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Executives

James Master - Manager, IR

Mike Starzer - President and CEO

Gary Grove - EVP, Engineering and Planning

Tony Buchanon - VP, Rocky Mountain Region Engineering

John Larson - VP, Mid-Continent Operations

Lynn Boone - SVP, Reservoir Engineering

Ryan Zorn - VP, Finance

Analysts

Scott Hanold - RBC Capital Markets

Brian Corales - Howard Weil

Irene Haas - Wunderlich Securities

John Malone - Global Hunter

Adam Michael - Miller Tabak

Andrew Coleman - Raymond James

Ryan Oatman - SunTrust Robinson Humphrey

Chad Mabry - KLR Group

Bonanza Creek Energy, Inc. (BCEI) Analyst and Investor Day Conference Call April 11, 2013 11:00 AM ET

James Masters

Good morning everyone. I apologize for the technical difficulty. My name is James Masters, Manager of Investor Relations. I know most of you. Thank you for coming. We sure appreciate the significant effort that you've expended to come out here in Denver in the middle of a snowstorm in spring. So thank you for being here (inaudible) a little bit tight. We will get started right now. I just wanted to go through the disclaimer, obviously we are going to make forward-looking statements today and talk about reserves and talk about tech curves, talk about things that may or may not happen. We are just at your convenience.

So I'll just introduce Mike Starzer, the President and CEO, many of you have met Mike. Mike has been the CEO of Bonanza Creek through its many iterations since 1989 and has got us to where we are today. I won't take any more time with the introduction, but as many of you know Mike that he is going to step this up, through a company overview and themes. He will pass it on to Gary Grove, who is our Engineering and Planning Executive Vice President. He will give a short operations summary of where we stand today. From there Gary will pass on to Tony Buchanon. Tony came to us from Noble about six or eight months ago and he has really taken over our Wattenberg horizontal program and he will give you a wholesome review of our operations and actual results as compared to type curves and that sort of thing. He is really going to be the highlight of our presentation and he is going to do a terrific job. From there Tony will turn it over to John Larson. John is our Vice President of Mid-Continent region. He will give an overview of everything we are doing out in the Dorcheat-Macedonia field and McKamie-Patton including the five acre spacing test that we have been undergoing over the last six months and the inflation there.

From there Lynn Boone, we have a highlight of our presentation, will cover resource potential and inventory as we see it here in the Wattenberg field and in the Mid-Continent region. We've done a fulsome review over the last six months of this company and she is going to roll that up for us. She has joined us about six or eight months ago from Bill Barrett Corp. where she handled a reservoir engineering for Barrett over the last seven years, and is doing that here for the next Bonanza Creek. So very happy to have her and good opportunity for you guys to meet her and Tony.

Finally Ryan Zorn, who is our VP of Finance will give a financial review and go over some of the exciting things we've been doing over the last few months including the equity offering that we concluded in January and the high yield deal that just concluded last week. Ryan joined us from the (inaudible) side. As many of you know Ryan previously was at Simmons and Goldman on the research side and has been a terrific addition for us on the financial side of Bonanza Creek.

We will wrap that up with Q&A where you have access to all of our senior management, take questions and answers. We will remind you then about the format, just state your name and where you are from or your firm and we will answer questions in terms of the webcast. So with that introduction and without further ado I will introduce Mike Starzer, President and CEO. Thanks.

Mike Starzer

Thank you James and thanks everyone for your interest in Bonanza Creek and joining us today on our first Analyst Day. We went public a little over a year ago and I want to give you a little bit of background for those of you that are unfamiliar with the story. Let me spend five minutes talking about where we came from. But also those on the webcast, appreciate you all joining us and we hope that you will enjoy the presentation and certainly any questions afterwards we will be happy to answer.

We also would have an exciting day, weather permitting out into the field. So we would be able to see some horizontal wells and the operation there or so should within and also from fracture stimulation. We will be rigging up on a well, but I think between the presentation this morning and then what you see in the field you’ll get a good fulsome picture of why we are so excited about the Wattenberg Field.

I want to thank also and recognize James Masters. Over the past year, he has been with us for a couple of years, but certainly over the past year he has done an exceptional job and many of you talk with him regularly and we very much appreciate that. He is, that’s one of our values is transparency in addition to integrity and that we work in a team work, both our investors as well as within the management team and our employees and James has just down a great job. So I want to recognize him. Also I think you will see several themes through the management team today, very much engineering and operations focused.

I am a petroleum engineer, so is Gary Grove and Pat Graham. We are all three petroleum engineers from Colorado School of Mines. Gary is from Marietta College and Pat is from Texas A&M. That operations in the engineering line of theme translates in to consistent and predictable and very reliable results and you will see as we go through the presentation, one of the reasons we entered the Wattenberg field back in 1999, with infill drilling, multiple rise in targets. We’ve never drilled a dry hole in the Wattenberg field. Similarly in 2008 when we entered in to our oily Cotton Valley sands in Arkansas, we are very excited about that for the same reason; infill drilling, multiple rise in targets, very predictable performance.

As I mentioned, 1999 was our first company that we started and we were more in the core gassy areas in the Wattenberg field. We were very successful in those first five, six years and Wattenberg drilling wells increasing production. We were primarily financed with Macquarie Bank and friends and family money. We delivered great return to our mezzanine investors and to the equity investors, but we changed our strategy in 2006 when we formed the second Bonanza Creek Company. We shifted in to the extension area of the Wattenberg field. We had the knowledge of the infrastructure and of the best practices in Wattenberg. Moving into the extension area moved us into our core strategy that we want to adopt in the second company of being oil and liquids rich.

We have maintained that strategy, where we are predominantly oil rated, with a strong liquids compound in the associated gas that we do produce. We’ll go in to that in more detail today. That second company let us to a recapitalization in December of 2010, where we had a private equity sponsorship come in and we formed our third company BCEI, and that is the company that we took public. In December 2010, when the 265 million came in, clean with the balance sheet and laid the ground work for us to test horizontal blowing that was being applied in Wattenberg field that enabled us to test some of the work that has been going with our great neighbours all around us including Noble and PDC, we have Anadarko a little bit more to the west, we have Carrizo around us and now Barrett to the north and south on positions.

All great companies, doing great work and you are going to see a consistent Wattenberg performance throughout the extension area that we are going to go ahead and share with you. We started with 3000 barrels a day in December 2010. We exited the year at 12500 barrels a day approximately, as a result of our horizontal development work. In 2011, we drilled four horizontal wells and that became the springboard for our public offering in December 2011. We went public, had a successful IPO and went through our first three, four months of public company [hazing]. Certainly we needed to establish our credibility as we had in the private arena, but to do that in the public arena and so that ended up. We wanted to make sure the first year that we communicated one is that we are company that hits our targets, did the best we can, and we know we live in a world of uncertainty but our mantra throughout the organization is we hit our targets.

Second, we maintained very strong financial position all through our Bonanza Creek companies. We do that through two pronged approach, a very strong balance sheet at all times, we have the best-in-class balance sheet currently. We also maintained strong hedge positions protecting our price in a sometimes volatile price environment, and Ryan will share more with you about that. That all translated in to the successful horizontal drilling, the IPO, and then the work we did last year into a year-over-year 115% increase in production and EBITDAX of 136% year-over-year increased. Very impressive numbers and this performance contributed to BCEI achieving the top performing domestic E&P Company and total shareholder value for 2012.

So we are very proud of that, but we don't rest on that accomplishment. We are looking to the future, and I am very excited about what the team is going to show you today. In January of this year we completed the secondary offering of 13 million shares on behalf of one of our private equity sponsors increasing in BCEIs public company flow to about 73%. Last week we completed our first high yield public debt offering selling $300 million of eight year note, substantially increasing the company's liquidity and we will show that a little bit more as to now as those funds have been received and the strength of our revolver and balance sheet.

With this recent debt offering, we achieved a new record with the 150 investors pricing the lowest yield for the first time single B upstream debt issuer, another great accomplishment. Today BCEI is very well capitalized and with our strong balance sheet you are going to see investment opportunities into the future that we are very excited about pursuing. We want to stay in our top quartile of our oily peer growth domestic onshore producers and you will see that we have the asset base to do that. We are going to introduce you and share more about the management team to do that and then we will open up for questions and we can fill up any gaps in case if you have any questions on what we've presented.

This first slide is our overview that many of you have seen, so I won't spend a lot of time. The two regions that we operate and you all are very familiar with this are both Mid-Continent and Wattenberg. Wattenberg is our proved reserve growth region and now represents about 6% of our proved reserves. We will continue to have strong proved reserve growth and you will see that in the presentation. Mid-Continent is just a cash engine for us. It has been generating free cash flow very predictable performance. We have good upside potential in the five acre infill drilling program we are testing this year, but it is very stable cash flow for us that we are using to assist in funding our Wattenberg reserve growth.

Wattenberg certainly is our flagship asset and you see 80% of our 2013 CapEx is going to Wattenberg. We have we will show you later, 247 million barrels of 3P reserves we attribute to the Wattenberg filed. And in contrast we have 36 million barrels of 3P reserves that we will show you and delineate for you in more detail in the Mid-Continent. Finally we have other resource opportunities; the North Park Basin opportunity, 30 to 60 million barrels. We have been in [mass] acquisitions since 2006 and we, it’s an area where EOG has supplied horizontal drilling to the Niobrara. We are excited about the future potential and we talked with many about that there's no gas takeaway out of the region. So we see that more as a 2014-2015 stories as we continue to test it.

The Brown Dense similarly 30 million barrel potential, all of our assets or predominantly all of our assets are held by production and will be after this year’s drilling. So we are not driven to have to drill the whole, the Brown Dense is definitely in that category. We are watching our neighbors; South Western, Devon, Cabot, EOG as well as Exxon test the Brown Dense. South Western I think is definitely the leader in that area; and you will see a theme that we have thought through the company's history as we are fast followers when we see get up on that 85% of learning curve. All in all it’s a nice asset mix, stays oily, very predictable and when we show you our – that’s certainly our 1P as we dance through our 2P and 3P and I know that you all are more interested in a drill down of the assets rather than my 30,000 foot overview. So this time I will go ahead and turn it over to Gary to talk in more detail and then introduce the members of the team.

Gary Grove

Thanks Mike, I appreciate that and similarly I won't take a lot of time as well, because what we really want to do is kind of get into the meet of the day. But I do want to just take a short period and then just go over a couple of things. Some of the accomplishments we talked about, a little bit about where we are currently on our drilling status and just a little more detail behind the reserve picture of the year in 2012. So just looking at what we've kind of done today in some of those accomplishments; one of the things you will see in here as I will pretty much spend it out vertical program in Wattenberg and kind of go into a total development going forward being horizontal from what we've done at the end of last year and into this year.

With that in mind we did drill about 36 horizontal wells last year in 2012, and that was about 51% of our production. So as we continue to drill horizontally out here, you will see our horizontal piece of production grow obviously. We have plans to drill about 72 gross wells out there in 2013 and are well on our way to doing that through the first quarter. Our rates we feel like have been improving. You can see some continuous improvements slides coming up here a little bit later, and the reason why we see our rates continue to improve, but overall we've seen our 30-day producing rates increase from about 470 Boe a day from those first four wells that Mike mentioned in 2011, up to about 500 Boe a day when we take in to account the first 36 wells altogether. The last 12 wells however averaged even a little bit higher than that, a little over 530 Boe a day. So we're encouraged by that. We always strive to continuously improve and you will see us do that going forward as well.

Lastly, we talked about drilling some catalyst wells [intended] last year. If you remember, probably at midpoint of last year we decided to augment our budget with the key intent to go out here and drill some of these additional zones in the Wattenberg. All the results we've been talking about so far have been from the Niobrara B zone, 4000 foot laterals. So wanted to go out and do these three things if you will at the end of the year and we did accomplish those. So the first thing we did is went out and drilled a Codell horizontal well, had a great 30 day rate again about 370 Boe a day. More importantly though, as we talked about being out here in this oily area, is 81% crude oil.

Again we saw a lighter decline if you will or a lower decline through the first 60 days, flowing down to 367 Boe a day, and again keeping that high oil rates. So that was right in line with our expectations. We are very encouraged by that and we will continue to drill Codell wells in 2013 to kind of feel forward with that development. The next thing we talk about is drilling Niobrara C Bench well. The 30-day producing rate on that was a little under 450 Boe a day, again 79% crude oil. Again same sign of comments I can make there too. We're very encouraged by that. We will continue to drill the C Bench also along with our neighbors and look and see how the best way to develop will see us going forward.

Lastly we did drill an extended reach lateral and got to about 8600 feet in lateral length, completed auto length I should say IPed slightly under 800 Boe a day, again a nice healthy 76% crude oil to wellhead, and one comment I will make this right up front. When we talk about the amount of oil at the wellhead that is truly black gold, gets (inaudible) black oil, not (inaudible) condensate. It gets trucked out away from the locations and sold into that particular market. So those are the types of things that we look forward, where we wanted to be excuse me, when we made our decision back in 2005, 2006 to kind of go into this area and we are comfortable seeing those results.

