

So we have a lot of flexibility in moving gas around right now that we didn’t have probably before the beginning of April. So we are really positioned, I think, really well going forward for Midstream.

With the Sullivan running very well now, with the connector lines, and with Lucerne 2 and the 70 Ranch compressor station, I’m really optimistic about how things are shaping up for us for the rest of the year on the Midstream side there..

Okay, great. So that gives you a chance then to optimize the various pricing points that you are getting on NGLs and everything else. Thanks very much..

[Operator Instructions] Your next question comes from the line of David Tameron with Wells Fargo. Please proceed..

Hi. Congrats on the quarter. I know the differential you guys have in improvement.

Can you talk about - if we think out a few years, and with some of the DCP stuff up and some of the gas processing now taken care of, at least near-term in the basin, is there any - if you think out two to three years - any chance that that differential comes in a little more on the oil side? Or are we in that $8 to $10 range as a permanent fixture for the basin overall?.

Hey David, Bill here. Look, I think that we would expect the differentials to move in, given the pipeline capacity that we’re going to see coming on in the basin. Also that we see some of the rail capacity I mentioned earlier coming in from the West Coast, which gives us additional competition to move the barrels out of the basin.

So I think that, coupled with the slowdown in activity that we’ve seen over the last six months or so. By the time that all ramps up and take into account the timing of the Grand Mesa Pipeline and other pipelines coming into the basin, I think you will see differentials start to tighten in.

Obviously we had an $8 differential back in September 2013, prior to the flood. We got quite a bit in the last 12 months or so. We’re seeing that all come in due to previous mentioned pipelines and slowdown activity..

Okay. So a couple years down the road you won’t be surprised to see maybe a 6 or 7 type differential.

Is that fair if I think out to maybe next year 2017?.

Look, I think we’ve always just given guidance for quarter ahead as we see it. So looking out to two or three years down the road is probably a bit more speculation on my behalf. So I will leave everyone else to think about that..

Right, fair enough. Thanks. Thank you..

Your next question is a follow-up from the line of Ipsit Mohanty with GMP Securities. Please proceed..

This time I have to correct it, it’s GMP Securities. Thanks for the follow-up, guys. Quick question to perhaps Tony.

If you could comment anything that you can on your success with plug-and-perf and some of the other techniques that your neighbors are talking about and doing in the basin, and what your experience has been with them?.

Yes, Ipsit, hey. What we are doing on our frac side, as you know, we are using the gel frac systems and we use the sliding sleeve with the Swellpacker technique. And that is kind of our go to system. We did do two plug-and-perfs at the end of last year and we are evaluating those results right now.

But we have not made any significant changes to our programs on our frac designs that would be merit to anything else at this point..

All right. Thank you..

You bet..

Your next question is a follow-up from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed..

Thanks. Yes, I was just thinking through.

As it relates to Lucerne starting up this summer and the situation around NGLs, I think just broadly and regionally, have you all had any discussions or thoughts around the increased supply of product that will likely come from Lucerne, potentially weighing on realizations through the summer? Is that something we ought to contemplate? Any thoughts around that?.

Honestly, I do not think that there’s going to be anything to really weigh in, especially for the rest of this year, as Lucerne 2 comes online. Obviously I would view Lucerne 2 as a positive event across the board, I think, for the operators in the area. So, I want to keep that in that mindset, very positive for us as that comes on..

Yes, no, that makes sense. I just thought I figured I’d ask. Thanks very much..

You bet..

With no further questions in queue, I would like to hand the conference over to Mr. Rich Carty for closing remarks..

Well, thank you again for spending time with us this morning. We appreciate the support you provide for the franchise and I look forward to our next opportunity to update you on our progress at Bonanza Creek. Have a great weekend..

Thank you for joining today’s conference. That concludes the presentation. You may now disconnect and have a great day..