James Masters - Investor Relations Manager Richard Carty - President and Chief Executive Officer Bill Cassidy - Chief Financial Officer Tony Buchanon - Chief Operating Officer.

Irene Haas - Wunderlich Securities Brian Corales - Howard Weil David Deckelbaum - KeyBanc Phillips Johnston - Capital One Paul Grigel - Macquarie David Beard - IBERIA Ipsit Mohanty - GMP Securities Ken Beyer - Stifel Andrew Coleman - Raymond James Jeffrey Connolly - Clarksons Capital Markets Mo Dahhane - Northland Securities Matt Sorenson - Global Hunter Securities.

Good day, ladies and gentlemen and welcome to the Quarter Four 2014 Bonanza Creek Energy Incorporated Earnings Conference Call. My name is Cathy and I will be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. [Operator Instructions].

As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to, Mr. James Masters, Investor Relations Manager. Please proceed sir..

Thank you, Cathy. Good morning, everyone and welcome to Bonanza Creek’s fourth quarter and full year 2014 earnings conference call and webcast. Yesterday afternoon, we issued our earnings press release and this morning filed our 10-K with the SEC. You can access both on our Web site.

It is my pleasure this morning to introduce, Richard Carty, Bonanza Creek’s President and Chief Executive Officer for his first conference call with the company.

Rich officially took over the role in November and has since been actively engaged in finalizing the 2015 budget and getting to know key stakeholders in the midst of a very challenging market environment. On this call he will provide a brief overview of 2014 results and 2015 strategy.

Following his remarks, Bill Cassidy, our Chief Financial Officer will discuss financial highlights and our recently completed equity offering. Finally, Tony Buchanon, Chief Operating Officer will review operations. As usual we have endeavored the key prepared remark short to leave ample time for Q&A.

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 these measures to the most directly comparable GAAP measures are contained in our earnings release. With that, I will turn the call over to Rich..

Thank you, James. Good morning, everyone and thank you for spending time with us today. I’ve enjoyed meeting many of you over the past several months and have appreciated the chance to share our vision of Bonanza Creek. For others that I have not yet had the pleasure to meet, I look forward to having the opportunity soon.

2014 was a very successful year in many respects, in operations, we grew sales volume by 45% and increased EBITDA by 33% and our recent improvements in hydraulic fracturing methods with 28 stages demonstrated 21% increases in 30 day production rates with a 7% increase in well capital.

On a strategic front, we doubled our acreage footprint with an important $213 million acquisition in the Wattenberg Field and a corporate finance returned better balance sheet with a timely issuance of $300 million of high yield bonds with a 5.75% coupon and a 2023 maturity to match the investment horizons of our acquisition.

With respect to execution, our results for the first three quarters of the year mashed our internal engineering forecast for measured growth. But as we previously disclosed the fourth quarter was impacted by disruptions related to weather, third-party infrastructure downtime and a delayed five well pad.

That said, I am very pleased with the overall achievement demonstrated by the Bonanza Creek team and acknowledge this as another milestone year for the company. This is the first class organization that I am proud to lead behalf of our stockholders.

We have demonstrated the value of our high quality asset base, which is complemented by prudent financial stewardship and a capable execution team. Together we have positioned the company for sustaining success. Looking ahead, 2015 will be a challenging environment that will test the E&P industry.

Our senior leadership team is well prepared to lead the organization through this complex environment to be tactical and preemptive when opportunity provides and to be disciplined and deliberate and affecting our mandate. In this lower price environment, we’re focused on maximizing the productivity of our capital expenditures.

As such our 2015 budget is designed to drive efficiencies by maximizing our ability to leverage fixed assets in surface infrastructure while producing the multiple sub-surface intervals and our full-field development strategy.

To compliment the rigor of the budget plan, the company’s financial condition has been structured with the margin of safety given the evident increase in the volatility of externalities in our business environment.

We entered the year with liquidity availability of approximately 750 million, a competitive balance sheet without debt maturities before 2021 and pro forma net debt to 2014 EBITDAX of 1.7 times. To speak briefly about the circumstances in the oil markets, it is a time of contradictions.

