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Bonanza Creek Energy, Inc. (NYSE:BCEI)

Q3 2013 Earnings Call

November 8, 2013 11:00 AM ET

Executives

James Masters - Manager, IR

Mike Starzer - President & CEO

Tony Buchanon - COO

Bill Cassidy - CFO

Gary Grove - EVP, Engineering & Planning

Pat Graham - EVP, Corporate Development

Analysts

Brian Corales - Howard Weil

David Deckelbaum - KeyBanc

Ryan Oatman - SunTrust Robinson Humphrey

Daniel Burke - Johnson Rice

Ipsit Mohanty - Canaccord Genuity

Adam Michael - Miller Tabak

Michael Hall - Heikkinen Energy Advisors

Joseph Magner - Macquarie Capital

David Beard - IBERIA

Mike Kelly - Global Hunter Securities

Ravi Kamath - Global Hunter

Ray Deacon - Brean Capital

Michael Scialla - Stifel Nicolaus

Brian Steck - Mangrove Partners

Operator

Good day, ladies and gentlemen, and welcome to the Quarter three Bonanza Creek Energy, Inc. Earnings Conference Call. My name is Carolyn and I'm your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of the conference. (Operator Instructions). A reminder, the call is being recorded for replay purposes.

Now I would like to hand the call over to James Masters, Investor Relations Manager. Please go ahead.

James Masters

Thanks, Carolyn. Good morning and welcome to Bonanza Creek's Third Quarter 2013 Earnings Call and Webcast. Yesterday afternoon, we issued our earnings press release and this morning filed our 10-Q with the SEC. You can access both on our website.

In today's prepared remarks Mike Starzer, our President and CEO, will discuss results from the quarter and will provide an update on our plans for the remainder of the year. And Tony Buchanon, our Chief Operating Officer will give an overview of our operations. Bill Cassidy, Chief Financial Officer, Gary Grove, Executive Vice President of Engineering and Planning, Pat Graham, Executive Vice President of Corporate Development and other members of management are present and will be available during the Q&A portion at the end of the call.

Today's remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-Q, and our other SEC filings. Also, during this call, we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release. Also, all results discussed today reflect continuing operations, not counting the results from our remaining California property.

With that, it's my pleasure to turn the call over to Mike.

Mike Starzer

Thank you, James. Good morning everyone and thank you for taking the time to join us as we discuss our third quarter results. Before we get started, I would like to take this opportunity to comment on the recent devastating storms that affected many communities along Colorado's Front Range. We extend our sympathies to the families and businesses that were displaced by the floods and have partnered with organizations focused on helping these communities get back on their feet.

I specially want to thank our operating teams for their professionalism in the face of the storm. Because of their dedicated efforts we had zero safety incidents related to the flood and we were able to get back to work quickly experiencing minimal disruptions to operations.

Now as it relates to the results we have achieved this year, we understand that the first two quarters were difficult to forecast because our drilling and completion schedule was backend weighted. As a result, we missed consensus estimates even though we were comfortably on our internal plan. We asked for your patience as we ramped up our activity and we are pleased to reward that patience with tremendous financial and operating results for third quarter. These results reflect value creation across both regions and positions us well to continue delivering shareholder value.

Third quarter production was up 88% over last year, net revenue and EBITDAX more than doubled and adjusted net income tripled. The company continues to perform at a high level in the second year after our IPO as we manage rapid growth in investment, production and employee count. We maintain a positive long term view point on our business with an uncompromising focus on operating excellence and disciplined investing.

Specific to the quarter, Bonanza Creek reported sales volume of 17,656 Boe per day, a 32% increase over last quarter. These record volumes coupled with strong crude oil pricing drove net revenues for the quarter to $126 million.

Before the effective commodity hedges, our average sales price per Boe of $77.54 and disciplined control of operating cost contributed to a cash margin of approximately $58 per Boe, up significantly from $45 per Boe last quarter. Strong margins resulted in EBITDAX of $86.7 million and adjusted net income of $25.6 million or $0.63 per share.

Per unit LOE and cash G&A dropped 24% and 20% respectively from last quarter primarily because of increased production volumes. Also, contributing to the decline in operating expense was the reduction of some prior costs, such as certain gas plant expenditures and legal and professional services.

With the third quarter completed, we continued to confirm previously established ranges for 2013 guidance with respect to production, unit LOE and CapEx. While we are not altering the range for unit cash G&A, our best estimates are trending towards the top end of the $6.25 to $7 per Boe range as we continue to add highly experienced employees to enable the company to execute on our future growth plans.

We are very proud that during third quarter Tony Buchanon accepted the role of COO and Bill Cassidy joined the executive team as CFO. Tony and Bill are outstanding additions to our talented and accomplished team. Our core values of integrity, team work, and transparency remain the foundation of all of our hiring and training programs.

One other thing to note, as we move into the end of the year, our crude price differential in the DJ Basin has widened as a result of longer oil hauling trips due to the September floods and seasonal refinery maintenance. We expect both of these issues to be short term.

Finally, our liquidity position became even stronger with a re-determination of our bank borrowing base from $330 million to $450 million just a few days ago. As of September 30, pro forma for the increased borrowing base Bonanza Creek's liquidity stands at just under $400 million.