Quickly shifting over to kind of where we are from first production tie-ins and when I say it’s a tie-in that means it came online during the quarter, it doesn’t mean it was online for the full quarter and I want to get some a little bit of explanation there because, it kind of goes towards predictions for where are we going to be in terms of volumes as we go through the year. We have given annual guidance, we haven’t early given quarterly guidance, we are not going to do that today as well. But overall you can kind of get a sense where we are going to be as well. So in the Wattenberg field you can kind of see going back to first quarter of 2012 those tie-ins and when they came online and you can see how they ramp a little bit of well [drilling] from quarter-to-quarter, we did see a lot of wells for us come on in the first quarter which is great, not all of them came in the beginning, some of in the end.

And in the first quarter of 2013, we’ve shown about all about seven wells, they are coming online. I will tell you two of those came online from the end of last year that we have just had completed at the end of the year or just in the first week of January. But the other five of those have come online again tied in but really towards the lateral part of the quarter. So as far as having a big impact on the first quarter we are going to have obviously more impact in the second quarter and beyond. Along with that when you talk about our rigs that came online here in the Wattenberg, we currently have four rigs running. The first of them came on in early January, the second one came on in kind of mid-January, the third one came on in mid-February and the last one came on in the early part of March. So you can get a feel for when those rigs came on line and when the impact of the wells that they were complete will start showing up in our production volumes.

Over in the Mid-Continent region similar comments about when they come online, you can kind of see what happened through 2012 there as well. But in the first quarter of 2013 we had three wells that we brought over from last year again that got completed in the first quarter that we had drilled in 2012 and in the remainder of the wells again or something that we bought online during the quarter not online for the full quarter. The rigs there, both started in early January and so they are just a little bit ahead of what we want in the Wattenberg as far as the rigs coming online. We did have some non-op wells again going back to Wattenberg that we brought online the fourth quarter, I think here it’s, we talked about in our fourth quarter call. We do expect some non-operated activity well into this year as well and Tony will give you a little bit more detail on that.

Last thing I want to finish up with there is just a little more detail on the proved reserves. Obviously we came out with our proved reserves around $53 million Boe for the year, ending 2012. This just kind of shows you where that comes from going from year end 2011 to get to that number. Obviously we are moving production and a little bit of divestiture from the California properties that we announced, the big add is in capital adds predominantly in the Wattenberg field, and as far as the revisions go, the first revisions there were a little under 5 million barrels, quite frankly that is from our transitioning into the horizontal program that we talked about. So we removed a lot of vertical PUDs, if you go from last years reserve report, and so you are going to see us do that as we transition back and forth. Our third party reserve report is truly and as prepared report, and so going forward you can kind of see that the growth we are seeing in the Wattenberg from the capital adds will somewhat be diminished a little bit as we transfer out from some of those old vertical positions and replace them in the current very orderly fashion into the horizontal wells.

We did have some other small revisions so you can see there are no other properties and pricing revisions to get the 53 million for the end of the year.

Overall, key metrics, obviously we feel very good about the 21% true year-over-year reserve growth, 371% reserve replacement, obviously the increase in Niobrara 'B' reserves very good. At the end of the year we only had -- still only had 75 horizontal locations both gross locations both for horizontal 'be' 4000 foot lateral and our proved reserves. We don't have anything booked in the 'C' Bench. We don't have anything booked in the Codell other than the two wells that we are producing at the end of last year.

The 19% PUD conversion rate in the PDP is right in line with what we need to be in our five-year program. Proved developed ended up being 45%, up from 39% from the previous year and staying very similar on 63% on oil and liquids weighted. Obviously, PV-10, that's ended at right around 835 million based on the SEC pricing scenarios.

So a good year for reserves for us. We will continue to see reserve growth. We are happy with what we are doing out there and looking forward to obviously bringing the reserves in line with our production growth.

With that being said, I don't want to spend any more time, I do want to introduce Tony. As James said, Tony comes to us from Noble. We are excited for what we are seeing here and he's going to go into a little bit more operational detail in the Wattenberg Field.

Tony Buchanon

Good morning, everybody. Again, I'm Tony Buchanon, the Vice President of Rocky Mountain Engineering and I do come to Bonanza Creek from Noble and coming from the other side of the fence I'm very excited to be here. I've been here since August, but as someone on the other side of the fence looking over at the Bonanza Creek acreage from there, it was acreage that I definitely coveted and now I get a chance to work it, so I'm very pleased to be here. So thank you.

What I'm going to take you through today is on Wattenberg Field operations. I will take you on a tour and walk you through a high level geology overview. We are going to have a poster session at lunch where Dana Strunk, our Senior Production Geologist will be able to talk to you in more detail, but we will give you an overview there. I talked to you about our 'B' Bench performance which is our bread and butter. Gary had mentioned earlier about our catalyst wells, I will go into a little more detail and give you a little more on our catalyst well update.

We will talk a little bit about the operational improvements that we have going on, specifically the ones that we started in the fourth quarter and now are carrying through into 2013 and beyond, and specifically more around the conversion from well [that has been] flowing to artificially lift the inspiration of gas with some of the things you may have heard about from some other operators in the area.

And at the end we will talk about the future concepts that we are testing that we would like to look at that would be evolving around spacing in the 'B' Bench, spacing in the 'C' Bench, how we stack the wells, and then that would lead into how that ties into our 3P analysis that Lynn Boone will be presenting here in a little bit. So with that, I'll move this forward.

Just to give everybody a [warming] at it on the Wattenberg. We talked -- I think Mike talked a little bit already about the gas window and the oil window. As I can see if you look at the map on the left hand side of the slide, we've indicated the gas window which is kind of the core part of the field and then we had the green boundaries on the outside which indicate the extension area which is the liquidier or oilier window of the field. And what I have got highlighted in the black circle of course is Bonanza Creek acreage position and our acreage position is solidly located in the oil window. And what that does translate into is obviously more improved economics because of the oiliness of the area.

If you look at it from a geological standpoint, I would like to carry and take people back in time a little bit or just a with the walk is, if you go back about 85 million years ago and this area was a seabed and we were under water right here. And so what that was conducive to doing is depositing the calcium carbonate rock that makes up the Niobrara formation. So that's where it all started. So where is it today? Well, it's about 6,000 feet deep and what we do is we drill down about 6,000 feet for hitting the top of the Niobrara and then we will drill out 4,000 feet on our normal laterals and we will drill about 9,600 feet for our extended reach laterals.

And as you know, this area has been around a long time. The DJ in Wattenburg has been along a long time. It's been a vertical well play for all those years with an economical vertical well play and obviously what we found us and other operators have determined is that horizontal drilling and frac technologies, you can make it even more economic to move forward in this play.

I will take you down on the ground here for a little bit and give you kind of a look at the vertical section. You probably have seen this before, but I will kind of walk through it and bring everybody on to the same page as I talk to through the rest of my presentation. Obviously the reservoir that we are talking about and I am going to point this year. What we talk about in the reservoir, obviously we're looking at the Niobrara and the Codell and from the top of A Chalk to the base of the Codell formation is what we call the total reservoir.

So when you hear people talking about the regional oil in place in the total reservoir, we're counting all the rock that's in between that. So from the A Top to the A Chalk all the way down to the Codell, we consider that as potential reservoir rock. Now, specifically we're targeting the Niobrara formation and the Codell Sandstone formation. In the Niobrara, it's broken up between what we call chalks and morrows and so look to chalk, well that calcium carbonate material that I talked about earlier, that makes up our chalks and the chalks are basically only that material, calcium carbonate rock. The morrows are that same calcium carbonate rock but interlaced with clays. And so when you see us talk about a chalk and a morrow we put that together and call that a Bench and so that would be our 'B' bench. So that's how we come up with that term on the benches.

So with that being the case, we have obviously targeted the 'B' Bench and the 'C' Bench as our primary target so far. As Gary had mentioned we have drilled significant number of 'B' Bench wells and again that's kind of our bread and butter now. We feel like that's delineated out across our acreage, but we have also tested the 'C' Bench and the 'C' Bench has had pretty good production obviously early on. We were very pleased with that. So we are considering the 'B' Bench and the 'C' Bench as primary targets. Now you may ask what about the 'A' Bench, you probably heard some things from Noble about the 'A' bench. We are looking at the 'A' Bench on our acreage. It is a little bit different. I have been on another slide as we move forward to kind of describe the differences there. And we still think that's the perspective, but it's still something that's under evaluation.

Now the Codell, if you look at the Codell sandstone, you can see obviously when you compared it to the Niobrara, it's thinner, it's a thinner target for us, 10, 12, 14 feet thick but it's a sandstone and so that sandstone has much better reservoir qualities, better permeability, so therefore better drainage. The Codell historically has been a very good performer in the area. And of course, our first Codell well that we drilled we consider that actually very successfully so far and we consider that a primary target. The difference that you will see in the Codell well of course is how do you space the wells in there, what we space in that 160 acres, well we space in that 80 acres, don't know that yet, but it's probably going to be less spacing in the Codell than it is, it's going to take more denser spacing in the Niobrara than it is in Codell just doing the reservoir quality of the rock.

All right, so that was the brief geology overview from an engineer. So again more detail questions you can have, we'll have Dana in the poster session you will have more information on that. I would like to now kind of take you better kind of on the history lesion bringing up to speed in the area how this area has developed and how rapidly it has developed.

What I had up here now is the map of the current situation that we have in and around the Bonanza Creek acreage. So I am going to specifically talk about this three-by-five township area as I go through the next slides. And what is interesting here as you can see that we've got pretty good acreage position, obviously nice continues acreage position and you can see the different operators that are currently drilling and producing in the area.

This is 2013, so I am going to move back, looks like I just did, I move back to 2009. As you go back to 2009 and before, this is what that area looked like, and it's fascinating that that was only four years ago, I mean I have been in the industry third year and it takes a lot of time to do things and four years that we step back here, horizontal activity in this area was basically non-existing.

The first well that was actually drilled was in 1991 and what originally highlight that is that horizontal well was on our acreage. And when you look at the oil shores and the gas shores that came from that well, they look like the wells we are drilling right now, but in 1991 obviously the frac technology wasn't available the time to develop that, so that is why that well was drilled and abandoned.

In 2009 the company Noble Energy obviously came and decided to test horizontal concept, they drilled two kind of shorter reach diagonals, and when we say diagonals, we are just talking about moving the direction not up and down or not looking north and south or east and west, so referring to the diagonals. Noble drilled two wells. So at this time in 2009 in this area everybody is drilling vertical wells, horizontal is kind of just maybe we might be thinking about that kind of thing and that was only four years ago.

2010, I will do the math for you, that's three years ago, all right. So if you go back three years ago, where were we, 2010, well Noble had a little bit of success with their two wells and they decided to continue to do some drilling. So they drilled 12 horizontal wells in this area and also tested something different. Obviously their first bunch of wells (inaudible) back then. We didn't know what kind of space we were going to be on, what we were going to be on, 640 spacing or was it going to be 1,280 spacing like the Bakken or was it going to be down spacing, do we need to go down.

Well Noble tested an east-west orientation at this time. Bottom line was that I'm not sure they wanted the east-west more south at the time, but it kind of flipped the acreage position. So with that we have that testing and then of course we have PDC entering the play, right. So PDC enters the play and they drilled their wicked well and it's more south oriented well to the north and east of our acreage. It’s a take away from this slide. We are still in the infancy of horizontal development. 12% of wells drilled in the area are horizontal wells, 96% of the other wells obviously are vertical wells. Everybody is still thinking vertical development. So, that's just three years ago. Where is this all going, it's the learning curve that we are on. This is where this is all going to end up at, what kind of learning curve we are on.

2011, activity began to pick up. Noble again taking the lead. The Wells Ranch Section 25 in situ lab. Noble highly qualified technical people spent additional monies to really start to do some science on this stuff. What do the spacing need to be? We look at and we had different benches, those kinds of things. So Noble stepped in here in Section 25 and I'm going to continue to highlight this because I want to tie back to that because again Noble's released a lot of information on their Section 25 in situ test, that's been very valuable to us as we can tie our data to it. Again larger company, maybe a little bit deeper pockets from the standpoint of being able to do more intense science and then we can leverage off that. I think as Gary mentioned we like to be the fast followers and we want to run real close to a mill.

So we did the in situ lab, Tesoro tested their first horizontal long reach lateral and you can see how close -- you can notice one township, two townships, three townships, that's basically that's -- I am sorry sections, not townships, excuse me, sections one, two, three so that's just three to four miles to the north of our acreage position. So we are very, very close and the geology as I will show you is very, very similar.

So anyway there's the 40-acre and 80-acre down spacing testing going on and the testing with extended reach lateral. Obviously at the same time a lot of other operators jump in to play, PDC accelerated their program somewhat, Chesapeake jumped in, Noble jumped in, Marathon and the company that's presenting to you today jumped into the play with our first four horizontal wells on our acreage as you can see here.

But again three years -- I'm sorry two years ago, 2011, they had the map test already, right, 2013 minus 2011. 15% of the wells in the area were still only horizontal wells, 85% vertical drilling. So everybody was still doing a lot of vertical drilling at this time. 2012, we can see that things really started to ramp up here. Half the wells in the area are now being drilled as horizontal wells and this is just last year. More in situ testing released from Noble, favorable results on the 40-acre down spacing, favorable results on the C bench. Some things that we are really looking at to learn from.

If you look at what we did, Bonanza Creek, we drilled 36 horizontal wells last year. We tested the C bench. We tested the Codell. We drilled our first extended reach lateral. So everybody is starting to do a lot more under -- trying to gather a lot more data through the drill bit to understand how we needed to develop this reservoir. I think the key takeaway that was still again is that half the wells drilled last year were vertical wells. Bonanza Creek ourselves, we drilled 72 vertical wells last year and 36 horizontal.