For instance it's curious that an approximate 2% global excess supply of oil which equates the seven days of global consumption has impacted oil prices by greater than 50%. Apparently the implied marginal value of storage for seven days consumption is considerable indeed.

In contrast, preliminary 2014 figures indicate that discovery the new oil and gas reserves around the world continue to deteriorate with 2014 marking perhaps the worst year for finding oil and gas since 1952. So small changes in short-term supply have triumphed large ongoing deficiencies and long-term reserve replacement.

If only we can each store our share of the oil we consume for a rainy day. Nevertheless we are very pleased of Bonanza Creek to reflect upon our 2014 reserve replacement ratio of 330%, our 28% growth improved reserves which comprise 52% proved developed and 48% proved undeveloped and at 40% growth in 3P reserves.

Our aggregate 3P reserves now register in excess of 550 million barrels of oil equivalent which when compared to our current enterprise value represents approximately $3.82 per BOE.

As many of you may appreciate our unconventional oil resource which resides in a 6,500 foot deep reservoir can be brought on to production and into sales lines in less than 45 days and is thereby effectively an old storage mechanism enabled by the metrics ferocity of our sub service geology, so storage we have at Sebring Pickens once said and as may yet be relevant again has become cheaper to look for oil in the flow of the New York Stock Exchange and in the ground.

Notwithstanding it seems us the only certainty on the horizon will be the shortage of things that will surprise as many future outcomes appear plausible in the industry. While we promise to keep it short so I will give the floor to Bill to give you a quick overview of the quarter’s results and the equity offering completed earlier this month.

I look forward to taking your questions..

Thanks Rich and good morning everyone. As Rich mentioned, we grew production by 45% in 2014, prove reserves by 28% and 3P reserves by 40%, a very successful year and I add my congratulations to the Bonanza Creek team. I wanted to briefly comment on three notable topics in yesterday’s release. The first is a non-cash impairment charge of $167.6 million.

The significant decline in oil prices triggered the company to assess its proved oil and gas properties for impairment.

If the CEO’s net book value exceeds its future net cash flows then the cost of the property is written down to a value based on discounted future net cash flows estimated using commodity prices established in our 2015 budgeting process.

Most of the impairment charge relates to the Dorcheat Macedonia Field which represented the majority of the company’s proved reserve value at the time when the company restructured from an LLC to a C Corporation in December 2010 in a much higher oil price environment. None of the impairment charges is related to the Wattenberg field.

The second topic to address is DD&A, for the quarter DD&A was approximately $29.50 per BOE and $26.66 for the year.

This DD&A per BOE level is a consequence of three primary factors; first, higher start up production growth rates, 45% in 2014 outpacing historical reserve growth of 28%; second, the legacy effects of the cost attributable to the vertical well portfolio; and the third relates to the purchase accounting basis of our Mid-Continent assets that resulted from the 2010 corporate restructuring.

Back then when we isolated our DD&A rates to the current horizontal program in the Wattenberg and removed the costs associated with vertical wells, 2014 DD&A is more than 10% below 2014 annual rate. This is more in line with what we would expect to see for these assets.

I would also like to highlight that contributing to the higher DD&A rate is a conservative booking philosophy for proved reserves. Currently 95% of our PUDs are direct offsets to existing PDP producers leaving only 5% of PUDs that are more than one direct offset from our producing well.

In addition we are very cognizant of the SEC’s five year PUD development rule and are diligent in only adding PUDs that are in our development plans resulting in a PUD percentage for the total company of 48%. And the third topic to address relates to severance and ad valorem taxes.

During the fourth quarter 2014 we decreased our Colorado severance accrual rates on increased ad valorem tax credits related to the 2013 production year. 2013 was our first year dedicated entirely to horizontal drilling in Weld County. The ad valorem credits are not eligible for deduction in the year the well is completed.