I will now turn the call over to Tony to discuss operations in more detail and the encouraging results we are seeing from our catalyst testing in the Wattenberg Field and in Southern Arkansas.

Tony Buchanon

Thanks, Mike. We are fortunate to have superior assets in both the Wattenberg Field and in Southern Arkansas that performed within a tight range of expectations allowing us to forecast into the future with a high degree of confidence. As we often point out, we are a company of engineers and we like assets that are low risk, repeatable and have multiple resource opportunities. We certainly have that in both of our major properties.

In the third quarter, we placed 30 horizontal wells in the Wattenberg Field and 14 wells in mid-continent region into sales. Crude oil and liquids volumes remained approximately 72% of total production accounting for 90% of company revenues. In the fourth quarter, we expect to place our remaining 14 horizontal wells into sales in the Wattenberg Field while we move forward with drilling operations on the super-section test.

Production from the Rocky Mountain Region was 11,802 Boe per day, a 135% increase in volumes from one year ago, and a 41% increase over last quarter. Our horizontal results continue to impress as production from that program increased 271% over last year and 55% over second quarter.

Wattenberg operations were again impacted by high line pressures. We have approximately 130 or about half of our vertical wells shut in with the remaining wells making up just 6% of our total Rocky Mountain volumes. Horizontal wells were better able to deal with higher line pressure are not immune. Most notably, early producing rates are somewhat suppressed as high line pressure acts as an additional choke or flow restriction.

Our Pronghorn area wells on the eastern side of our acreage have been hardest hit this year with pressures as high as 400 pounds per square inch. Also, some of our catalyst wells depending on location have been impacted. We are beginning to see line pressures moderate however as a result of a number of infrastructure projects put online early in the fourth quarter. Most significantly, DCP brought its new named gas O'Connor Gas Plant online in early October, adding an initial 80 million cubic feet per day of new capacity and added additional compression facilities.

We also proactively installed upgrades to our gas gathering lines and installed our own additional compression. Together, these improvements have had a positive impact on our ability to produce gas, reducing line pressures in some areas by approximately 20% to 35% in the past couple of weeks.

Moving on to our catalyst well program. We are pleased with the progress being made to delineate our acreage both aerially and vertically. The results from our three producing Codell wells have really stood out from the group and are tracking above our 313,000 Boe target type curve, producing an average 30 day IP rate of 540 Boe per day at 69% crude oil. They exhibit a slightly lower content or slightly lower oil content than our Niobrara wells but produce at higher rates. We intend to test expanding the eastern boundaries of our identified Codell potential in 2014.

We placed all four of our planned Niobrara C bench wells into sales during the third quarter. The average 30 day IP for the five total wells currently producing is 422 Boe per day with a very strong crude oil cut of 83%, well within our range of expectations. We are very pleased with these results. Keep in mind that the impact of high line pressures continues to be present by restraining initial rate and elevating the crude oil content of the wells by suppressing early gas production. We are getting increasingly comfortable with the Niobrara C bench's ability to deliver highly economic results across our entire acreage position.

Next, our extent to reach lateral testing program continues to provide compelling results. Our second well that we reported on last quarter held relatively flat over its first three months of reduction from 767 Boe per day to a 90 day average IP of 678 Boe per day, which compares favorably to the typical profile of other extended laterals in the area. Results to-date suggest an improved F&B cost versus a standard 4,000 foot lateral. We initiated gas with on -- our long east lateral couple of weeks ago. It is still our initial production stage and we do not yet have a 30 day IP.

Finally, we are encouraged by the early results of our 40 acre Niobrara B bench testing. Last quarter we reported on our first two 40 acre test wells that were drilled next to an existing producer. Three months later these wells continue to perform similar to the 80 acre B bench wells in that area which of course is what we are hoping to see. Our second 40 acre test completed during the third quarter, included four wells on a single pack testing an area that has no existing producing wells. The average 30 day IP rate for these four walls was 343 Boe per day with and 83% crude oil cut. The average 60 day production rate was 292 Boe per day at 77% crude oil.

Though these early rates are below what an average 80 acre B bench well produces they fall within the range of our expectation especially when you take into account that we had some operational issues on these wells during the 30 and 60 day period.

A few things to keep in mind as it relates to the IP rates. First, as discussed earlier higher than anticipated line pressures restricted rates by as much as 100 Boe per day per well. Remember that these wells were brought online during the height of high line pressures observed in the field during August. Second, we shut in two of the 40 acre wells closest to latest extended reach lateral well during flow back operations to ensure an effective frac was achieved on the offsetting extended reach lateral.

As a result of these two factors we assumed lower average rates but a flatter decline during the first 60 day period that our typical 80 acre B Bench well. We continue to be very encouraged by the potential down spacing to add significant value and will continue the 40 acre space testing on the super-section.

Speaking of the Super-Section, all of our three rigs are currently drilling the first of the planned 15 wells. We expect to be finished drilling by mid-December and begin completion operations in mid-January. We will utilize three frac crews to complete the wells new form and concurrently across the super-section and expect to see many full production in early March. Please keep in mind that due to the super-section drilling program first quarter of production will be impacted relative to fourth quarter as Q if any Wattenberg well will be brought online in January and February.

We will provide greater clarity rent when we released in 2014 annual guidance in January.