So even at that point, we're still early in this horizontal play. So what did that lead, the takeaway is that the Niobrara and the Codell are going to work from an economic standpoint, but all of us Noble, Bonanza Creek and the others are still trying to figure out what's the best way to extract all that resource out of the ground. And so we're going to be doing some additional testing on spacing, additional testing on how far apart we need to put the wells, how we stack them. So those are kind of things we're looking as we go forward. Now I will show you some of that as we do it, but I thought the history lesson here was important because again it's rapidly developing and if you just step back four years ago, it was a whole different world from the standpoint of what kind of wells we're drilling.

Early in 2013 than we have to date now, 93% of the wells in the area we've gone horizontal. Not the same, we will never drill another vertical well of course, but predominantly it's going to be vertical -- horizontal well drilling. We've got 19 wells completed so far to-date. We've 72 operate wells in our plan as Gary had mentioned and you can see the activity continues. One of the things I think I am really excited about is to see Noble has announced obviously drilling more long reach laterals and we will talk about that more going forward, but they are doing a down spacing test with long reach laterals just to the north of this. So it will be really interesting to see how that works out and what kind of results we get from that.

So, that kind of was our acreage position and kind of the history lesson on what we've done till 2013. Now, I would like to tie back on the geological piece again and kind of tie us back to the Wells Ranch acreage that Noble has developed. I'd like to do that again as I mentioned, Noble has released a significant amount of data about Section 25, which is if you look at our across section here, I am going to try to guide you through this. A is like there in Section 25, it's a vertical well that has a log on it that we are going to correlate to, but that’s basically in the middle of the Wells Ranch Section 25 in situ lab that Noble has released results on. And the reason I tied to that again the oil in placement where that ties to that is that 73 to 74 million barrels of oil in place, that’s what they have looked at from the top of the eight of the base of the Codell.

So if you take from A I am going to draw you down to the western part of our acreage here and then I am going to take you across section to the east so we will come to the western part and move to the east. So what's significant about this, well first the benches that are precedent in the Wells Ranch, the A, B, C and Codell are present on our acreage, we have them all, they do and we have them, what's the difference. Well, let’s start with the A Bench. We have had some questions on the A Bench and why we consider a something under evaluation. Well we look at our A Bench and if you look here, and you track it across, hopefully you can see these pairs that it tends to turn from Wells Ranch as it comes across our acreage.

Does that mean that's unproductive and not a target? Absolutely not. What it means is that we need to do some evaluation on it and take a look at it, we see it not, if might be something we would want a drill a well on? Or is it something we can may be drill a well in the A morrow or the B chalk and still access, but that's something we have to evaluate. We are just a little thinner and have a little bit less resistivity and thickness and resistivity are kind of indicators of productivity, a little thinner and a little resistive as compared to the Wells Ranch data.

Now the good news is that the B Bench and the C Bench are very similar. As a matter of fact, when we look at our B Bench, we have similar thickness all the way across compared to the release that we had from Noble in Wells Ranch. And if you actually look at, if you could actually make a case in some of the areas we might be a thicker. So the B Bench is the very, very prospective and very, very similar, so you tie back to that we are encouraged with that and I am very pleased with that.

The C Bench is also very similar. We have very similar resistivity which is a great indicator. It does turn slightly at the base of the C Bench. Our benches actually have benches within themselves, so we can have a bench, may have three or four benches that make that up and the lower bench and the C Bench slightly turns on our acreage, but it's still when you compared it on the thickness and resistivity standpoint makes it a -- it's very nice target for us the horizontal drilling.

Looking at the Codell, the Codell is very similar in thickness and moving porosity as the indicator in the Codell instead of resistivity because resistivity gets masked when you run the launch across that due to the thinness of the zone, but if you track that across we are very similar to what they have on Wells Ranch and we consider very prospective on our western acreage and the best track to our eastern acreage, it does thin and again I am not saying that it's nonproductive on our eastern acreage but I am saying that when you look at our 3P analysis that Lynn was presenting, we can't account the Codell right now on this approximately plus minus 15,000 acres on the western side as definitely something is the primary target and that the stuff on the eastern side of our acreage would be something that is under evaluation.

So that was the review of geology and how we tie back to the Wells Ranch and the known data that's out there. What I would like to do now is now moving to more performance related issues on what we have done so far today. So what I have got up here for you now is times here apply of all the productions that has come out of our B Bench wells.

And if you look at this what I have here is, this is the raw data, this is all the production that came out of our B Bench wells is the great thing and what that is, it's got downtime, it's got everything in it. The wells come online, we bring them back to time zero and whatever they do in that time we put them on this plot, and so then there's blue line is the average of the production of those plots. So if you look at all the wells and you draw the production average of those, you can see where the blue line falls. The green line is our new target type curve, our target type curve is at 313 MBoe type curve and I will have more details in a second on the type curve but here's the 313 type curve that we are looking at.

So you can see from one the real data with all those down time that we have here, those icicle looking things that look like they are hanging off the side of your house during the winter storm that we just had maybe two days ago, those things obviously are influencing this average. In some of the operational improvements that we are employing at the end of the last year as we move in to this year on our later wells, we are starting to eliminate some of this stuff. We will not give it at all, but we are going to reduce it. So if you look at the curve where the actual data is with all that down time and you look at the type curve that we have, you can pretty much make that mental leap that if we can get a little bit better on reducing this down time that we are going to be right on this type curve and probably a little bit above that. And again some of the recent data that we have has indicated that we are reducing this down time and I will show you that later.

The other thing you look at is that when you look at the lateral length of this well and you kind of just put your eyeball on this line, we are coming down here with a curve and I'm not saying a conservative or aggressive, but if you put your eye on this there's a possibility your eye might start to say you know what that actually might be a little bit above that curve. So if you can track the production later on in life it could track. Now I'd caution everybody not to do that because if you look down here, we are only at about 330 days, okay. and so that's why we haven't made any other kind of changes on that because we are still waiting as more data comes in to help us move that. But what I am saying is, we feel pretty good about our target 313 type curve and we feel pretty good about the operational improvement that we are going to do that we are going to start to move these things on to that type curve and either given where we are right now, we are not very far below that, we are very, very close.

Unidentified Analyst

[Question Inaudible].

Tony Buchanon

Yes it is, it is two streamed. So that was the actual production on the B bench. Let's talk about the performance improvement that we have. Some of the technical improvements that we employed last year and probably one of the most significant one I think is to increase the frac stages from 16 to 18. We really think that we are contacting more reservoir locks by doing this and we think that's helped. It’s added a little bit of cost to our wells, but we think its well worth the investment. If anything obviously we talked about control playback and the benefits that we get from that by limiting the sand production, prevents the fracture from collapsing too fast and really gas breakout. But we’ve also set the line on a deeper inner oils and we are setting those near the horizontal section now and by doing that, it’s helping us now when we run in with our gas to be able to set that much deeper in the well and therefore improve the productivity of the well by reducing the amount of brac pressure by being able to produce deeper and I will show you that shortly also too.

But if you can track, we've been advertising obviously IP30 rate and IP60 rates and you may have seen these already and we had gradual improvement through that time, but what we haven't shown you before is where we are now on our IP90 rates, and we've had a gradual improvement on our IP90 rates too. And I'm very encouraged with that as we are starting to see that extended out. Now I would have mentioned that, obviously the well count in the IP90 rate some of our best wells have been our most recent wells. So the IP90 rate is still missing, a few of those wells just because we don't have the time on those wells yet. So I would suspect that our IP90 rate and once those wells come online that are actually in the IP60 and 30 rates, when those wells come on line the IP90 rates will follow and increase that number somewhat too. So we may have even a little bit better improvement once we add those wells to that data.

Type well economics. This is based off the production data that I just previously showed you and then we figured the type curve to that. And if look at that, here is that 313 number that I was talking about, the 313 MBoe number. The crude oil make up of this type curve for the life of the project is 62% crude oil and again that is crude oil, not liquid. It is crude oil. Obviously a very strong rate of return, 64%. But let me go back to crude oil make up, 62%. If I could direct you down to the curve that’s in the lower right hand side, target type curve percent crude oil, this is a plot of what our crude oil is, percentage is through the life of the project or at least out 60 months and that’s the 62% line right there. What I want to emphasize to everybody is in that first year or so, I apologize but this might (inaudible) this one out. If I can point you though, I tell you what I will just point for a minute, how about that. If I can direct you over to the target type curve I want to emphasize that early on in the first 12 months, we're well above that 62% line. We're probably more in that 70% range for the average for the first year, 70% oil and what we have down below here is the actual 30, 60 and 90 day oil cuts. So 76, 74, 73; so that are fixed that we are very early and we are oily early on and you can’t debate we are still at 62% average for the entire life of the well.

Sensitivity to oil price, if you go up to the right hand side what I find extremely attractive about this play is that obviously at $90 we are getting a 64% rate of return, but if you go down to $60 20% rate of return. We could actually do this project at $60 of oil. We don't want to be at $60 oil, obviously we like the 90, much rather have the 64% rate of returns but that’s how strong the economics are. And again on the bottom left hand side is just what those target rates are on the type curve and our actual reported IPs are. And as I have mentioned here on the IP90, if we add in the wells that are coming online that have influenced the IP30 and IP60, that IP90 is going to exceed that 355. So we are right on the type curve with some of the actual data that we have completely on.

Catalyst well performance; this is a little busy but we worked through this. I would hope that it would be layered in for you, but we did not do that. But let me go ahead and just kind of walk you through this. What we have here obviously 2012, we had tested the Codell, we had tested the C Bench and we tested the extended reach lateral. So let me walk you through the curves that we have around here. First of all the dark black curve that goes across is our 313 target type curve. The grey curve to the top which looks like a smooth curve that is our extended reach lateral type curve reduced for the lack of section that we are able to complete. As I have noted down below, it’s a 660 MBoe extended reach type curve and the reason of course we did that is, we attempted to drill and complete the 9600 foot lateral, we drilled the 9600 foot lateral but only we were able to complete an 8600 foot lateral, so we reduced that.

So when we measure our extended reach lateral performance, we are going to measure versus the reduced target type curve just to give you flavor for the performance. The blue line let's start with that one. The blue line is our Codell lateral and that’s the one they had the most production data on so far, and we are very encouraged. As you can see early on this thing, it was under performing the type curve and we hadn’t talk about the 370 Boe 30 day IP rate. But we installed gas lift and by installing the gas lift, we have kind of flattened out the production curve and again this is the first well that we did run the tubing and get the gas as early as we could on the well bore, kind of our new technique versus how we used to do it, let the well flow, die and then put it on (inaudible) pump.

So by doing that it looks like we flattened the curve and you can see the Codell has kind of ventured back onto that 313 type curve, so we are very pleased with those results. If you look at the next line, the gold line if you well that is our C Bench test. C Bench test performed so well also. We had a real kind of shaky early on line and then out again, it was a C bench well but we did get on gas lift tube and as you can see, you look at that now it started performing in the 60 to 80 to 90 day range. You can start to see that that well is approaching on 313 type curve or approaching the 313 type curve. Again very encouraging results for first C Bench test.

And then lastly talking about the extended reach lateral, the extended reach lateral is the brown line and as you can see on the brown line we approached the target of the type curve as we get after the day 40 and 50, we are very pleased with the performance, but then you started to have a little bit of a decline and that could cause some concern, but we don't think you need to have a concern about that because that well at this point was flowing and there we go actually I do have a laser as good. Right here at this point the wells started to come off and it was slowing at this point and it drops down here and this is about when we got it on gas lift. And as you can see once we got it on artificial lift that production performance has flattened out and you can obviously draw your eye to it. It doesn't take too much to think that maybe if we can keep these things flat we are going to get back on the curve. Now you asked yourself why didn't you put your gas lift on back here. Well, you know when its happening real time, it’s hard to see. It’s really easy to see when we get another 20 days of data and then we can look back and go on, geez I should have been on gas lift. Now that's going to go different for us obviously on the well or (inaudible) our second extended reach lateral I think today and that's with PD well and we completed that well we are obviously going to be looking at that data point right there when we start to see any kind of effect on the pressure or things like that, that looks indicative of what happened to the first well, will probably turn the gas that provided at that time and minimize this drop off that we saw when it was converting from flowing to gas lift.

So that's the explanation about it. I would like to see this thing back on curve and I think we are going to get there, but we are not quite there yet. But again still that's only our first well, we didn’t get all the lateral there are some things we need to work out, work out the [kinks]. So that's kind of an update on the catalyst wells. Let's talk back a little bit more about those long reach laterals. There's been a lot of information out there about people wanting to do more long reach laterals, Noble is doing that, Noble has advertised that they are going to do 60 (inaudible) the 300 wells program in 2013 in the long reach laterals. We obviously have done our first, drilled our second and we have one more in our program for 2013. Great story on long reach laterals with wonderful benefits that you can get from it. Obviously one of the big benefits that you get when you look at the long reach lateral, you pick up about an extra 1000 foot or so of reservoir of lateral length that you can actually complete, because when you have two 4000 foot laterals; one will go this way, and one will go that way and you got this gap in between, right? So the long reach lateral can start at one end and kind of cut all the way across. So you can kind of pick that up.