We are now seeing the effect of more ad valorem tax credits eligible for deduction against several taxes generated in the current year. As we look to 2015 the guidance of 10% we had given for 2014 could have some downward bias, but we are not adjusting our guidance to you at this time.

Finally I want to mention the equity offering we conducted on February 6. We raised just over $200 million of net proceeds and after paying off borrowings under revolver ended the year pro forma with $172.5 million in cash.

We were very pleased by the market reception that allowed us to upsize by 75% from the original offering and still be four times oversubscribed. It was very reassuring to us that the markets view positively our proactive response to the current environment. Now I’m turning the call over to Tony for an operations update..

Thanks, Bill. As Rich discussed earlier the confidence we have in embarking on the 2015 program stems directly from the success we achieved in 2014. Wholesale development isn’t a buzz word; it's where we are after four years progressively intensive exploration, delineation and optimization of the sub-surface.

Everything we said we would do, we have done. Remember one year ago the super section was our first initiative to understand well down spacing, interval stacking and full-field infrastructure development. The super section showed us that stacked wells in the Niobrara B and C was an improvement of our single zone pads.

It was also the first time we used centralized processing facilities with multi well pads, a model that will be utilized to a great degree in 2015. The 40 acre down spacing test with 18 stage fracs showed good old results, but clearly we had room for improvement.

Again testing 28 stage fracs and various 40 acre spacing configurations that each showed significant improvement culminating in a successful five well stacked 40 acres spaced Niobrara B and C bench pad to check the box for us that 40 acre down spacing and stacking between the Niobrara benches is the preferred way to develop this assay.

Tremendous progress in one year and we’re fortunate to have largely completed it when we did. During the fourth quarter, the company finished its field level gas gathering infrastructure project and in this current quarter is completing the installation of the remaining compression facilities.

This system is expected to achieve lower and more stable line pressures at the well head as well as quicker recovery times in the event that third parties experienced unplanned midstream downtime.

Moving on to reserves, as Rich and Bill have mentioned already, we increased proved reserves by 28% to 89.5 million BOE for 97 million barrels on a three-stream basis, 76% of which is assigned to the Rocky Mountain region. In Rocky Mountain region, our PDP reserves increased by 55% and the associated PUD reserves increased by 26%.

Reserve replacement for the company was a strong 336% and the total company 3P reserves also increased by 40% to 497 million BOE or 558 million BOE to restrain, with net potential drilling locations increasing to over 2,300 locations company wide.

Finally, as it relates to declining well cost, we are seeing encouraging movement from our service partners augmenting the already impressive efficiency gains we’re seeing form our own efforts.

We are inherently conservative and avoid aspirational projections about well cost, but rest assured that we are taking full advantage of our own efficiencies and with our supply chain organization working with our service partners, we expect to see 4,000 foot laterals below $4 million in the near future.

When we have sufficient clarity on our longer-term expectations on our well cost we’ll happily update you all. I’ll stop there and turn the call back over to the operator for Q&A..

[Operator Instructions]. Which comes from the line of Irene Haas of Wunderlich Securities..

Yes, my question has to do with now that in 2015 you're going to go into full development mode.

So can you maybe give us a little color as to which part of those deal you're going to start and what configuration and interestingly the acquisition acreage when would we see some activity in that particular area would you need more time to have that figure out, just want to have some sequencing just to get a feeling as to how you're going to tackle your very contiguous selling base?.

We’re going to focus on Irene is basically the middle part of our acreage to what we call our heritage legacy position where the infrastructure is currently built out, so the 35,000 net acres that we have previously developed.

So our 2015 program is going to broken up into about 70 plus wells with 14 pads with basically most of that all taking place on that middle position and again it's because we are leveraging these exiting infrastructure.

As for the new acreage that we acquired last year we’ll have some limited exploration or should say development wells up there on a north side, three wells is what we’re planning for right now, but again with limited infrastructure we’re going to plan to stay in that legacy position..

And all the pads I presume has been built and are ready to go?.

Well, the early part of our pads are being built yes, Irene and we are going to be leveraging the existing infrastructure that’s there but the pads are being built as we speak as we move through the program..