Moving on to the Mid-Continent region, I'm pleased to report very strong results. Our Arkansas property continued to put up great numbers quarter after quarter production from this area averaged 5,854 Boe per day, a 34% increase over last year and a 14% increase over last quarter. We continue to be encouraged by the five acre down spacing test. We have drilled 8 five-acre in-wells to date and plan to drill 3 more before the end of the year. We have not observed any interference between wells and initial production has been above expectations. The second of three round of recompletion on several significant wells have been especially successful with a result significantly above forecast.

I'm very proud of our operations teams. They have successfully executed the acceleration and drilling completion during the third quarter while ensuring their our properties were well prepared for the Epic Colorado in September. Being a good steward of the environment and a preferred neighbor to those that lived near operations, it's critical to our success.

With that, I'll turn the call back over to the operator to open up for questions. Mike will close with a final word after the Q&A.

Question-and-Answer Session

Operator

(Operator Instructions)

Your first question comes from the line of Brian Corales from Howard Weil. Please go ahead.

Brian Corales - Howard Weil

Two questions. Are line pressures have you seen those meaningfully improved, are they still an obstacle and do you think that -- or do you envision I guess that improving throughout 2014 or is it always going to be an issue?

Tony Buchanon

This is Tony; I'll go ahead and answer that question. Yes, we have seen line pressures meaningfully improve here in the fourth quarter with the startup of the O'Connor plant. We expect that plant -- we indicated that it came on at 80 million a day and it's ramping up to a 110 million a day here very quickly. We also see that expansion going to 160 early next year. So we think our midstream partners are really doing everything they can to kind of provide us the capacity to get our gas out and so we should be able to mitigate line pressures next year. But we will still have to continue with our own internal project or internal infrastructure projects with compression, pipeline improvements and things along that line to help abate those pressures. So not that they will go away but we do see them being there available for us to move the volumes that we're going to be planning to move next year and going forward.

Brian Corales - Howard Weil

And do you see that impact - is production going higher as a result?

Tony Buchanon

Every time you lower line pressure it does have a positive impact on production and most notably early on the gas volumes.

Brian Corales - Howard Weil

Okay. And then one more, the extended lateral well looked very encouraging. How does that fit into your plan going forward? I'm assuming that the super pad is not going to have any extended laterals, but are you going to get more and more of these each year?

Tony Buchanon

I think you can start to see us expand our extended lateral program. We haven’t announced what we'll be doing in 2014 yet, but I think you can see us planning to drill more extended reach laterals. The execution around laterals, those long reach laterals continues to be something that the industry needs to perfect and obviously we've drilled three to date, I think you could fully expect us to drill more and maybe as our pads develop start to see extended reach lateral type pads.

Operator

Thank you for that question. The next question we have comes from the line of David Deckelbaum from KeyBanc. Please go ahead.

David Deckelbaum - KeyBanc

Sort of to hit on last point about line pressures and some of the improvements, I know that production this quarter was again hampered by line pressures, but did you see a relative improvement on the horizontal side of the wells that you brought online at least - were the line pressures a little bit more amenable to bringing on horizontals at higher rates at least in the first 30 days. I'm just trying to get a sense that you look at some of the performance that you all had in this quarter. Certainly, there were a little bit more completions but it does appear that on average your core B bench wells did a little bit better than your prior batches?

Tony Buchanon

Well, I was going to say obviously the horizontal wells perform better with higher line pressure than vertical wells. But they still are impacted by the line pressures and what we were seeing I think is in the early time it is not so much the oil rates affected but the gas rates. The gas rates are more restricted and so it does affect the Boe when we report on Boes for IP 30s and 60. So we think those that are little restrained or constrained compared to what we probably had previously in lower line pressures back in 2012, but again it is more around the gas volumes but overall our horizontal wells are performing very well which is obviously why our production for the quarter exceeded our internal plans but exceeded obviously the expectations.

Gary Grove

Hey David, this is Gary. I was going to add one thing to that too. As Tony mentioned, the plant came online, the O'Connor came online in October. So we really didn’t see any impact of any of that reduced line pressure or potential reduced line pressure in third quarter at all. So as you look at those volumes, as Tony has mentioned, that's really due to well performance even in the face of those line pressures.

David Deckelbaum - KeyBanc

I guess going in the fourth quarter now and all the rigs have moved over to the super-section how many wells do you guys expect to complete in the fourth quarter? I'm sorry if I missed that.

Tony Buchanon

We expect to have 14 wells completed in the fourth quarter.

David Deckelbaum - KeyBanc

And the last one if I might, I know the production going into 1Q next year it is going to be a little bit lumpy, you are going to be coming out with your 2014 budget I guess sometime in January, is there a -- how would the super-section performance change that budget and whether it would be sort of a process that's initiated quickly after results are evaluated on that that would drastically alter your ‘14 program or is that more of a ‘15 consideration?

Tony Buchanon

I'll take a stab at the first thing. Obviously, we expect our production definitely to be a lumpy in the first quarter with the super-section wells coming on line really with meaningful production coming on in March. So fourth quarter coming in the first quarter of 2014 would definitely be lumpy. We will expect to start to extract data of that super-section obviously, if bring those wells on line in March it's going to take some time to get production data stabilized. I would suspect it's going to be at least six months production data before an analysis can really start to tell us some significant things about what's working and what's not working. So I would suspect us to be able to know later in the year of 2014 some analyses from the super-section. Expect any changes to our program in ‘14 after we come out, it could happen in maybe fourth quarter based on the results, I would suspect most of the changes obviously would impact maybe 2015 going forward.