Now you can make arrangements to get that 1000 foot in those 4000 foot laterals but you have to do some different contortions with how you orient your wells and things like that to make it less conducive to do so. So you pick that up; it minimizes the surface impacts, right. If you can drill one long reach lateral and get the effect of two plus well that sounds great and it is, it’s a great opportunity for us. It provides cost and operational efficiencies because again one well we only have to produce one well, that being you don't have to send the (inaudible) one time as opposed to taking care of two wells, those kinds of things. So that's why it sounds so good and everybody wants to do those. Now with the risk obviously there's an uncertainty and that's why we are not going full steam ahead on this yet because there are some uncertainties.

Long reach laterals put a lot of eggs in one basket, okay and so if you have a failure in your long reach lateral wells instead of having the $4.2 million investment in our record horizontal well, go south where you say, now we've got a $7.5 million to $8 million investment to go south if you part [casing] and can't recover the well, something like that. So to recover that it’s significantly more cost to get that. The repeatability of being able to do the beauty of the Niobrara play and the beauty of these unconventional resource plays is repeatability, being able to drill and execute back to back to back counting on success, low risk chance of failure. Long reach laterals, we still have to get to the mechanical part of this so that we can execute this over and over again because when we frac these things along these lateral, you are talking 36 to 40 stages. Our regular laterals are 18. So that means we have to do that thing 40 stage. We have to do that perfect every time, over and over again. So there is some risk.

If you screen out the well, what happens? You have to go and clean it out. So every extra stage you add to these things causes more risk execution questions, and so we need to get to where this is a repeatable event over and over again. Again Noble doing as many as they are, we're going to follow some of the things that they are doing. We're test the concept. I think at the end of the day, we're going to do more long reach laterals, no doubt but we're just not jumping in to it this year full fledged obviously. But I want to make sure we understood the concerns because when you just look at the benefits, you just go boy, why don’t you just go do a bunch of those and that’s not really, there is another side of that story.

Unidentified Analyst

[Question Inaudible].

Tony Buchanon

Okay, now the question was are they using sleeves or perf and plug and in our case, they have not come up to where you can use sleeves for that entire lateral length but there are some places where they have done a combination of both where they have done sleeves for say the first 30 stages and then doing perf and plug like this would be say 30 stages would be sleeves and then this last 10 stages could be perf and plug. It depends on the opportunity, it depends on the vendor that you are using, but the real we're trying to get to where this can be an entire sleeve execution and not have to use perf and plug if you chose not to do so.

Okay, we have some animation here and it was pretty good by an engineer although I can’t take credit for it. Actually the geologist did it. So I am not going to be able to animate. So I will have to step you through this. But what I am going do here is talk to you about our operational procedures. What we used to do back in 2012, especially early on in the year and then, talk about the difference what we are doing now later in 2012 and moving forward in 2013. The original procedure we used to do is step one, we come and drill our well, complete the well, frac the well. We’d then come in and clean the well up with coil tubing.

So we’d come in and drill out all these sleeves, okay all these sleeves are be cleaned out with coil tubing. So we come back out in the hole and at that point, we commenced flow in the well and so we would flow the well, there will be no production tubing in the well bore, so with the animation this would not be here, so in addition that this well the gas is coming, the gas and oil is coming in to the well bore and cleaning up this casing and you can see that the diameter of the casing is bigger than tubing. Actually this might be a good illustration, because this is what a tubing diameter would look like compared to your casing diameter. And when a well starts to flow up casing, it will flow for a while but the larger the casing the more or less conducive or the less conducive it is to maintaining those flow rates under natural conditions.

So what we would do is we flow the well back. It was great to get that production on quickly; we would get it on right after we completed the well. But then the well would die. Okay, so the well would produce and then the well would die. So at that point you didn’t have any kind of flexibility what to do other than you had to move a rig back on the well and then you had to pick up the tubing, run the tubing in the well. You had to pick up your sucker rods, run the sucker rods in below, set your pumping in it, get that all taking care of and then put the well on rod pump. So that was the activity level that would take place once the well cease flowing. Obviously that takes some time. And in most cases by the time you did all that work and then get the well back to producing status that would stabilize after you aligned at the pump, you could be down 10, 12, 14 days in that time period. So you would be flowing the well, boom you are down to zero, it takes all that work and then we have 12 to 14 days later boom you got your well back. But that some down time and you saw some of that in that production data that I had shown you earlier, and imitating that helps moves the curve up, so that’s the big piece of this.

So that’s the old procedure or the original procedure. The new procedure gas lift okay, so what we do now is we clean out, we drill and complete the well, we clean out the well with (inaudible) fitting except one or two steps would be same. But you (inaudible) immediately producing well, we take one to two days right at the beginning to go ahead and run our tubing and our gas lift valves. I talked to you little bit earlier about setting liners lower in the well bore, almost in the near vertical part or near horizontal part of reception, that enables us to run our gas lift and our tubing down in with the curve and (inaudible) down to 60-70 degree so pretty much down as low as we can.

Every bit as close as you can get there, that reduces the bad pressure that can be held on the formation when we have on the formation setting above, so the more you can get the better. Our (inaudible) pump system if you remember, we set up about right here; we were able to get much deeper. The other thing that this helps us do is now we starting flowing the well, but instead of flowing up it’s casing, we are flowing up tubing. Tubing small diameter is more conducive to extending the flow time. So we actually have longer flow periods naturally, and then when the well starts to act like it was going to cease the flow instead of letting it go all the way down to zero, all you have to do now is turn on our gas lift, the gas lift comes down it starts helping to lift the well. And the beauty about the gas lift is, if you just need a little bit of lift you can put it on for just a little bit of lift. If you need a whole lot of lift, you can run it towards forward lifting from the bottom down. What that eliminates as you can tell is that downtime of having to get back on the well and pulling it in one tubing and rods, as so gas lift (inaudible).

Now did we come with this on our own? Okay, you guys probably sat through the mobile presentation it’s exactly the similar procedure that they are doing. But its been proven, its working and gas lift is more conducive to producing the wells early on in the well bore than it’s been proved up for rod pumping.

So this is just a graph of a little display of what I talked about. And so if I didn't explain it well, here's exactly what happens right. The old procedures highlighted here in red, we get some early production, being able the well back online but here's that downtime I was referencing and then it comes back up.

Now what I want to point to you is when it comes back up, I have its drawn very smooth here, but a rod pump producing gas and again it's not geology that drives this, its actual volume of gas because early on these wells make a lot of oil and they make a lot of gas, okay, but the geo well maybe low, but the volume of gas could be significant. What pumps are not conducive to handling gas they gas lock. The gas gets into the chamber of the pump and all wants to do is compress the back and forth and they won't move any fluid. So that causes problems and when you do that you've got to pull the well, we have to do some to things too to get it to line up.

What gas lift does for you is gas lift is wonderful at moving gas. As a matter of fact, it likes the gas and so gas acts like it’s basically still displaying the well. So you don't have those kinds of operational issues. So when I showed up the gas lift comes online, obviously we eliminate this downtime and we have this smooth production, that's more after what we are actually seeing and that's more after what Noble was seeing when they went to that procedure.

So gas lift is really, I think really key for us in your early part of the well. I'm going to say 12 months, 18 months somewhere in there and then at that time we made that decision at that point we need to convert these other go up at that point, but that's when the volumes are low enough and the gas lines are low enough that the rod pump would be conducive to doing that.

Okay, operational methods, how that applies to IP reporting. We've had -- there's questions on IP reporting and I wanted to kind of address the variances that you might see from company IPs versus something that you would go into and calculate from state data and talked to you about what those variances are and why.

First of all when the companies are reporting their IP rates, our intent is to report the reservoir deliverability rate of the well and so what that means is we want to get a rate that's indicative of what the reservoir performance is. And so what we will do is obviously do an IP 30 are on IP 60 rate, there are some issues that occur that are not indicative of reservoir performance. And I'm going to show you some examples.

First, when a company uses -- when a company calculates its IP obviously we've got the real raw data daily rates. So we are looking at real daily rates. What's reported to the state is a monthly rate. So you get the state, you get the volumes and then you get the number of days the well has produced and you hope you can do the math and come up with some reasonable assessment of what the well averaged. But there's a lot of things that can drive that. Global flow back data, when the well is really going to flow back its producing. Now is it producing as effectively as the reservoir can deliver? Of course not. We just induced ton of water into the formation that was caused by the frac, right. And so as the well starts to flow back you start to bring back a lot of that water. So there's those couple of days four, five, six, seven days of production coming back heavily driven by the reservoir -- by fluids that you put into the reservoir and not driven by the fluids that are coming out.

Now that well could be cutting some oil, it could be cutting some gas, it did make one barrel of water, one barrel of oil or 1 Mcf of gas, that would put the reports to the state as a day of production. So you can have a day of production at the state that shows one barrel of oil but it's obviously not indicative of reservoir performance. So we do an IP reported rate, we are going to back that up because that doesn't apply to the reservoir.

The other things that can happen is most of well is online and it's flowing back, you can have mechanical issues at the surface and lots of mechanical issues I talked about one, you get a gas locking pump, you bring the well on January, it's freezing, you have the compressors stay down, you have DCPs lines have issues because of freezing problems. Those days that we might generate partial production days or lower production days, count again to the status, they count as a production day, you would recognize whether that was a partial production day or not. So at the day data, obviously with the internal information that we have, we can decide, whether that is not indicative of reservoir performance in those days need to be removed from the IP calculation.

And as I mentioned, the transition from planned artificial wells, when the pumps get in there, especially we look at old data, we have them on rod pumps and had gas locking problems, that wasn’t reservoir limiting, that was mechanical limiting and we have fixed that part with the gas lift.

So what does that all mean? Well, let’s take a look at a busy slide but I tried to get all the data on here that I could so we can kind of walk you through how you can come up with three different numbers with the same data. This is an actual result and this is actual data for that well that’s both in the state and in our daily rates. So what I would like to show you here is first of all state reported data. If you just look at this well, it was well we just brought on in December of last year for 10 days and if you look at the state data, which actually in the state data is 10 producing days with 4,867 Boe.

In January, we produced a well that had 31 producing days in January reported and 12,913 Boe, which we look at here on the gold line, is the actual raw data of that well, that’s the actual producing data. And so basically almost every one of those days is kind of producing days, but you can see that we had some days that were not optimal and why they were not optimal, we had early for that time here and we had some mechanical issues in January and we have got figure, we had some freezing in January so we had some mechanical issues at the surface that went these few days here with the production standpoint.

So if you do that and you look at the raw data and you look at the state data, so if you were to calculate and IP stay the upper state data and there will be different ways of doing that but all I did was we have got 10 days in December, we have got 31 days in January, so we take this number here divide it by the 31 times 20 that gives you 20 days in January so you kind of ratio that right. Added to the 10 days in December and you are going to come up with that calculation of about 442 Boe per day. So that’s the state data calculation.

If you just walk through this and move this kind of every day first, the first 10 days on this well, whether it had downtime or not or issues, if you catch it up that including those days that number comes up to be 474 Boe per day. So same data for 442, 474. If you really want to know what reservoir can do though to one of these numbers, the reservoir is going to say now wait a second, take out to back and take out that freezing stuff you guys going on, on the surface because that’s not bothering me just get it out of my way and I can continue to produce. If you take those days out, you get a well that can deliver varied IP, where it is 544 Boe per day.

So the intend of this was to come just walk you through why there is some differences when you go dig into state data and you try to do the calculations and how those numbers can be different from the overall report in our IP reporting. Now what did the operational improvement do for us, okay. One real base, when we try to get to an IP 30 we had operational issues and flow back issues if you take us up to 46 days to get to an IP 30.

In our current way of doing business or looking at 38 days, now that have been another this 30 because the only flow back time never goes away, you always going to have the early flow back time, okay. So thirdly to get 30 is really get and put it down close to be as good as we can get.

And when we look at what it takes us to get the IP-60, the IP-60 takes the 72 days, here it takes 92 days, so we cut off 20 days and what that is all, that is all about that transition from artificial lift, drilling the artificial lift. So we take the new methodologies that we are employing are going to close that gap, but not to do the same but they will close that gap so hopefully there will be less of the difference when you look at state data versus the IP reporting data is.

Drilling improvements got to get some level to drilling guys, all right. We have got here from the drilling improving standpoint, if you look at is back in 2011 we are making progress; we are actually making really good progress. We’ve reduced our spud to spud times down to 13.5 days and not going to have a trial the four rigs that we have won, we actually have the couple of rigs out there and I will get some kudos to Ensign, have a length time rates, we are actually running down to maybe into the 11 to 10 days range and we actually had one well that was 9 days, now that’s but the spud was on our location that we just had a case, so we didn't have a long move or anything like that but the improvements are coming and we are seeing those and so kudos to the -- at the Ensign rig and to the drilling guys for that.

Looking at cost, if you track our cost through there, this is historical the 36 wells that we drilled, we actually made one change back in the middle of last year going from 16 stages to 18 stages that Ryan mentioned and that did influence our cost that added about couple $100,000 to our ABs as we have talked about getting those two extra stages, but what I am going to try is kind of our running for that average is black curve -- is black dash curve.

When you look at where we are, we want to do making stages, obviously we had some key learnings, but we are starting to bring our cost back down and if you look the running for that average, we advertised our 2013 guidance at $4.2 million and if you look at our running average coming out at the end of last year, that's about right where we are at and we are seeing those costs pretty much stay the same, we haven't seen costs pressures of drilling yet, costs are looking good there, we have seen actually a slight relief on the fracs side from the stimulation side. So we are encouraged that this $4.2 million number is definitely doable.