Thank you for your question. The next question comes from Brian Corales of Howard Weil..

Maybe the first question for Bill, where do you feel comfortable on the balance sheet or is there is a metric that we should look at to kind of assume going forward? And then when do you all think you can start putting on some additional hedges maybe for '16?.

Well, I guess metric, you mean that on the leverage side, Brian?.

Yes..

We’ve always been very conservative on the balance sheet and I think the equity deal will -- it kind of demonstrates, that will continue in that vein.

And on a metric we’d spoken that we had a metric in the past and we will endeavor to continue to keep a very prudent balance sheet going forward, I am not sure there is an exact number we had two times in the past and we’ll endeavor to hold very strong balance sheet going forward.

And on the hedging side I think with the equity deal it’s given us a little bit more liquidity to assess where the market is going to go over the next few months, I am sure folks probably would want us to hedge at the current level. And we’ll assess the market as it progresses; I think this gives us a little bit more breathing room..

And then just one more….

And then also Brian we want to see where cost starts settling down, that’s the key..

And on the 3P inventory I know it’s the Codell increased a descent bit. Can you maybe comment, I know in the past you have tested thinner zones.

What are you all including right now for the Codell in that 3P inventory?.

Brian, right now we have the Codell on a 160 acre spacing on our legacy position it's focused on the 15,000 acres on the Western side. And then we do have some Codell locations on the new acreage position that we have picked up from DJR last year on the North side and on the South side..

And maybe just to add to that I know you have tested the thinner Codell I guess down to six feet.

Have you included any of that into the 3P inventory yet?.

Brian, no, we have not. We did do a couple of tests and we’re still evaluating that we were encouraged with our first test that we have talked about previously at the 426 barrel of IP rate for 30 day rate, so we are still testing that. But no we do not have that included on our current 3P inventory..

Thanks for your question. The next question comes from David Deckelbaum of KeyBanc..

Sorry if I missed the color on this, but looks like you guys are above plan at least in the Mid-Continent in the fourth quarter, at 6,500 a day I think the guidance for '15 was to kind of hold like 5,900 a day basically flat throughout the year.

Can you give any color around that?.

Yes sure David, part of that production increase in 2014 fourth quarter in the Mid-Con was associated with our recompletion program. And those recompletion programs, it’s a statistical play, we had a good run on those recompletions but those recompletions do decline at a certain rate. And so that is what we factored into our 2015 planning..

You have those recompletions declining at higher rate than the standard well completion there or does it basically exhibit the same sort of curve shape?.

It demonstrates kind of similar decline rates as our current wells, but I think the biggest part of that David is the statistical nature of those recompletions.

We do X number during the year knowing that a certain number will work out there but again it’s statistical and difficult to predict which best ones are going to happen at what time that’s why we do the number that we do..

And then you guys mentioned the added compression helping the fine pressure and obviously fourth quarter Rocky’s production was impacted by 750 barrels a day from midstream down time.

What sort of downtime have you experienced so far in the first quarter and can you kind of contextualize any improvement from the investments you’ve made?.

Well, I will say that obviously we’ve had cold weather and third party downtime in the first quarter specifically in January but we want to reaffirm that we are confirming our guidance for the year.

We do have our compression in place that is assisting us and as you know David we have additional compression coming online with DCP specifically with the 70 Ranch compressor station, the Rocky compressor station along with the expansion at Lucerne 2 here in second quarter that will greatly assist us in line pressure.

And one other addition is with the Grand Parkway we will have a connection line connecting our eastern acreage to our western acreage, which will give us two takeaway points for the gas that’s produced on our eastern acreage that now currently all runs through the Sullivan plant, we’ll have some flexibility here in the early second quarter to move that gas either to Sullivan or through the 70 Ranch compressor station onward to Lucerne 2 which provide us a lot more I think consistency in our line pressures that coupled with our own compression helping us out and then with own compression also helping us recover from their downtimes as they go down and come back up..