Operator

Thank you. The next question we have is from the line of Ryan Oatman from SunTrust. Please go ahead.

Ryan Oatman - SunTrust Robinson Humphrey

I know you are done with 2013 completion activity and I guess we have a little lull here but the unchanged guidance at the midpoint would imply sort of a flat quarter-over-quarter production, is that a proper take on it or do you think that you guys will be the high end of that unchanged 2013 guidance with 4Q growth?

Gary Grove

This is Gary, Ryan. I’ll go ahead and take that one. No, I think we are going to probably as you look at the numbers you are going to see us trending towards the high end of that volume guidance. We are not coming out with a change to date obviously we expect to see production continue to perform along the same lines that we have seen. I think on the completions we still have a few that were ready to still perform for the fourth quarter. So as we talked about before we still have another 14 that will come on line in the early part of the fourth quarter. So you should definitely take that into consideration when you are looking at your fourth quarter performance analysis.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. Great and then over in the North Park basin we have seen Ellora generate some solid results over there with the well doing over 1000 barrels of oil a day on a 48 over 64 inch choke. Can you describe the quality of that test as you can see it from afar and how much confidence it gives you or does in your own North Park acreage?

Patrick Graham

Hey Ryan, this is Pat Graham. Yes, I think early on when we started developing the Niobrara, the Wattenberg we started off reporting 24 hour test and there is a lot of ways to report that data, so obviously we got away from that. I think the same can be said for North Park I mean they are impressive results, but you know really until you know the underlying data that went into determining what that 24 hour IP maybe look at evidence little bit hesitant, but very again, very impressive; we are looking potentially at drilling a couple of wells up in North Park next year in the Niobrara and very similar reservoir characteristics between where Ellora is and where our acreage position is.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. That's interesting and I think on a prior slide you showed your acreage being separate from a fall from EO3. Stuff is that the case with the E3. Can you just remind us what geologically that that hob means or doesn’t mean?

Patrick Graham

Actually all the EOGs claim lying position is now (inaudible) that's what they purchase. I mean, you are correct there is a large kind of basis (inaudible) that separates their acreage from ours, but what it does, it really creates a bowl, which their acreage and the good part of our acreage at the same depths again very similar reservoir characteristics from what you have seen from the vertical well logs that actually (inaudible) at the time drill and what we have on our side of the well. So from the data we have very similar.

Mike Starzer

I might answer real quickly that the lower results are not added the range of expectations for us. 24 hour IP is a little hard to discern as Pat mentioned, but when we do see that that's consistent with what our thinking in this area too.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. That's helpful and do you think your first test next year will be verticals or horizontals?

Unidentified Company Speaker

The wells will actually be drilled vertically to just really get data, but the completions (inaudible) finally to be horizontal.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. That's great. And then one final one for me. What's your acreage footprint out there?

Unidentified Company Speaker

We are about 25,000 net acres or so.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. And do you feel comfortable with that or do you think there is an opportunity to add?

Unidentified Company Speaker

Yes, always there is a possibility to add up there whether it is on structure of (inaudible), but yes there is potential to add acreage.

Patrick Graham

And we are very selective Ryan as you know in our history we are very technical oriented and we pick up acreage that we know has a good potential for value creation. So that's why we have over the years we have let some acreage go in North Park and then we have added more as we have learned more about where are the sweeter areas are.

Mike Starzer

Yes, Ryan I just going to add to what Mike said as well you know it is important for us to make sure that in this commodity cycle specially there were any oiling part of that particular window and as we are concentrating on so the wells that we are look to drill next year as Pat mentioned we will be targeting in that area as well.

Operator

Thank you. The next question we have comes from the line of Welles Fitzpatrick from Johnson Rice. Please go ahead.

Daniel Burke - Johnson Rice

Hey, guys this is actually Burke, Welles is on another call. Most of our questions have been answered but LOE looks great. I guess despite the flooding. Do you expect that to say flat moving forward or how should we look at that?

Tony Buchanon

This is Tony. I can think you can look at us on our LOE, we continue to be vigilant on LOE and want to provide a low operating cost, so we are targeting just to be within our guidance range going forward. So we took out there is one time pass that we had mentioned and obviously the volumes are driving somewhat on the unit cost could be heavy, but I think you can look at us for a landing within our target range for guidance.

Daniel Burke - Johnson Rice

Okay. And just one more on that Codell that wasn't stack Codell Nio B, was it?

Tony Buchanon

No, they were not.

Operator

The next question we have comes from the line of Ipsit Mohanty from Canaccord Genuity. Please go ahead.

Ipsit Mohanty - Canaccord Genuity

Hi Tony, congrats I never had a chance to sort of personally congratulate you, but want to congratulate you on your promotion.

Tony Buchanon

Appreciate you, thank you very much.

Ipsit Mohanty - Canaccord Genuity

So just let me just quickly start of, Tony if you could elaborate a little bit on what happen if those couple of wells on the Niobrara B 40 acre, you mentioned here it was hampered due to post frac but if you could add a little bit more color please?