Moving up to a status report of what we own in 2013 program, Gary kind of mentioned the wells that were coming online early on as we carried into from ’12 into ’13. Here's what we had budgeted for 2013. This is kind of wells coming online as you can see in our budget we had our first wells coming online in April 2013, so we are definitely waited out towards the end of the year and not in the first quarter. We actually have made a little headway as Gary had mentioned a couple of these wells. We've got certainly a little relief. We have actually some of these wells coming online in March but the influence is late enough in March and there's not only flow back time period in March, its’ going to have very minimal if any impact on that first quarter production.

And so what we just want to guide here is that we are weighted out towards the end of the year and not in the first quarter. What are we doing this year? Well okay one thing is we are on time and we are on schedule, okay. We are on time and on schedule, that's always good news and then we are continuing with our catalyst wells and all I have done here is summarized where we are on our 2013 catalyst well development. We've got 4 C Bench wells. You can see the quarters that are going to be drilled in. We have got two extended reach laterals, I told you we are TD in the first one today so we will be completing that one right now I think from a schedule rate or permitting by the end of April.

We have Codell wells, we've actually drilled and run liners on our first Codell well and that well was the well that you guys were hopefully were going to go see frac but the mother nature intervened and we are not going to be able to frac that well till Monday but you will go by that location today and that's our Codell test.

We have three additional wells to be drilled. We had our 40-acre down spacing, the B Bench test going on. We've actually completed our first 40-acre B Bench and I'm not ready to release any 30-day IPs yet but we just bought that well online here at the end of March and so we will be talking about that probably in the next quarter, but encouraged so far but it's early.

Unidentified Company Representative

One that's been, that's 240 acre space.

Unidentified Company Representative

Brought them on in March.

Unidentified Company Representative

(inaudible) issues the permits or are they going to be released?

Unidentified Company Representative

Yes. No, we are not having any significant issues with permits. They do go fairly smoothly but we had a plan in place that gets us far enough ahead that keeps us to where we can get our permits and we have not had any headaches, but it takes planning and this doesn't occur without making sure that we came to do that.

Unidentified Company Representative

(inaudible).

Unidentified Company Representative

Okay, great thank you.

Unidentified Company Representative

Moving forward now we'd like to talk to about how we are going to move forward and tie into the 3P analysis that Lynn will be presenting. Where we are today, this is just continuous improvement, but basically we are driven single bench, B Bench wells, single pad, go out there drill the well. Where is it moving to? Well it’s moving to multiple pads, multiple wells on pad, stack driven, centralized production facilities, gathering systems all that to make this thing even more attractive economically. It’s attractive even on the one well pads, but they are so many synergies that you can gain by doing central gathering and pad drilling and all that that it’s going to make it even more economic going forward.

So what's that going to look like and again this is conceptual. Let me I think I have that somewhere, yeah, concepts, it’s a concept. What we need to do and this is not right now in our 2013 budget. Now would you may consider that, should, can these kinds of conditions we want, but you’ve probably seen some of this similar that Noble had presented in their Section 24 and 25 on how we're going to now determine what's the best way to stack these different benches in there, what's the best drainage to do. Does it take a 40-acre C Bench all the way across 16 of those? Does it take 16 B benches? Does it take four Codell wells to get all the resource out of that section? Don’t know that yet. Those are some of the concepts we want to test.

So we're kind of looking at some how to stack this. Here is we’ve got two 80-acre B benches, stacked with a C bench, that’s on a 40-acre location when we look at it from a surface standpoint and then we might come here and do a test on 80 acre Codells. So we could be looking at something like this to help us do this. We might look at this straight 40 acre B bench, straight 40 acre C bench test that would be a five well pad. These are spaced on 40, and these are spaced on 40 and so how that stacks in there.

So the bottom line is these are concepts that have to be evaluated as we move forward and so we're going to start to look at those kinds of tests and obviously some of that has started with the B bench 40-acre stuff that we're doing currently in 2013. The concepts of test and then of course pad drilling and super pads, those kind of things that drives facilities are all things that we will be doing pad drilling this year that will help us continue to evaluate how much more and how much savings we can generate from that.

Finally, I want to title the 3P or what we have in there. So the way we see our acreage position today, now remember qualify that how we see it today. We see that we can develop the B Bench probably and looking for ended the 3P. We see that we can develop the B Bench probably on 40 acres. We see that we can probably develop the C Bench on 40 acres and we see that we can develop the Codell on a 160 acres spacing right now.

Now what I am going to point out here if you had that upper section that’s 36 wells and so I want you to join to lower the reserves associated with the well as opposed to the number of wells. So there is going to be reserves associated with each of these individual wells that we drill. The objective would be obviously instead of driven 36 wells to get all reserves in that section to get out of resource out of brand and boy, sorry about that.

The objective would be instead of doing that if we deserve one well that would be optimal right, but one well right in the middle and doing the whole thing, well that’s realistically now what's going to happen. So what I want to say is that right now we built in more 3P is looking at these 36 well development, however if we can with 30, if we can do with 25, that’s what we are going to do, but those are some of things that tie back to the previous slide on the concepts we need to test to see whether or not we can maybe drilling more without having to drill the well.

So with that I am finished up with my presentation. I want to thank you for your time. And I would now turn it over to John Larson. Now look forward to any questions after the presentation. Thank you.

John Larson

All right. Good morning. That’s quite a story and I am going to give you an overview of what we have been doing in the Mid-Continent region specially in Southwest Arkansas. After the presentations we will have our geologist, Janet McAlee out and she can go through any of the detailed geology that you like. And after my presentation, Ryan Zorn is going to come out and she is going to talk about a little bit more detail of the five acres spacing pilots and the work that we are doing there and show some of the economics of that time.

So for to make sure that is word what we are doing in Southwest Arkansas is we are -- we have production from four well, just north of Shreveport and east of Texarkana, most of our development right now is focused on repeatable low risk infill drilling at the Cotton Valley in the Dorcheat-Macedonia Field. We are doing that on 10 acres spacing, we have drilled over a 100 wells and completed over 100 wells in that field on the 10-acre basis.

I am going to go through a little bit of what we do and why that gives us hope for five acres spacing. In addition and so this development is primarily designed to provide for cash flow that we can redeploy to the Niobrara area. In addition to that bread and butter work that we are doing, we do have some outside potential, one is five acre internal testing that I have mentioned. We also have a Cotton Valley over the Macedonia pattern field that we’re testing and we have some acreage that has [smacker route] ownership which is commonly called the bound dams up in that area. We are currently watching, as Mike I believe said we are watching Southwestern in the area to see what they do.

As far as on the map there where Southwestern has drilled wells up to today, some other well drilled by Anderson over by McKamie area. So in addition to the fields that, wells that we produced, we operate two gas plants and we have a gas gathering system, all that is a 100% owned facilities. We remove nitrogen and sell liquids from those plants. We do produce from other different reservoirs, but the main for our development is Cotton Valley at this moment. Here's kind of a cartoon view of a Cotton Valley formation in this area. It’s very early in this area as opposed to some of the areas on East Texas and Northern Louisiana where it tends to be gassy, but it has a lot of ventricular sands and so these are little pods of sands, they are not connected together; each of them has its own pressure and fluid composition. We will probably see 25 to 30 sands in a given well and whether seeing is when we drill our chemical wells is that we are not necessarily seeing the same sands in the wells right next to us. And so that's what's given us some encouragement or maybe how low can we go. Can we do it as a five acre spacing opportunity here? So that's what we are doing.

When we started doing this, we started drilling in between these wells and we’d find zones that we are completely fully pressurized, virgin pressure and so the people you that had not completed the wells, in these sands in that particular sand or the sand wasn't even in that well. And as you can see the other thing that we did different in these wells, over the last few years is we went through a different track methodology. In the old days what they used to do is go in and frac one or two times and most of the frac sands would go into the best sands. And what we've done is we've gone and done what we call pinpoint fracturing and by doing that we are grouping small groups of sand that have similar characteristics and we will be stimulating those sands in some cases that have never been stimulated before and that increases the recovery in the original oiling place.

But as I mentioned before, we've done over a 100 of these and both come in pretty much the same, all the way across. This kind of shows you what we are actually doing right now. We are drilling these wells vertically to 8800 feet where we log and obtain pressure for each of those 25 to 30 sands and we use that pressure data and the log data to help us develop our completion plan. If the zone’s already been depleted we don't need to worry about that one initially. We will go through the higher pressure sands first and then we will come on down the line. So after looking at our logs with the in-house petro physical model, we will fracture stimulate in vertical fractures would enforce a smaller pinpoint intervals. And what we will do there is we will go ahead and put those wells on pump and produce them back for about three months or so until they kind of die down and then we will come back in and we will add additional Cotton Valley zones. So you can see the fed zone in this type curve on the right all are down at the relative part of the Cotton Valley where the sands are a little bit tighter and they benefit from stimulation. But as you come up the hole, the porosity and permeability is better and we don't need to frac those sands and so we've been very successful. We are recompleting in the shallower zones.

Generally we plan to do each well twice in this life time. Once after three days and then once a year later, but in reality we have recompleted some of these wells more than two times but almost every well has at least two and so this is how it appears on our type curve. When we first bring the well on, we will probably get somewhere around 67 barrels of oil equivalent per day. Three months later, we will do the pay add now will get a bump in production and then it will die down again and then at the end of the year we will do that again. So this type curve here represents a 138,000 barrels of oil equivalent, ultimate recovery and it does include those recompletions. In the Dorcheat-Macedonia field we own roughly 80%. We have a 120 gross locations available in the 10-acre spacing and then Lynn will kind of go in to what that would look like in five acre spacing. We spent $1.8 million to drill the well and we completed twice. So that’s not all spent right immediately, but we keep that out in the economics.

Drilling the wells takes between 10 and 12 days, and about three days to complete and we've had two rigs running pretty much steady for the last three years, two and half years. The best tour you guys are going on this afternoon is not going to stop in Arkansas. So I thought I would show you a few pictures along with some of our highlights from the first quarter. In February, let begin with February of this year, we started processing gas to our second train at our Dorcheat plant, that’s the train on the top, it is mere image of the train below, both of those are good for 12.5 million a day processing capability, so this facility right here is good for 25 and then we have another 15 million a day unit at McKamie-Patton. All of our fields in the Dorcheat Macedonia and McKamie-Patton are connected to both plants, so we can move the gas around as we need to.

All of the gas here is being processed primarily to remove 9% nitrogen. We are setting a residue gas that is methane and ethane and we are trucking a raw mix liquids of propane plus. At McKamie-Patton plant we do fractionate and make a propane product and the rest of the liquids are sold as a raw mix. This is a very good looking facility; I would like to take out there and go look at it, but not today. You may not get to see a frac today, but this is one of our fracs looks like. It’s much, much smaller than the horizontal fracs. We use much less water, much less sand and much less pumping rate to put our wells away. The other unique thing of what we do is we use coil tubing and so we actually cut holes in the casing with sand and then we down the (inaudible) of the core tubing and the casing and then from there, we would flow up the casing with sand and them come up all and do it again, and so we just come right up. However when you are done you use the coiled tubing to remove the sand and then you are ready to finish with the completion.

So far this year in the first quarter we drilled 12 wells. We did just TD second five acre [interval] last night, so we drilled 9 of the 10 acre roll and we’ve drilled all three of our McKamie-Patton wells this year and we have completed in addition to the new wells, we have completed three wells from last year and so we got our five acre, our first three five acre wells came on February and we will have the rest of them come on in May. In addition to the completions and the drilling, in the first quarter we did 26 new completion in Cotton Valley and we are looking for the rest of the year right now, the plan is to drill 36 wells, 30 of the 10 acre wells, three of the Dorcheat-Macedonia 5 acre wells and three of them McKamie-Patton wells.

And lot of this plan was put together was based on gas capacity, and so as we go through the year where we will be launching that. We plan to complete up all of our wells that we drill this year in addition to the three that we drilled last year, and we have plans to recompleted the 114 wells. One of the advantages of doing the recompletions is that recompletions cost under a $100,000 and they come on usually pretty robustly and so they have been very economic. But in general those are included in the overall economics of the program. So at this point I'm going to ask Lynn Boone to come up and she is going to talk about the upside both at Wattenberg and here in the Mid-Continent area.

Lynn Boone

Good morning. I'm Lynn Boone, Senior VP of Reservoir Engineering and it’s a pleasure to speak to you today. Let me make sure I can operate this. Okay I will be presenting the basis of our 3P work and the results of that work to you today for the Wattenberg field and for the Dorcheat-Macedonia field. In the Wattenberg field, we start with a strong foundation which includes delineation across our acreage for the Niobrara B, detailed geologic analysis for both the Niobrara and the Codell, and very strong earning results for our first two horizontal wells in the Niobrara C and in the Codell. In our Dorcheat-Macedonia field, our 3P analysis is really based upon a history of low risk successful drilling of our 10-acre wells. It’s this program that provides substantial information and knowledge on which we base our analysis of the potential of five-acre increased density.