So at least it sounds like at least from the first quarter the percentage of downtime that you’ve experience is much lower than fourth quarter, is that fair?.

We're not all the way through the quarter though David, but I would say yes, but I do want to emphasize that obviously there has been cold weather in January, but we would reaffirm our guidance for the year..

And then delays from the pads that was supposed to come on in the fourth quarter that came on in the beginning of the year right so that would benefit your first quarter as well?.

That’s correct but we do have that factored into our production guidance..

Thank you. The next question comes from Phillips Johnston of Capital One..

Just a follow-up on Brian’s question earlier on the Codell. You’ve expressed confidence that close to 30,000 net acres as perspective.

Do you view that as a minimum type of number that has upside potential as you continue to sort of test that new acres that you acquired or do you think that’s close to the final answers so to speak?.

I would say at this point that the 30,000 is probably a good number, but again as with we’ve done with other zones I hesitate to say that that’s the extent as we will continue to test those boundaries and as we have success we’ll continue to push that, but again we don’t have that captured in our 3P, but I would think that we have additional potential, yes..

And then just with the shift from four acre to 2.5 in the Wattenberg.

Can you maybe walk us through to quarterly progression of your production vibes throughout this year seems like we should maybe be up sequentially in Q1 and Q2 and then maybe flatten out for the remainder of the year, but is that safe to assume?.

Yes, we have 14 pads that we are drilling this year. The intent of our plan for 2015 is to maintain exit rate from December of '14 to December of '15. So we expect a fairly a linear progression through the year, but as we’ve talked about with 14 pads, pads tend to provide lumpiness in production.

But there has been no intent to have a higher quarter or lower quarter throughout the year, our intent is to try to keep this flat as possible, but as for how it actually occurs, we are little bit dependent on how those pads come online in each quarter..

And then if I could maybe follow-up on that. If we kept the 2.5 rig program in place throughout all of this year and pretty much all of next year.

What would you expect your '16 production to look like at least from a directional point of view? And what it would sort of take on the oil price front just to cause you to either further slowdown activity or accelerate activity?.

I’ll take here the first one is that, we have not laid our 2016 plan yet and so we’ll continue to address that as we go through the year based on the macro circumstances.

As for which price, there is a lot of variables that go into what we will be planning to do with price, cost, forward looking price curves, all that is stuff that we -- we look at that all the time from our end, but we’re not ready to obviously talk about 2016 at this point, we’ll just take those as we go through the year then evaluate little bit further in the year from that standpoint..

And the next question comes from the line of Paul Grigel of Macquarie..

Just focusing on the differential, as they continue to make progress in tightening up in the Wattenberg.

Could you just kind of speak to what you guys view as the trend and is there potential for even inside the kind of nine to 10 range as more takeaway capacity in the oil side comes on 2Q and into later in the year?.

At the moment we’re looking at the kind of 10 to 12 with the guidance to head lower to that number. The DJ lateral is coming on the second quarter and then clearly you have the Grand Mesa pipeline coming on in next year. We’re seeing some real capacity open up into the West Coast.

And I think that all these factors are going to drive those differentials down to historical levels where I think September 2013 were about $8 as a differential. So, I think we’re going to see that trend head in that direction again..

And then Bill just following up on the DD&A comments you made earlier, just want to make sure I understood them saying that DD&A for the Wattenberg horizontals was 10% lower.

As you look at 2015, would you expect kind of 10% off for the 4Q number to be held for the company as a whole or would we expect to be closer to the 29 unchanged number for the company..

I think will be 10% of the annual number which is the 26 -- 66 approximately 10% off for the whole company..

And the next question comes from David Beard of IBERIA..

My question kind of follows along Bill’s line of thinking. But maybe you could talk a little bit about your decline rate going into 2016, just given you have a much different production profile this year than previous years.

And how much money it would take to it to spend to keep that flat again in '16?.

So our decline rate was 45% in 2014 and we’re going to have a flash production to exit '14 to '15.