Tony Buchanon

You bet, Ipsit. Let me get start off on the catalyst well in general again. With the data that we have just kind of capture it all, but the data that we have available us internally we are pleased with the catalyst results and they are all falling within our range of expected outcomes and for continuing to move forward with the development on all fronts which includes obviously down spacing in the B bench, the evaluation of the C bench the Codell and extended reach lateral. So again I would just want to re-emphasize we are pleased with all the results on our catalyst testing.

So specifically to your question, Ipsit, going to 40 acres what from an operational standpoint that we saw obviously I talked about high line pressure, that was a impactful on the area but specifically the two eastern wells of that four well pad were offset are most recent extended reach lateral that was drilled in the area.

During fallback operations on those two eastern wells, the timing for the frac came up with the extended reach lateral. We made a decision at that point to shut those two eastern wells in to go ahead and frac the extended reach lateral and of course the technical reason to do that was one of the insured that we properly fraced our extended reach lateral and not create any kind of offset to pressure sink by producing two wells that were offset to it that could influence a frac job on that well.

So it's not preferred operations. It worked out that way. So you might ask why we do that well that's the way it work up, but how do you fix it? How do you fix it? Well, we fix it by super-section ideas that the techniques that we are going to be doing as the go forward with pad development in super-section type operations where you come in and drill all the wells and frac them all at the same time eliminates the need to be frac or to be shutting in these offset wells as you perform frac procedures on your well.

So I think moving forward obviously we are going to be optimizing those procedures to do that. How does it impact those two wells? Obviously, when you frac an offset well, yes those two wells were impacted a little bit by additional water been induced from an offset frac and so that hampered the recovery in the early time. But overall I just want to emphasize that the results that we were seeing from the overall pad and given the result as we are to date they fall within our range of expectations and that we are seeing a flatter decline rate out of these wells compared to our 80 acre B bench wells.

Ipsit Mohanty - Canaccord Genuity

Just a quick one -- just to stay on the same like that the Codell wells that you have given and obviously this would be getting better as you have moved from one to the other, but just geologically are they the same, is there any differences that you have seen in the rock quality?

Tony Buchanon

Our wells between our Codell wells maybe minor, Ipsit, typically the Codell it’s the sandstones better perm better porosity but again you have some variability probably just across the field but nothing significant. Again when we complete these wells we expect a range of outcomes, there is not just a one number that we are shooting for when we bring these things online.

So we look at all these Codell wells as being within our range of outcomes. There is just not that much variability in the reservoir that would cause that. And I think it's a good point, our first Codell well was the 370 Boe per day IP 30 and I just wanted to say that there are probably wouldn’t quite that our, there were some people that reached maybe a little disappointing with that rate of course internally we are very encouraged because it indicated that it would be productive and that we can improve moving forward and so when you think about back to our 40 acre B bench that something kind of factor in my mind.

These initial B bench results on that four well pad that we just did is very similar to our initial results on our Codell and you can see where the Codell has taken us. So I just want to capture that there is a range of outcomes and that all the wells we drill are falling within that.

Ipsit Mohanty - Canaccord Genuity

Yes, and my last one. This is more of a broader question for Pat and the rest of the team. In our past discussions you have talked how the Wattenberg is pretty cored up among the guys who are there the large caps and then you all at the mid cap level. As you look outside from any -- is this something within taking a step back is it something within the region that interests you, I mean Whiting has talked about its red tail and how good its doing, Noble has done about East 1E. Is there an extension of the (inaudible) that you are looking within the basin?

Michael Starzer

This is Mike, Ipsit. I will go ahead and feel that it maybe something would like to chime in. Being operators there in Wattenberg since 1999 we have a very strong knowledge of the basin and we are very selective, but we are also very aggressive that anything that becomes available in the basin that fits our investment criteria, we are all over it and there is a number of -- now we pick up small pieces of acreage here and there all around our position. The bigger blocks although mostly caught up, we look at those very closely too and if they become available we are over them. Pat, any additional color from that for Ipsit?

Patrick Graham

Well, I have to say that we have done a number of acquisitions this year and we probably increased our acreage position by about 10%. Now, it's all on our core area and as Mike mentioned, we are very aware of what's out there; we have got the whole basin mapped out, we know where the places that we want to acquire acreage would be and we definitely keep an eye on those rocks and approach any parties out there that we believe might be interested.

Operator

Thank you. The next question we have comes from the line of Adam Michael from Miller Tabak. Please go ahead.

Adam Michael - Miller Tabak

Hey good morning guys, I think most of my questions have been asked already, but I did catch there is a line in your press release about a pipeline system to bring frac water in. And I wanted to get a little more color on that just curious, what you currently spent for well trucking water out and how much potential savings could we see from this?

Tony Buchanon

I will go ahead and take that. Adam, Tony here again. We have that pipeline system we just got that up and running and basically the pipeline system that kind of goes through the middle part of our acreage what we call our 70 ranch area and we are utilizing that now versus tracking water. We are starting to see a reduction in cost on that. Obviously, any time you take trucks off the road and can pipe water that works for us.