So I'll start this discussion with the Wattenberg field. Based upon the data that we've acquired to date, we have technically identified and placed value on the Niobrara B across majority of our acreage, about 89% of our growth acreage. Our 3P philosophy is to value the unproved reserves at the current proved reserves or PUD levels. We consider this a conservative approach for estimating the reserves about possible and probable categories, but it ensures us that we are going to increase our reserves over time and it also prevents us from getting out ahead over our skis. We have not captured the more recent positive production performance that Tony presented in his talk today, but we know that over time that's going to roll through our proved reserves and it will also roll through our unproved reserves. Our Niobrara B EURs both for the PUDs and for the unproved reserves range above and below our target type curve level of 313 MBoes per well and that's because its based upon natural PDP performance. But the result of this analysis is that we do have a reserve level for PUDs and for unproved reserves as high as 313 MBoes per well.

Now the Niobrara B locations have been rigorously appraised and reviewed by our experienced geologic personnel as well as our engineering staff. I will speak to the exact numbers of the location a little bit further in the presentation. The Niobrara C is also considered to have significant potential across our acreage. These locations were obviously also appraised and reviewed by our geologic and engineering staff. We only have one at the time of this analysis we only had one producing well on our acreage in the Niobrara C. So we have chosen to you the most conservative Niobrara B PUD EUR of 230 MBoe per well. That will represent the another C potential across the acreage. As Tony stated, our Niobrara C production performance is very good and it is approaching our Niobrara B target curve levels. So we're expecting increase these reserves for both approved and the unproved in the near future.

Obviously, as Tony said, this is a very dynamic play and we see changes happening frequently and so we will be updating our 3P reserves periodically. The Codell Sandstone is currently assessed by our technical staff to have economic potential for horizontal development over approximately 15,000 acres or 43% of our gross acres. Again with only a single well producing from the Codell, we have chosen the most conservative and the lowest Niobrara B EUR for our PUDs and our unproved locations of 230 MBoe per well to represent the Codell across those 15,000 acres, and again as Tony showed earlier, the Codell performance of the first well is very good and we expect to increase this reserve level overtime.

The development plan for our 3P analysis includes development for the Niobrara B and C as Tony stated on 40 acre spacing that’s currently being tested by ourselves and other operators in the DJ and 160 acres space inside the Codell. We are seeing the 4000 foot laterals on pad development through this 3P analysis. We have four rigs running this year and we are assuming that we will have up to eight rigs running year around as of 2017. And as Tony also stated, we may have as many as 36 wells per section if the Niobrara B and the Niobrara C and Codell are all present and have sufficient thickness to complete as horizontal, but the numbers for each section all of our growth acres are analysed geologically and the number of locations per section vary across our acreage. We do expect to operate 96% of locations in our 3P analysis.

Before we address the original oil and place and recovery, I would like to step back and look at the cross section that was presented earlier, which runs from the Wells Ranch area designated here by the capital letter A and that runs south in to our acreage and then east across our acreage. If you recall from Tony’s statement that primary difference between the general Wells Ranch area and our acreage is a thinning of the Niobrara A. With that in mind, we can easily identify the difference between the original (inaudible) in place that Noble Energy has quoted on their Analyst Day on December of 74 million Boes per section to our 58, which is a preliminary estimates of our original oil in place in Section 2 of 4N63W. Both of the core locations are shown by the stars and the red start for Noble Energy just indicates the general area from which the core was taken, we don't have the exact location in that.

So the majority of difference individual oil in place beside in the A Bench, and if you look at the numbers that has been presented by Noble, they are estimating about one-third of their original oil in place resides in the A Bench. Using our regional oil in place and the amount of recovery that we are currently estimating from our development program, we expect to recover up to about 17% of the original oil in place with our current development plan. So we got the results of our detailed 3P analysis. Total net reserves are 237 MMBoe of which 32 million are proved. Approximately half of the unproved reserves of 250 million are in the Niobrara B Bench which we have derisked across our acreage, the remaining half of the end proved reserves are made up by the Niobrara C combined with the Codell.

We have 1452 undrilled, unbooked locations within our acreage assuming our current development plan. Our intent however and I know Tony spoke to this early, is to drill as few wells as necessary to recover these reserves in the Niobrara benches and the Codell.

This table is a detailed accounting of our 3P location inventory, 48% of our net under locations are in the Niobrara B. Please note the risked EUR reserves located to the right. Those are the reserve levels that make up our currently estimated 3P reserves of 247 million Boe. We have stated that we are targeting a tight well of 313 MBoes per well. As we achieve these reserve levels, we will move our 3P estimate toward 303 MBoes. That's 23% above our current estimate. So we recognized that we have an upside to our 3P analysis that is represented by the difference between 247 and 303 million barrels of oil equivalent.

Now let's consider a conceptual five-year development plan in the Wattenberg. As of January of this year, we had 36 wells producing -- horizontal wells producing from the Niobrara B, one in the C and one in the Codell. So conceptually over the next five years we could drill 740 gross wells that would make up about 48% of our total drilling inventory. By the end of five years we will be drilling, as I said earlier, with about eight rigs running throughout the year.

So the result of this conceptual five-year drill plan is a production forecast, as shown here the production is increasing as a compound annual growth rate of about 33%. At the end of five years we would expect to be producing over 40,000 MBoe per day net to the company.

Now as illustrated here in the yellow we are aggressively developing the Niobrara B and this year we are ramping up the Niobrara C and Codell and those -- the drilling of those formations will be increasing over time as illustrated by the green layer on this curve.

So in summary, again we have a very strong foundation for 3P work in the Wattenberg Field with delineated acreage, detailed geologic work and some very strong early production results. The opportunity we have out there is abundant. We have over 1500 gross locations and that's in our current 3P development plan. We have 247 million barrels of oil equivalent of risked reserves in our 3P and we have the potential for a growth rate of five years of compound annual growth rate of 33%.

Now what I would like to do is move on to the 3P analysis of our Dorcheat-Macedonia Field which is a smaller development opportunity that financially is very important to the company. So in Dorcheat-Macedonia we've been drilling low risk 10-acre wells since 2009 and we have a very strong track record. As a result, we understand the complexities of the Cotton Valley formation.

Also on the positive side, as John mentioned, we own a 100% of the gas process and facilities. And as of right now we’ve had great results from our very first five-acre pilot which came on in February. So I will show you today that we had a significant unproved reserve upside in Dorcheat-Macedonia and that will be represented by our 3P analysis.

So as John stated, we're currently developing our 10-acre wells out there -- all of those wells are in the pipe category. We had a 120 and they are booked at about 148,000 barrels of oil equivalent per well. We drilled 98 wells since 2009 and we significantly ramped up the activity in the last two years.

So let me take you a nature of the Cotton Valley fan, newly creates the opportunity for undrained reserves that being offsetting wells that encounter different sand lenses and John spoke to that earlier. Clearly, as we increase the drilling density in the field, we're increasing our recovery. Our volumetric analysis indicates that increasing our development drilling from 10-acre spacing to 5-acre spacing will increase our recovery some 13% to approximately 20%.

The 5-acre increased development is considered unproved and we've included classified it in the possible reserve category, but we expect that the results of the pilot as well as gathering and analyzing more data to decrease the uncertainty of these reserves in the near future. We have accounted for depletion for the 5-acre spacing wells by risking our 10-acre reserve level by 20%. This gives us an EUR for the 5-acre increased density wells of a 118 MBoe per well.

So the next step is pilot well program. And as John and I had both mentioned, the first program came on in February of this year, our second pilot will be on production within the next two months. For our planned development in our 3P analysis, we are assuming approximately 15 wells per 80-acre area.

So 19 million barrels of oil equivalent are currently proved at Dorcheat-Macedonia, 46% of which is in proved developed. These reserves are 65% liquids and 35% dry gas. The result of our 3P analysis is an increase of reserves of 17 million barrels, which is significant to this property and our location count increases by 219 locations.

The economics are strong for both the 10-acre wells and the 5-acre wells. For a capital expenditure of $1.8 million we generate a discounted present value between 1.3 million and 1.8 million and a rate of return between 51% and 68%.

So the economic forecast is solid and what we need to look at now are the actual production reserves from the 5-acre pilot. So any results from the 5-acre pilot is very encouraging. The initial rigs and the 30-day rigs are 22% and 18% respectively above our forecast, and that is the forecast for the 180 MBoe per well for 5-acre spaced well. So we are very encouraged with this, we know this is early time data but we are also excited to see the next pilot and expect that well to perform -- that pilot project to perform as well.

So in summary, we have a strong track record of drilling low risk 10-acre rigs in a very complex reservoir that we both understand and appreciate. We benefit by owning the gas processing facilities and we have very good early production rates from our 5-acre pilot project. Our 3P reserves are 36 million Boes and we had increased our gross location count up to 340. We are currently free cash positive and we expect to continue to generate free cash flow which we'll fund our other projects in the company.

This concludes my presentations. I would like turn it over to Ryan Zorn, who is our VP of Finance and have present the financials.

Ryan Zorn

Good morning to all. We wanted to be well to [appropriate] these slides and simplicity and transparency are really the hallmarks of what we try to do and how we try to communicate with you all and likely we've got a relatively simple asset base with a lot of upside. We want to be true with expectations we set for you and obviously manage the business financially in responsible way. So I hope you will take a balanced approach to our capital allocation. We are going to try to protect and promote our already strong cash margins that we enjoy and then all the while maintain the best-in-class balance sheet.

This is a slide that some of you have seen before but obviously we have guided to you annually. We are not feeling the need to make any changes to those guidance -- annual guidance numbers today. We are sticking with almost $400 million capital program. Obviously 80% of that is setting towards the Wattenberg which is a high growth opportunity for us, but we feel like we are achieving efficiency with this capital budget, that is adding production at a rate of about $30,000 per Boe per day which we feel like that can pose favorably to present M&A activity that you see out there and certainly equity valuations. I mean we are doing very accretive things with this budget.

In addition adding slugs of EBITDA on the oil of about $100 million per year, you take a market valuation of those types of incremental additions to EBITDAX and compare it to incremental debt that we are putting on the balance sheet to achieve those, we think we are doing very accretive things with the equity holders.

You can see the Wattenberg Field, that's really a $324 million, that's achieved, that's going to promote production growth over 100% this year versus last year, 35% year-over-year increase in capital. You can see that obviously as you've heard we are still focusing on the B Bench but we are going to be testing some concepts and how the laterals, how we sequence them, we think those are the things that are most important for us to learn this year in particular and as we contemplate development programs out into the future.

Arkansas is a special asset for us. It really differentiates us in my mind. We are not a gas company transitioning to oil. We are an oil company that's stunning oil growth with oil cash flow. And I think that really separates us from the pack and you've heard Wattenberg, we’ve referred too for many years as a reliable and I think for us Arkansas is a reliable. We are going to spend $70 million, that's going to generate a 10% year-over-year production growth, but that's actually on a lower capital number versus last year, about 15%.

So as Lynn mentioned, we have transitioned last year into a free cash flow generation capacity there. Obviously that's very, very core to our future development for the Wattenberg. And we just highlight also to you in the lower weight, just our operating activity, we drilled it really too earlier but just to put some numbers around it. Our net completion time -- horizontal completion tie-ins for the Wattenberg for the first quarter was about 7. We will be ramping that up to 15 in the second quarter, 22 in the third and in the fourth quarter, 20. So we have back-end loaded there. Again we feel very a good about the guidance we've issued to you and see no reason to change at this stage.

Mid-Continent completion schedule also a little bit back-end loaded, obviously a less of a driver of the growth but just point that up to as well.

I mentioned earlier our cash margin clearly is really best-in-class. We are driving down our unit cost picture with the increasing mix of horizontal production represents the lowest unit LOE opportunity that we have in the portfolio as an example and we're seeing some of this versus the Marcellus with people just have extraordinary initially low unit LOE. We see sub-$3 per Boe unit LOE and the first year of horizontal well that for instance and over the life of that well, it's certainly sub-$7. Right now, we generated roughly the same cash margins in both regions and that's a lower LOE opportunity in the Rockies with the higher commodity type of benchmark versus the Mid-Continent which has a higher LOE but obviously we're realizing some premium pricing there.

At current hedge position, roughly two-thirds of our oil production this year is hedged. Minimum price assured is about $88.45. Just to give you a sense of how much we're protected and we feel like we've locked in and assured ourselves of $200 million of revenue for this year is guaranteed. We think that we're assuring roughly about a third or two-thirds of our EBITDA this year. 4200 barrels currently hedged with [Carl] measures swap and collar in 2014 at roughly the same minimum price levels.

We're not very hedged on gas right now. You have seen us stated previously in today that we're comfortable hedging 50% of our production, obviously with a very low level of hedging on the gas side of the equation. We're running a little bit wide of that, but if you feel like the oil side of the equation is much more important for us to guarantee.

Current balance sheet structure, obviously we made a lot of headway on that last week and several participants who are here with us today, we appreciate their support. We had a great week this year. We already had high yield last week. We upsized it to 300 million, 8-year term on that. We set a record for coupon, just a great week this, obviously it's a great environment coming from a standpoint of really well rather relative to our peers which I will get into in a second, but just over 150 investors in the book which we have read about, five times oversubscription at the level bid of price.

As a result, our base is clubbed back a bit, so we will have 250 million available to us there. We completed paid down revolver with the proceeds. We will go through determination here at the end of the month and then again in October. We would expect modest increases in April followed by many more material increases we hope in October. And lastly that all matures in September of 2016.

Just a quick landscape really to just how we stock up from a balance sheet standpoint to single P oily weighted peers, the peer group as we compared ourselves to, this is in the foot, at the bottom. (inaudible) all these matrices that we feel great about, we want to protect this status intensely and this is also obviously performed the $300 million high yield. You can see even despite the small production base that we have relative to some of these folks, well far left hand in that low left hand chart in terms of the net debt production metrics.