I think if you look at the cost to keep that or maintain that our budget we came out which is 420 million, if you back off some of the infrastructure and back off you probably get to 400 maybe a little bit below 400, that basically is the maintenance for our 2015.

For 2016 we haven’t gone into that at this stage, but I think given more flat year-to-year on production you should see kind of 400 as the maintenance capital there..

So decline rate is about the same of that 35 maybe it touches above we're going into '16 and a little less capital is that fair?.

Yes, you would assume the decline rates to come down if you look at the trend from '12, '13, '14 its 54%, 53% and 45% for last three years. And with the larger base production you should see that decline rate being a little bit lower for at year end..

Thank you. The next question comes from Ipsit Mohanty of GMP Securities..

My first question on oil realization. On one hand you are watching those differentials are going down which is great but on other hand you have little proportion of Arkansas property production in the mix for '15 going further out, and historically did give you an uplift on the pricing.

So net-net if you look at for Q4 '14 going forward to '15, how does the oil realization looks like as a percentage of [DI], is it going to be similar to 4Q, any color on that?.

We haven’t really guided on the overall differentials for the year ahead. I think we can be -- just looking at Mid-Con we would see those differentials staying the same and then Rocky’s from an earlier comment I think that’s what we should be looking at.

So having really guided it’s tough to look at with quarter-over-quarter into the Rocky’s given the amount of changes going on, we’ve seen it come down from the high of kind of 15, 16 differential on the oil side in 2014 all the way down to the kind of $10, $12 range and we see that going on further, we don’t see a whole lot of change at Mid-Con..

And then second question on the production taxes, as what you've seen in 4Q is that sort of -- is that trend likely to continue into '15 or is it going to, the production tax is going to go down even further?.

I think you should really look at the annual basis which I think we’ve guided at about 10% and we should just continue with that moving forward into 2015 to be conservative on that side..

And then one of -- you’ve talked about well costs going down even further beyond 4 million on standard lateral. I see one of the reasons the service and vendor cost reduction, it's hardly 5% in your current slide.

Is that where you're going to see a substantial change as you look at the well cost reduction? Or are there any other aspects behind going down even below 4 million?.

As we factored in our cost for 2014 changing to 2015, the two biggest pieces so far were the two things that we can control which was reducing the number of stages from 28 to 25.

And then of course leveraging our fixed infrastructure for the program as I mentioned earlier, but the remaining cost reductions we would think would come from our service partners as we continue those ongoing negotiations with them. And so I think that’s where that will come from in 2015..

Just give us an idea of how you look at the trend? I mean right now where it is and where do you see that going towards the end of the year?.

Again I hate to say it, but I don’t want to be aspirational in my projections. When we looked at those costs at 4 million that’s where we stood at the beginning of January and those were costs we knew that we could capture and we were seeing evidence of that and we’re very comfortable from putting that into our budget as an unknown quantity.

I would suspect as oil prices continue to remain lower that those costs will come down. But I can’t tell you is what kind of percent those will be. As you know our base in the Wattenberg is an active basin, cost will come down faster and other basins where economics are more challenged.

We have strong economics in the Wattenberg, so the activity levels will be slower to come down. And I would also say that we also are going to be hopefully seeing additional iron moving into our basin and that will be something we can take advantage of but as soon as we get those numbers we’ll get those to you..

And then my final question is on extended laterals. You’ve got as much as a contiguous block of the acreage as anybody else among your peers. And then some of them have guided for a higher proportion of extended laterals in '15. I understand it's a jump for you as not given where you are.

But would you see that sort of going up in terms of your comfort level in it, drilling these extended laterals.

Would there be any uptick in your current guidance of the proportion of extended laterals?.

Again I would emphasize, our acreage is very well set up for extended reach lateral drilling, but the focus of our program in 2015 was to maximize returns on the wells we were going to drill in 2015, and the biggest part of that was leveraging the existing infrastructure.

And that existing infrastructure that we have is in the middle part of our acreage that 35,000 net acres that made our legacy position. Our northern position and southern position that we had recently acquired has less infrastructure. So, we focused our drilling in that infrastructure area.