So I don’t have a firm number yet on that because we have our estimates but we are actually starting to see the full impact of that here in the fourth quarters. We finish up these competitions, so I can probably give you a better number going forward. Obviously, intuitively we are going to be saving some money by doing this, but I hesitate to give you a number today that you can put into a model because I really want to get some real numbers documented as we come to fourth quarter now that this thing is up and running. But again safety wise it is important to get trucks off the road. It's good for the land owners, it's good for everybody to produce that kind of traffic so we will have some savings but if I can leave it at that I'd go from there.

Adam Michael - Miller Tabak

And then I guess do you think that something that you would expand to other parts of your acreage going forward or is this kind of a specific project just done on that one area?

Tony Buchanon

No, I think you can look for us to expand as we go forward. Obviously, in our 2014 and going forward as we increased the number of well we have out there, you can see as to we would be looking to have infrastructure projects on water delivery water to disposal oil piping around our core position. Since our position is so contiguous, it leverages us very well to do those types of infrastructure type projects. So I think you can see us doing those going forward and anytime we can get that done it will improve our efficiencies.

Mike Starzer

Adam, I might just interject also, Tony's team are always looking for continuous improvement in operations and investments out there. Having contiguous acreage is a real blessing to have but to be able to bring some economies of scale in all our development going forward. So we will see cost savings, we have quantified that internally but as for significant and Tony will give you better estimates later on I think are right now we are still projecting the same cost going forward.

Operator

Thank you. The next question we have comes from the line of Michael Hall from Heikkinen Energy Advisors. Please go ahead.

Michael Hall - Heikkinen Energy Advisors

See I just wanted to circle back a little bit on a topic that we brought up earlier as it relate to those 40 acre down stage tests and I had to set them up in an advance of fracing the offset and extended reach lateral. I understand what we kind of better understanding how to approach the super-sections and what not, but it seems that's probably more of a later '14 early '15 type time frame to move into that on a widespread basis. In '14 should we expect to see any material amounts of downtime associated with setting in wells for offset fracs or I think there will be more as kind of one off and shouldn't we have a material impact having here?

Tony Buchanon

I guess, what I would answer that first half obviously as you delineate your acreage you have wells that are going to be out there that you had to drill first delineate acreage to prove if you wanted to go back and drill again. We are going try to minimize that going forward but I would say that obviously in 2014 we are still going to have wells where we go drill offset existing producing wells and we will have to shut those in and they will be impacted by that.

What I can tell you though is it that when we release our volume guidance for next year that will all be part of that. We have done a detailed technical analysis of the wells we have on today and that impact from those wells and that would be factored into our production forecast that you see as providing here when we get guidance in January. I wish it will get avoid but once you delineate you are going to have some of that. Now we are optimizing our program to minimize it. So I will say that.

Michael Hall - Heikkinen Energy Advisors

Great. That makes sense and that's helpful. And then I guess the only (inaudible) was around the -- actually the mid-continent program was just better than we had been modeling. It seems like some good strength in the quarter there. Anything in particular driving that and is that sort of production level sustainable going forward?

Gary Grove

Yes, this is Gary, I will go ahead and take that one. I think a couple of things down at mid-continent are driving the quarter if you will and we have talked about our five acre into a program and that has been doing well. Internally, we added some risk on that just because the expectations as you down space you might see some interference.

As Tony mentioned earlier, we could just haven't seen that today on those wells, but those well quite frankly are outperforming what we would consider for a five acre initially and performing more in line with the standard 10-acre wells that we have been drilling out three since 2008.

Not to add into it, the second thing I would tell you that as we drill these wells, we produce the bottom mineral first and then we started to add zone through time either three months later or even beyond that and now those particular recompletions have been very strong in this quarter as well. It goes from the ability for us to get them performed and also have the responding.

And then thirdly I would leave it with the plants that we have in the plant that we brought on line earlier in the year continue to help our performance there in terms of lowering our shrinkage, if you will, and increase in our yields. So the combination of all three of those I think will lead into a strong quarter in the mid-continent and we would expect to see that in a continued performance going forward.

Operator

Thank you. The next question we have comes from the line of Joseph Magner from Macquarie Capital. Please go ahead.

Joseph Magner - Macquarie Capital

Just curious on the outlook for first quarter and then 2014. Last year you guys slowed development drilling towards the end of 2012 and that sort of pulled down the first half 2013, is it right to think that you will see kind of flat start to the year and the back half loaded ramp or beyond the super-section activity in the first part of the year how might things shape up for the balance? Just trying to, I know we have not given guidance here, but just trying to take through those.

Gary Grove

Yes, Joe, this is Gary again. I think the important thing to know is it did not come out as -- right now the way the schedule looks is probably in January and February we won't be bring in any well online at all in the Wattenberg due to the fact the way the super-section drilling has been performed and the way we are going to completed those wells and bring them online.

So I think that's probably the biggest piece of information that we would like to share with you and looking at the first quarter as it might compared to the fourth quarter of this year and then as you would expect as those 15 wells, if you will, start to come on line at the end of March and towards the beginning of April. And then we continue to see that program ramp up from there with the rig now moving back to a non-super-section type of drilling program. I think that's the best way I describe at this point in it. While it maybe not for the same reasons you might see some similar attributes in 2014 as you have seen in 2013 as far as the construction of the volumes go for the year.

Joseph Magner - Macquarie Capital

Okay. And then I guys just want to make sure I understand where it hit the comments made drilling on a super-section will be done in December and then completion activities work start in January, where will the rigs move and is it all the activity and all the effort will be focused on super-section completions and you would be able to get to new wells that might be drilled in the first quarter until later?