New chart on the top on some Boe metrics, obviously we think that’s leading given oily nature of our reserve base even relative to some of these folks. We think the bottom charts obviously normalized for that as you look at value, so debt to PV-10 and certainly debt to enterprise value will certainly best-in-class among seven peers here.

Our balance sheet strategy obviously, we want to keep ourselves liquid. There is lot left to learn about the development of this asset. We have shown you activity escalation now through 2017. All our internal model is down on the lower risk type curves, not the 313, so we think we have been very conservative in the way we model this going forward.

Current liquidity exceeds $300 million when you combine that with cash flows or generating annual funding capacity if you will in excess of $550 million which we feel that is a very good level for us given the $400 million capital program this year. As we get into how we think about managing the balance sheet going forward, we want to have a target annual funding capacity in excess of our next 12 months casual CapEx. We don't have any long-term rig contracts. So we don't have red lights flashing out us necessarily right away at commodity prices to do take a dip. So we feel like we got ample flexibility to act to those situations if we see sustained commodity price weakness.

It’s our objective to maintain net debt to EBITDAX at or below two times given the organic program that we’ve got. These folks and I am sort of roughly on the team. I have got here in October but we had a long history of making good acquisitions and divestitures I might add. So we want to keep ourselves flexible, so that as opportunities do arise to do some incremental bolt-on work we are able to do that.

I'll wrap up with a series of bullets here. You know again we are funding oily growth with oily cash flow. We think that's a real differentiator for us. We are going to maintain a block and tackle program in the Mid-Continent. Obviously the five acre potential there is really appealing. You know we would have some decisions to make on whether to expand the gas plant, if that does turn out to be viable. We will keep you posted as we learn more. But that will take us really all year to figure out. So not a near term decision point for us, but certainly in the next 12 months. Clearly best-in-class growth driven by the Wattenberg both on an absolute basis and we feel like on a debt adjusted as well. We are going to focus in on cost as we sort of get visibility on the way that this asset in particular the Wattenberg is going to be developed. Certainly we will be taking a hard line there, and obviously we are going to be hedging to ensure constant cash flow contribution to the capital program.

Finally we feel that real quartile debt metrics will (inaudible) all stakeholders, both debt and equity. So we have a strong objective and we feel like our equity value has benefited from that in the last 12 months and we certainly don't want to drill ourselves into a corner like we've seen many of the gas peers do and have a cycle turn on us. So you are going to see us again stay sub two times net debt EBITDAX, we flex our models again based upon a risk type curve running through the growth profile down into the mid to low 70s, and we accomplish that objective which we feel great about. Opportunistic bolt-on acquisitions we want to be in a position to execute on those and utilize the balance sheet primarily, obviously depending on the nature of the asset would dictate whether we have to do some equity to accomplish those. But we feel like that level of leverage gives us maximum operational flexibility and makes equity dilution an unlikely event for us.

That concludes my remarks, I'm going to invite Mike to come back up and we will actually I'm going to send these slides and I'm sorry we had to make our laptops switch out here so I'm going to have to scroll back through to one of our earlier summary slides, I apologize for that.

Mike Starzer

I'll just close with few remarks and I want to leave plenty of time for questions and answers. But I think you see from some of the members of the management team, you may have never met before and if you see why it’s a real pleasure to come to work everyday at Bonanza Creek. We hold ourselves accountable to you all that we achieve our results and we make sure we hit our operating targets. We maintain that financial discipline that has been engrained in over a decade of working together and then we effectively communicate to the market. So there's no surprises both good and bad and we've had a lot of good. But every now and then there’s some bad that comes up, we want to make sure you all are in front and center on that. So I appreciate all your time and going through the presentation and it sounds good. Now I'll just go ahead and open it up to question-and-answer.

Question-and-Answer Session

Scott Hanold - RBC Capital Markets

Scott Hanold from RBC Capital Markets. The first question would be referring to I guess slides 44 and 45 on the Niobrara acreage and your assessments, a couple of things just to clarify so in your 3P assessment you are using the 269 MBoe type curve which is the average PUD type curve you have, is that correct?

Mike Starzer

Yes, I'll turn it over to Gary.

Gary Grove

On those two slides and what Lynn has as well that is the average that you are seeing across the acreage for the Niobrara B, and I thought it was the one prior to that. Only one that’s got the numbers on it, right here. So when you are talking about average across the property, yes and the Niobrara B, we're using a risked EUR 269 in the B bench on the upside for the 313.

Scott Hanold - RBC Capital Markets

Okay, and what was the range of that? Was it 230 at the low end?

Gary Grove

Yes, something like 230 at the low end of that range.

Scott Hanold - RBC Capital Markets

Okay, so when you look at the 269 versus your 313, what's the variance? Was that’s just conservative among the Reservoir Engineers assumptions at this point?

Gary Grove

Pretty much right now, yes, and it's also, you know, we're recognizing that our third-party reserve analyst will trail us obviously as you move forward in bookings reserves. So we're kind of a little bit conscious of that as well. I think Lynn said it really, really well. You know, some of the latest data that we have hasn’t been completely incorporated in to these numbers. So we're seeing better and near-term results as well. The Tony slide earlier that showed exactly where our Niobrara B bench shows a flattening of that curve as you move outward. Obviously that would increase just from an EUR standpoint also. So when you look at common themes here, that’s exactly what you are seeing. So overall, yeah, we're probably trailing a little bit on our 3P analysis right now from what we're seeing from the most recent results.

Scott Hanold - RBC Capital Markets

Okay, and then one more question on the Niobrara C assessment, it looks like in the Niobrara B I guess you said you validated roughly 90% of your acreage. That looks certainly Niobrara C in your 3P assessment. It's pretty close to the same based on one well. How do you get so confident in those 3P well counts with just one well? Is it vertical penetration throughout that acreage, and could you talk like how much more you have that?

Gary Grove

I think when you look overall, it's a combination of things one is not just one C well that we are looking at we are obviously have offset industry information as well. But we also have 3D seismic coverage across entire position and yes we have drilled vertical wells out in that particular area also and we have drilled back in actually 2006 and produced from the all three layers, excuse me, predominantly the B and the C in the Niobrara, so you have some initial flow back information from verticals as well. So if you are comfortable knowing what the opportunity is for the area to produce and it's just an extrapolation of what we see geologically and also from that limited data set in terms of production, does that answer your question? That’s really the ground work behind that yeah.

Brian Corales - Howard Weil

Hi it’s Brian Corales from Howard Weil. In one of your slides you had in 2017 eight plus rigs, can you talk about from ‘13 to ‘17 is that just adding a rig a year? Is that kind of a thought process or...?

Gary Grove

Yeah. That’s pretty much in-line with that Brian. I mean either there might, as you kind of trailed up. We have seen kind of consensus if you will kind of have us any where from three to five years to get to an acreage program out here in this particular area just kind of right in line with that. So yeah it might not be exactly one well per year, it might be one and then one-and-half depending on when the rigs schedule during the year. But as you can see it's somewhat linear, I would put it in a linear context, where we are today.

Brian Corales - Howard Weil

Okay. Thank you. And one more those PUDs and I don’t know if it’s only 36 wells but when you will be testing all different zones and one section, when do you plan to do that, how long would it take to drill one of those PUDs, and I don't know how many wells you will start at beginning, but...?

Gary Grove

Well, I think Tony can follow-up too if I say something correct. But I think what we are really looking at right now is some of the information that (inaudible) from some of our offset operators first at the same time I think Tony mentioned we don't have anything schedule for this year to go ahead and put a stack arrangement in place other than what’s currently already set up for drilling nearby wells that we have in both of the B and C Benches.

I think as we look towards the lot of part of this year from some of that information comes out, that’s something that you may see us come out and say we want to go ahead and augment our budget this year, put some of those kind of principles in place. But at the same time how long it’s going to take to where you kind of have the fully, this is exactly what we are going to do and this is all we are going to do from today. Honestly we may never know what the exact perfect thing is until we’ve drilled the last well. Our goal as with all things is to be as most efficient as we can be, and the way we see doing that is to drill the least amount of wells possible to drain an entire section of oil or that cube of oil if you will and gases in that area. We think there is opportunity there to see some kind of movement in between some of the benches, right.

But we know we have influenced those from the work that we have done today. The real question is that how much can we drain by drilling in between or drilling near closer to one of the others and reduce some of that capital. Honestly I think you are going to see us probably have that answer a year to two years from now along with, I know again a lot of asset work along with what we are doing as well.

Tony Buchanon

I might add to that briefly Brian. Ryan mentioned the governor of two times total debt to EBITDAX when you look at your the forward planning and any price scenario that you have, we stay true to that governor and that’s a self imposed limiter on how fast we can spend capital and grow. Obviously with our assets base it’s rapidly expanding, we could accelerate that quite a bit but in all work internally we’d stay through to that limiter when we build our [lawns], and that where you see, anywhere from maybe three to five years out going to the 8 rig program.

Irene Haas - Wunderlich Securities

This is Irene Haas from Wunderlich Securities. I have two questions for you; firstly by installing the gas lift early in the history; that’s going to smooth out the production profile, can you discuss how much so incremental costs are there and sort of extra logistics set the goal for, and question number two is pretty simple in February it was pretty cold, but did you experience any freeze off on your lines, that could impact production.

Gary Grove

Hi Irene, I guess on the capital cost associated with the gas lift actually its going to be a little bit less. The cost of the gas lift installation as you saw on the slide it really is around the valves that run into the well and then in the compressor that's set on the surface instead of setting a pumping unit which pumping unit with its full established pumping unit rods and all that can cost you up to about $150,000 for that whole installation. But the gas lift is going to be significantly less than that. Now down the road about 18 months or so we will have to put a pump on those wells, but hopefully at that point we will basically trade out the compressor and the gas lift equipment that's in the current well and move it into another well as you have your inventory tweed up. So you start to kind of rotate the equipment across.

If that answers your question on that then as the freezing, yes we did have some freezing issues in February, obviously with the cold weather, we have issues where we will have some line freezes off. It does affect our compressors. One of the things that happens to us as obviously is we are transitioning from the pumping units gas lift, and so the compressors were sitting on the ground running the gas lift early on in our program are a little more susceptible to freezing weather just because we are running a program and we don't have all the sheds put over and all those kind of things to keep them warm. So going forward we are going to see that if we did have a few hits in February.

Tony Buchanon

I am Tony I will add one thing to that and Irene just kind of maybe on kind of guidance on volumes, you know we include those types of things on our calculation of guidance for the year so its not in our minds if we are not giving you any new guidance today. We are still within our annual guidance on volumes, when it happens during the year. Obviously we are going to see more freezing and more of those types of things that we see in the winter time. That along with you know what we are pad drilling centric its going to go down the list here, those kind of things we try to include into our guidance for this year, I think as we talked earlier. So when we are drilling next to a well we might need to shut it in a little bit while we frac that side by side well as an example. We try to incorporate that into our guidance. Anything that we thought we might have you know there's been comments about and some highline pressures in the area we try to include what we learn from last year and in to our guidance for this year. John, down in Arkansas manages the plants, we turn those plants around so we try to include them in our guidance as well. So at this point in time there's no change to that, but yes we did have some weather issues in the beginning of the year.

John Malone - Global Hunter

John Malone from Global Hunter. When you set to prove up global viability of five acre space into Dorcheat-Macedonia is that (inaudible) that decision.

Mike Starzer

Definitely the answer is that we need to make sure we have a full understanding of the [EMP] asset base there and what it can do for us into the future. So until we have that full complete picture, and that's going to drive a lot of that thinking. We hope that maybe the second half to early 2014 that we will be looking at tabbing and understanding what the five-acre can do for us and expanding that development inventory. Now we will look at that. Certainly at any time that someone looks at the beautiful asset like that very predictable and we've done a nice Midstream infrastructure that strategically helps us maximize the cash flow from that. It will be very attractive acquisition for someone and we've got a good idea of what the holding value of all our assets are. If someone were to come in and offer something above that holding value, certainly that would be something we would look at very seriously.

Adam Michael - Miller Tabak

Adam Michael, Miller Tabak. Just a follow-up on the Dorcheat, the 5-acre spacing, how many wells would you actually move across your acreage to kind of prove up the concept?

Gary Grove

I think, Adam, there we drilled three in the last year, brought those on and kind of report on those. We're drilling next three well set if you will. And probably one or at least two or three more of those type of things across the field. So again like Mike said, we look towards the later part of this year and the beginning of next year. Again, but looking at historically, we have some 5-acre locations that are kind of spread throughout the field and we will take that information in as well.

So I would probably be a little more conservative and say that probably towards the middle part of next year we may have a better feel for that in terms of how it kind of transforms all the way across the field, but at the same time with continued success, obviously then it's a statistical play and those statistics should hold up across the property.

Adam Michael - Miller Tabak

Okay. And then as a follow-up, if I am looking at I guess the 5-acre spacing and you are going to drill 36 wells this year, what's the current field production and where do you kind of see it plateauing at and you know if you are going to sell it in the year or two once it kind of delineated, what is that production at Watten?