Anywhere in that area where we could drill an extended reach lateral because it is an improved economics of our standard reach lateral and leverage existing infrastructure we did that.

But leveraging the infrastructure provided a more positive impact to the return on the well in 2015 than it is by drilling an extended reach lateral versus standard reach lateral. So standard reach lateral with existing infrastructure yields better economics than in extended reach lateral but I would actually have to build infrastructure to.

So our program focuses on that and if you look at our investor presentation we obviously have that slide of where our pads are; the pads on the western side of our legacy position are going to be 4,000 foot laterals, that’s because we actually started with 4,000 foot laterals in that.

But the remaining parts of our position you’ll see us go to extended reach lateral drilling in the future..

Thank you. The next question comes from Ken Beyer of Stifel..

First question just wondering if you guys have any data available for your 25 stage wells and if -- or I guess how those are tracking against your type curve?.

We have just started to implement the 25 stage technique. Again we expect no degradation to the type curve.

When we went to the 28 stage fracs from the 18 stage fracs the key there was the 18 stage frac on a 4,000 foot lateral had 220 feet approximately between stage, when we went to the 28 stage frac that dropped it down to about 145 foot between stage, we saw the benefit.

As we would have done in a $90 world or $45 world, we would then continue to optimize our completion techniques.

With our engineering teams looking at it, we felt that we could come back on those 145 foot stages that add about 15 feet and bring this to about 160 foot per stage which caused of those three stages taking us from 28 to 25 and still yield those same results that we have seen from the 28 stages..

And then in your 10-K release this morning I noticed that says that you're planning on developing Niobrara B and C at 16, 40 acre spacing.

I was just wondering does that imply that you're seeing any kind of well communication at the 40 acre spacing or are you still planning on developing the entire acreage on 40 acre spacing?.

Our plan is to develop the Niobrara B and C on 40 acres spacing across our acreage position. We do have some areas of our field where we’re drilling these extended reach laterals that we are drilling those on 80 acre spacing at this time, but our intent is to get down to 40 acre spacing..

And then was just wondering if you guys can speak to the legislative environment in Colorado given the recent findings and proposals from the Colorado Oil & Gas Task Force? And kind of what percent of your acreage could be affected or rather what percent of your acreage is located near suburbs of recreational areas?.

So the Colorado Commission is reporting to the governors, so we’re waiting to hear back from them as they finished all their open mic sessions which they had over the last number of months.

When we looked at this in the past the 2,000 plus offset proposal we were at 3% approximately affected using regular reach laterals, if you move that to long reach laterals none of our acreage is affected by any setback rules proposed..

And then just one more quick one.

You guys see any consolidation in the bid/ask spreads or possible bolt-on acquisitions?.

Not really, we’ve seen there are opportunities come up, we look at the opportunities and if they are appealing we’ll go after them we’ve got over 2,000 locations to drill in the basin and we think we’re attractively positioned from a contiguous acreage position if we see bolt-ons will blast and we really haven’t seen any changes in pricing at the moment..

The next question comes from Andrew Coleman of Raymond James..

I think you covered this on the call when I was just kind of looking to the notes there. With the slowdown in the Cotton Valley activity and that had a nice uptick and volumes are about 10% growth in the fourth quarter there.

I guess what would the shape of that trajectory look like as you go through '15? Can you give any color on that please?.

Andrew the uptick again in the fourth quarter was associated with our recompletion program. That recompletion program is a statistical program, so we have to do certain number of recompletions to get those. What we can’t project is exactly which ones are going to be the good ones throughout the year, so that’s what we do with certain number of those.

The decline rate on those are kind of approximated by what we have for our regular drill wells so that’s kind of we factor in there. But again that production can be lumpy quarter-to-quarter as we do those recompletions depending on how the statistics play out..

And you had added capacity out there added a second plant I thought, that was maybe 18 months ago.

I guess there is still capacity at that plant and does that factor in your equation or is it just clearly the kind of statistical nature of kind of all those recompletions?.