Tony Buchanon

This is Tony. I will just check, yes, no problem moving the rigs those three rigs that we drilling once they are done with the super-section other than coming out of the holidays we will plan to put those rigs back to work quickly in January on our 2014 drilling program. The super-section is tied to one section but we have plenty of our opportunities to go drill and that's where those rigs will go.

Gary Grove

I am going to add one piece. If you think about a typical well out there when we spud and when we bring it online you know are in that 45 day to may be 60 day timeframe from a new spud to bring it online. So if you don’t start drilling again on something other than the super-section again at the early part of next year and that's why you say you probably don’t look to bring wells on in January and February just because of that normal cycle timeframe on a given well throughout our acreage position.

Joseph Magner - Macquarie Capital

And then on the go forward ground there is still a lot to learn on the super-section development, but given what you have seen already with the need to shut in offset locations in kind of an isolated scenario granted it makes a lot of sense to drill a section and complete all the wells at the same time, but moving forward you know what kind of a question or what kind of a right term would be that as you develop super-sections next to one another how much of a buffer do you need, how many wells might be need to shut in on those? Granted it is down the road, I'm just curious that you think about impact on the drilling completion and shut in nature of that as it rolls forward?

Tony Buchanon

Yes, this is Tony again, I will take a stab at that. Obviously, as we drill wells, wells that are directly offsetting the existing well that we drill and get rid of frac would be wells that we would need to be shutting in. And again, as I mentioned, preferably going forward hopefully we have tried to do with our acreage position and leave ourselves a lot of places that we would be come in and do the full pad development type drilling or you don’t have to shut in if any wells at all or just a few, but again going forward you could look at having to shut in the offsets and then every area the field can be different. We would take a look at there maybe area of field where you don’t have to shut it in because of some the way the wells are producing or they are in the production life for something on that line.

So we will manage that as we go forward but what we can tell you is when we provide our production guidance going forward all the technical analysis that looks at all that with all the data will be included in those production guidance numbers that we release especially as we started to talk about 2014 that will be counted into that.

Joseph Magner - Macquarie Capital

Okay. And just one last one from me, I think in the presentation you all had been guiding to take around 18 completions for the fourth quarter. Were some of those put forward in the third quarter or some to third because of the super-section activity?

Tony Buchanon

They were pulled forward in the third quarter, just towards the end of the third quarter.

Gary Grove

And again, a week or two we could put it in the third or fourth quarter. So that time it is a little somewhat nebulous there, but it was that definite as we go forward.

Operator

Thank you the next question we have comes from the line of David Beard from IBERIA. Please go ahead.

David Beard - IBERIA

Most of my questions had been answered, but I wonder if you just have me understand things like down in the mid-con the mix shifted all the more towards NGLs and what was driving that mix and is that sustainable and could that even grow going forward?

Gary Grove

It’s a combination of a couple of things. First is we probably seem a little bit more well head gas, I know it is going to sound a little bit odd but a little bit more well head gas, which obviously brings more gas into our plants and remember our ownership structure there is we own those facilities 100% and so the way the contracts are structured the plant does receive a bulk of the liquids revenue there, if you will, than corresponding volume. That's one thing that would kind of lead us to little bit more liquid yields there.

Second one is, as I mentioned earlier, the plants themselves have been operating very efficiently and our yields have actually been increasing throughout the year with that stream of gas coming into the facilities. I am sorry about coming and going forward, again we can't always know exactly that the mix was going to come from the well head but given the existing conditions we make our plants are going to continue to be efficient and I could tell you that.

David Beard - IBERIA

Okay. And as a quasi-related follow up we have seen some competitor advances in the brown dense, just wanted to hear your updated thoughts on that region?

Gary Grove

Absolutely, this is Gary again. We are excited honestly, we are excited to see that sharp well come on from southwestern. I mean they really had a lot of conversation around it and we are excited to see that that well is obviously in the weak dense, were a bit further away from us. However, they did mention not their second well, but their third well as they mentioned that they just finished the drilling is the McMahon well and it is about five miles south of (inaudible) position. So quite frankly we feel like we are in an MBO position here, all of our acreage there is held, we don’t have to do anything with it.

We do have brown dense opportunities there as we have mentioned in the past. We are excited to see this new well, if you will, that's going to be completed hopefully very similar in line with a sharp in their (inaudible) well and see the results of that and if it continues to be successful that's something that we will look to basically follow quickly on our acreage again as that information starts to come in.

I think the other thing that we have seen and would be interesting to us is the report actual cost on the second and third well. The first while came in around $10 million, we would like to see those cost come down more and I know they do too and it is kind of intimated it might be around $7 million on the second well. So as we continue to see the results even a little bit close to home, if you will, we will be quick to follow on that.

Operator

Thank you. The next question we have comes from the line of Mike Kelly from Global Hunter. Please go ahead.

Mike Kelly - Global Hunter Securities

So the catalyst program through this year obviously it has been a huge success and still get a lot of work and a lot of excitement left with this super-section that you're going to have come on early next year, but I am curious just moving beyond that given the technical talent you guys have with the company it appears to here if you are starting to think about what potential next vintage of the catalyst program could be out there for you, if the Greenhorn is starting to be something that you are going to think about testing more seriously or some other concepts up there that we may hear about in 2014? Thank you.