Gary Grove

And guys, remind me what last year’s average was here because we're going to see about 10% or 11% growth coming through this year off of that number. I mean I know where we are. Roughly, we're going to be around 5,000, little greater than that, kind of exiting the year. I think the average for the year was a little about 4,700, 4,600 Boe a day last year out of the Arkansas properties. Again, we will project some growth there for this year. Where could we be at that point in time? Obviously, you know, I don’t want to give any further guidance but I will probably tell you just look at the kind of the track record of growth in that particular area and it should continue in the same vein because what we are seeing is very consistent results. When we put capital to work there, we get a very good idea what we are going to get out for every well we drill is very consistent.

Ryan Zorn

I would just add to that. We haven't modeled in anything beyond 10-acre for our own internal results. So I mean for the three years on average about 10% growth with the $70 million program is what we think we can achieve.

Adam Michael - Miller Tabak

Okay. And if I could (inaudible) to the Wattenberg, you guys have 220 vertical wells, what are those producing and I know there was south that comes on into August from vertical wells usually the ones you have high line for sure. So it better seem like you have that much production coming from these vertical wells. So may be if you could help us out there a little bit?

Gary Grove

Sure. Right now let’s say about 60% or 65% of our production comes from the horizontal wells that we have on that area. So we are still looking about a third of our production coming from the vertical wells. Obviously they are down from where they were, where we feel they actually could be, but again that’s something that we have put into our guidance for this year as well in terms of where those wells are ending the year at when we put our guidance together.

So as we see some opportunities to kind of alleviate some of those pressures we will be looking to put those types of projects in place. And if we feel like we thought we might see some additional recovery for that, we go ahead and let you all know as well.

Andrew Coleman - Raymond James

Andrew Coleman from Raymond James. I had a few questions if I could sneak in. Firstly I guess on the (inaudible) as you had deferred a north, do you have other type curve or just other cross section that you can show, what do you think that had (inaudible) uniform across all your acreage?

Tony Buchanon

Do we have other cross sections? I guess, if you looked at our cross section they came down one of the tie wells was on the tight wells was on the southern part of our western part of acreage, yes go back to that. I don't have another cross section to show you today, so maybe I can talk to verbally and then somebody stop me upon same things I shouldn't say. If we track this down for here obviously we had this grow on the western side of our acreage on the 'A' Bench and then as you come down in the southern part, what we see geologically is that down here in the southern part obviously is it looks a little thinner but it does come across here but we actually see that the 'A' Bench and it goes to the north towards Wells Ranch does get thicker.

So what you probably see here on this cross section is a little bit of conservative approach to what we are seeing on the 'A' Bench. So I am not sure from the productivity gain standpoint, I don't have anything to show you what that delineates after going forward there back up to the Wells Ranch will be definitely do see a thing thicker up on this part of our acreage position. So hope that answer your question but it's probably best I can do right now.

Andrew Coleman - Raymond James

Sure.

John Larson

We left about it when we put it together. If you look at it the [14-2 well] it shown from the core that's actually is the small state bench across that entire cross section, but that's the day we had but that is what we are going to share. And so I think Tony said it really, really well as we move actually out in that direction does taking a look at.

Lynn Boone

But if you’d like more discussion on that, you could speak to Dana, our geologist she will be out in the poster session.

Andrew Coleman - Raymond James

Okay. My second question was looking at the [Fortes] down page 12, it got some (inaudible) porosity and then got the greater thickness makes the target down the road and all the things you are doing [Fortes] what the Codell? Thanks.

Tony Buchanon

Well, the [Fortes] is for being considered possible reservoir rock, yes it is common as far as rock. So we do see it as oil all bank. We do have some data in there that indicates that. We actually contemplate putting a well on the [Fortes] right now. I can't really answer that question because with the opportunities that we have to delineate in the C bench and the B bench along with the Codell or probably we are going to be focusing on that for the time being.

At the end of the day, when we get out through this 3P analysis we are going to figure out how we need to drain the [Fortes] because that's going to be a part of that IP that we want to recover whether it takes a well in that, great, if it doesn't, that we met (inaudible) in the Codell and frac up it to it, we can prove, we convince ourselves that we are draining it and that so much the better there too. But we count that as reservoir of rock and we will get to it.

Andrew Coleman - Raymond James

And last question I had is if you look at the -- look at the 5-acre pilot you have in Dorcheat-Macedonia and you look at the change in the time that you set the pump for gas lift or the B Bench completions, what I guess those two probably point (inaudible) why long we are seeing more of a human up in that pressure guidance?

Gary Grove

Yeah. You see them all run when that question came up. Yes, we like what we are seeing but again when we put our guidance together that annual guidance takes into account a lot of opportunity and a lot of things that we try and forecast going forward. Right now with where we are we don't feel like we need to change that, you know yeah we are seeing some incremental good results in the first month. We are seeing some operational changes that are good for us.

Honestly, quite frankly, you probably know we have a couple of things that are darned knowing is exactly the way we had them planned as well, but we think overall we are still right where we want to be on guidance for this year. And if we do see that going up you know continue to go up through the year, then definitely we will be out telling everybody where we think we will be in the latter half of the year. But I really wouldn't expect us to come out with guidance -- Ryan and James may give them, but I really wouldn't expect us to see what come out anything before midyear at this point in time until we have a little more data that would go towards the annual numbers.

Ryan Oatman - SunTrust Robinson Humphrey

Hi, it’s Ryan Oatman from SunTrust. I want to stick with 2012 here and see if any color you guys can provide on this morrow kind of the rock properties you see there and the potential for that to act as a separation between the B and the C chalks or what sort of connectivity you see between potentially those two benches, how effective is that morrow as a frac barrier?

Tony Buchanon

Well, if you as a frac barrier I'm going to say some of the data that we've seen shows that when we initially fraced the well that we do pop through that the model and up until possibly up into the A, I mean we've seen that when we look at our microseismic. I think the key point is and we can talk in the poster session with the geologists they can give you a little bit more around that, but the model has those plays involvement and what we are concerned about is once you pop through it, that's fine, but once you release the pressure and the frac starts to heal, what do those models do when it closes around a bit of those plays doing a close on the prop. And so to really have an effective prop frac up there that you can drain.

And the gross we did right now on the verdict is out on that but the indications are that you are probably not and that's kind of what we heard heading and we are kind of confirming that with some of the data that level has released and they have looked at the number of wells that they have tendered they kind of put into their sections when they are looking at that 30 well plan per section. You can see they are putting in A, Bs, and Cs. They are not really indicating that they are draining from the B up into the C or I'm sorry from the B up into the morrow up into the As or anything like that in any kind of consistent fashion.

So to answer your question, the verdicts are lap; I don't think we are going to be in a situation where we can kind of tell you right now that we are going to be able to do that and that more unlikely we would have to talk to do it separately.

Chad Mabry - KLR Group

Chad Mabry with KLR Group. A quick question on the gas cost. We're seeing agreement in the Wattenberg. You have alluded to that in the past potentially getting some of the BCP. Just curious how those discussions stand and if you can also comment on potential economic implications on the economics of those projects?

Gary Grove

As far as infrastructure goes, on the gas side, yeah, I think we all heard that last year and talked about that last year, especially in the second and third quarters. Some high line pressure there kind of really mainly revolving around gas processing capacity. So to think south land, there are most recent information from DCP looks like August, maybe late August and coming online, it's next to us. A lot of our acreage out in that particular area that would have a capacity about 110 million a day and so that will relieve a lot of some of that maybe near-term pressures. And we also expect to see that continue as we move to the later part of 2014.

Again, DCP and others, Anadarko and other private companies have committed a lot of capital to go ahead and expand that infrastructure at a certain point and double it by the end of that timeframe. So those are the kind of key components that we see going forward.

The short answer for us is we don’t see that as a material impact on our development throughout that timeframe. The other thing we always look to do is what can we do on our side of that line as well and our side of that gathering system. So we installed compression upstream of those lines where we can. We installed our own gathering system with upstream to give us that opportunity to putting compression and we will continue to do that because we feel like that’s again a key component of our strategy going forward.

Did that kind of revolve around your question? Did that answer what you are looking for that around the infrastructure? Our contracts or DCP are all percent of proceeds contracts and we don’t have any firm commitment on NGL lines or dry gas lines. As a matter of fact, on the oil sides, we don’t have any firm commitment on outgoing oil area as well. We feel like that’s completely covered if you will by our purchaser and the case on the oil side it's plains and shale at this point in time.

Chad Mabry - KLR Group

And I guess you just stated that, you too included type curve, it’s kind of head of type curve in your presentation and then the NGL breakout and how that might impact the economics of your wells?

Gary Grove

Well, as far as the economic goes, the economics won’t change, the revenue side is not going to change, it's just a way to show a three stream curve rather than a two stream curve. So we currently get paid on a wet molecule gas, we get paid on a percent of proceeds contract for what goes through the facilities and get sold at the tailgate of all of those facilities and we take that revenue both from dry gas stream at the tailgate and raw mix stream or actually it's a fractionated stream at the tailgate take all of those revenues back to a wet Mcf molecule pre-process molecule if you will and that’s how we get guidance on pricing. Currently we are doing about 150% of pricing on that.

So revenues really won’t change if you went to a three stream model, we just report differently and show you the true NGL breakout versus the dry gas break out instead of a wet molecule.

Irene Haas - Wunderlich Securities

The question on other horizons, understanding that your footprint stay compact really contiguous, just wondering if the [green horns and Jason] would be future targets for you?

Gary Grove

I think what you see, Irene, is there is not you ride in a right order, what's makes the most sense to go out of from a horizontal standpoint, obviously vertical wells have been drilled out here to the Niobrara and Codell and the J into the Codell for years decades. But when you look at the long parameters, you look at response today. It make sense that the Niobrara Be was the first target, that’s what everybody went to Niobrara See would be next, Codell in long lines of those and that probably come after that [green horns] further down the line if you will.

Quite frankly right now with all the opportunity that we have, we know there is handful of [green horn] wells, that in theory kind of being permitted. We haven't seen a lot of results from that today. It's going to be a little tougher to crack; obviously the geology will be different than [green horn]. It's tighter and so we are going to be content again to kind of maybe take that fast follow approach and that maybe some other spend a little bit of R&D money they are going forward.

As far as the [Jason] goes is predominantly gas and so as we look at the [Jason] what an opportunity might be there, quite frankly in this current commodity cycle, the economics will be compared. So I would say as far as anything further in the J especially in our area, that probably further down the line and need the rebound in gas price for us to probably consider doing some of that work.

Unidentified Analyst

(inaudible) Morgan Stanley. On your 5-year Wattenberg production forecast, this is based on your best type curve at 269, maybe you speak to where CapEx peaks out and if you get to free cash flow up here?

Lynn Boone

It is based upon the risk EUR levels that are lifted on whatever supply that is, so that is what five year forecast is based on, yes, and far as the cash flow. Ryan?

Ryan Zorn

Yes. So I think CapEx would sort of be towards, and this is an official guidance, I understand that 700 million to 800 million as we get into the eight right program assuming we got to continuing to run going our concern. So it maybe a little bit too lower into that range and free cash flow positive would be real close at that point but maybe not quite over the hump, but really in ’16 and ‘17 you get off the close.

Unidentified Analyst

I guess the last one, although you haven't delineated the long laterals across your acreage but just logistically in terms of joining sections, how much of an acreage you think could work logistically for long laterals?

Gary Grove

I'll chime in and then Tony can tell me if I'm wrong, but you see a lot of contiguous pieces to our acreage and that's obviously very good for doing extended reach laterals. Overall I'll answer it two ways, one is if you look at our acreage and you say what do we want to really control, so control the entire length of lateral with the very high percentage of the working interest and probably talking about half to maybe as many as two-thirds of those locations, we kind of shrink down to the extended reach area.

However that being said, if extended reach is truly the best economics, then our neighbors would most likely see that same scenario and then it would come down to just simply saying look if we are going to drop to 4000 foot laterals, if one was on the other side, and one was on our side as an example, why wouldn't we go ahead and partner together and drill one extended reach lateral and share the benefits of the increased economics in that situation.

So ideally you could say that all of the locations would open themselves up for extended reach laterals. You know we've been approached where we had a very small percentage of a piece of land like an outline 40-acre block to go ahead and participate in extended lateral which we would do with some of our neighbors as well.

Tony Buchanon

I may have one thing, there is a geological component to those extended reach laterals, also that kind of drive that subtle changes in the geology underneath that don't affect 4000 foot laterals can affect the 8000, 9000 foot lateral if you cross a subtle fault that you can cross, it may take you a longer time to get back and so and so. Those things they don't have to obviously understand before we went out and determined to do an extended reach lateral just based on the surface location. Now does that say we are not going to be doing extended laterals, absolutely not but it’s just another consideration to put into the factor?

Mike Starzer

I might add to that, it’s a $4 per barrel savings is our target with the extended reach laterals when we based on what Noble’s done and what we've done today. It’s a great target to say it’s already a very attractive development profile going forward. I think we mitigate that uncertainty a lot with our 3D seismic we have across all of our acreage. So we go into with our eyes wide open.

And as Gary mentioned, we also have a very high working interest control on all our properties, 99% of our proved reserves are under our control and our operations. That controls our capital investment and we can increase it, new information we can change on the dime and I think that's what we will say for the next year as we look at more extended reach laterals being applied to the area and we can very quickly mobilize and move in that direction.

Mike Starzer

With that, it sounds like that was our last question. On behalf of Bonanza Creek, thank you so much for today. And we just really appreciate everybody's interest and we look forward to doing the best job we can for everybody going forward.

James Master

The management team will be joining you on the field tour to follow up questions.

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