We have the plant capacity we have an integrated midstream asset that ties into our production out there. We have the capacity to handle the gas that we produce and we do have additional room at those plants..

Thank you for your question. The next question comes from Jeffrey Connolly of Clarksons Capital Markets..

What kind of opportunities you have to grow the lease position just through others either non-consenting or just through organic leasing on your part?.

Obviously non-consenting is a great way for us to continue to lease our interest certainly at the wellbore and we have seen opportunities come up and as we see them we’ll take advantage of we think they’re going to work with our position clearly our contiguous nature of the acreage as that puts us in advantage as Tony has outlined earlier.

And then we continue to look at opportunities as they come up..

And then let me ask one more for Tony, it’s kind of been [part down] a little bit.

But the 4 million well cost for the 400,000 foot lateral as of January, can you give us a number for what current AFEs are at?.

Again I want to reaffirm that the 4 million that we had at the beginning of January was a known number at that point factoring in our infrastructure, factoring in our completion design and current captured pricing that we had from our service partners.

We are in the process of working with our service partners to see what those cost reductions can look like going forward and as soon as I have more clarity on that I’ll surely get that out to you.

We do suspect in this lower pricing environment for oil prices that we would suspect that the cost will come below that $4 million, and as soon as I have the opportunities to have more clarity on it we’ll get that up..

Thank you. The next question comes from Mo Dahhane of Northland Securities..

Just very quickly you guys talked about drilling a second step-out Eastern Codell well.

Any updates on that well?.

No not at this time. We have some additional Codell wells that are testing at thinner Codell acreage that are in progress and as soon as we have some additional results on that we’ll get that out. But again we’re encouraged by the first one that we have done, but we have not factored that into our 3P analysis at this time..

And my second question about the Niobrara A well, do you have your 60 day average for that well, or no?.

The Niobrara A again we had our IP-30 of 325 BOE a day. We're continuing to watch that well, we suspect that we’ll have to do some work on the Niobrara A going forward but that would not be something we’re pursuing currently in 2015 as we produce the risk profile of our program through reduced catalyst testing..

The next question comes from Matt Sorenson of Global Hunter Securities. Matt your line is now live..

As you guys convert to three-stream, could you guys help us understand the impact on your gas and NGL differentials?.

I guess we haven’t really quantified that in the public yet and we’re assessing that as we go through. So there will be some minor impact, but we don’t expect a whole lot and we'll come back with more details as we get that information..

As you move into 2016, about what portion of your undeveloped acreage at that time will have existing infrastructure on it?.

I’m sorry Matt could you repeat the question please?.

As you move into 2016 about what portion of your undeveloped acreage will have existing infrastructure on it?.

In 2016 if I heard the question right which portion of our acreage will have more infrastructure? I think as you know in '15 we’re focused on developing our legacy position because that’s where the infrastructure is currently.

And so we are not going to be investing a whole lot of money in infrastructure on the new acreage position ourselves in '15 as we focus our capital to just strictly as much as we can to be B&C. So really not much will change from '15 to '16 as we go into that year..

Cathy, just a second. Matt I am sorry this is James Masters. I wanted to address your realization question on the gas NGLs in Rocky's on the 3Q basis. Right now it's a little bit hard to nail down as Bill alluded to because this is a first time we’ve really been selling our own NGLs for our account.

But as far as we look forward to '15 for our model, the NGL pricing is approximately 30% of WTI, and the natural gas realization is approximately 80% [trending] up.

And that’s pretty consistent across the company as you recall in the Mid-Continent NGLs historically had a stronger pricing relative to what we see at the Rocky's and more in 50% to 60% range. So corporately we’re seeing 30% and as I said gas probably about 80% [trending] up..

I would now like to turn the call over to Richard Carty, President and CEO for closing remarks..

Thank you very much for your attendance on the call today. We appreciate the ongoing commitment of our investors in the company; encourage ongoing report with them and we look forward to a very successful 2015. Have a very good day..

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day..