Tony Buchanon

Yeah, Mike. This is Tony. I will take first pass of that. Obviously, there is other horizons out there as with any play with the (inaudible) stacked pace. We always seem to be able to figure out something else that is going to work. So if you look at our acreage position we have the A bench, we do not have that in our current resource but as you can look for us to be looking at something there in the A bench testing. We also have -- as we talked about the Codell, as we continue to push to the eastern -- push the Codell development in eastern.

The Codell sits on top of the Carlile Shale and the Carlile Shale it is the source rock ford the Codell. As we continue to see how this works, as we go to the east, if we can drill wells in the Codell on the less and less Codell and can encounter more and more Carlile and still make wells, you can see that the Carlile could have some potential. If that works that something that could expand across our entire acreage position.

As you talked about the Greenhorn, the Greenhorn is another one. We are looking at the other companies and some of the things that they are doing in the Greenhorn but we have Greenhorn. So yes, that is another potential resource for us. The (inaudible) Shale is another potential resource. Again, our technical teams will start to look at those resources assessment as we move forward and apply the key data that we are getting out of the Niobrara's and Codell right now to see what we can do to crack those open to possible.

Mike Kelly - Global Hunter Securities

Okay, great. You think that is something that we see -- how do you guys at 2014 some horizons tested?

Tony Buchanon

Yeah, and the one other thing I might add to you is the fortunate thing we have on our acreages, we have 3D across our entire acreage and so would that does allow us to also look for is something little more conventional and its the lines formation. The lines formation sits down about 9500 feet, it is more of a conventional trap. It is not something you would pursue from an unconventional resource play. But if you got 3D seismic on it and you can see the bumps and you can drill it, you can be very successful and you can see us while looking the test of lines potential that we have on our acreage position. We are actually in the process of drilling a lines test today and we will continue to look at that as we go forward. So that is another horizon, but again it is not more -- it is more conventional, if you will, but again we have the data we will take advantage of that.

Gary Grove

I just will add to that lines piece real quickly. I mean it -- we are looking for oil initially, it is not -- as Tony mentioned it is not huge resource across the area so it is going to have its opportunities across the acreage. But we also have -- and what we like to kind of firm up is our backup position there which would be you use those wells, if they happen to be unsuccessful as a saltwater disposal candidate, which would go to ordinary kind of eliminating or if you will reducing some of our operating expenses going forward as well. So it gives a nice kind of intern opportunity for us at the end of this year and even at the beginning of next year.

Mike Kelly - Global Hunter Securities

Very good. And just a quick one here. How much of your acreage do you think now is derisk for the Codell? What is a good number for us to throw on there for risk factor? Thank you.

Mike Starzer

We are still carrying, Mike, about 15000 acres on the western portion of our acreage, we are going to learn more as we develop. And that is why as Tony mentioned about testing the Codell further and then in conjunction with the Carlile. So -- but right now we are still holding a 15000 acre number, we feel very confident in.

Operator

Onto the next question. We have comes from the line of Ray Deacon from Brean Capital. Please go ahead.

Ray Deacon - Brean Capital

I had a question about the sea test that you announced. Can you talk about whether they were geographically spread out across your acreage or on the same block?

Tony Buchanon

Very good question. This is Tony again. Yeah, what was encouraging about our sea bench test, they were scattered out across entire acreage position from the furthest to western part all the way to the furthest eastern part of our acreage position. So we have five of them online and that is why it lead us to -- I am not saying it is fully delineated but obviously our confidence factor is increasing significantly with the sea bench potential across our entire acreage position because of that.

Ray Deacon - Brean Capital

Okay, great. Thanks. And with the super-section there is not a relatively fewer sea bench test, is that because of vertical wells in the area or just that you feel its derisked?

Tony Buchanon

No, on the super-section test again, one of the key things that we are testing there is more of the vertical stacking. And so, we are stacking B, C and Codells together to get an optimum fit, if you will, from a vertical standpoint on how we want to lay these wells in and how we need to stagger them. So it was more to test the stacking technique and not so much to do to delineate the C or the B or the crude oil because that is basically and that area is already delineated. We know that it is there now. Let us try to figure out how we want to stack the wells in there to produce them and complete them efficiently.

Operator

The next question we have comes from the line of Ravi Kamath from Global Hunter. Please go ahead.

Ravi Kamath - Global Hunter

I had couple of questions. One on the mid-continent, how much of your position in Dorcheat you think is de-risked for the five acre down spacing and do you expect to be booking lot of five acre reserves at that -- at your end?

Gary Grove

Yeah, this is Gary again. The two areas that we have the most information on are kind of towards more the eastern and central part of the field. The wells that we are drilling now, that Tony mentioned are more towards the western part of the field. We obviously want to continue to see information across the property. And so, that is kind of what we have delineated at this time.

As far as booking for year end of this year, I think what we have determined with looking at an internally as we probably would not look to book any five acre offset at this time and get a little bit more production history. If you remember that we want to see not only the initial completion but also the additional zones that get added and they get added over the course of a year at a minimum. And so we want to see a little bit more data there before we feel comfortable going to our third party analyst and recommending any direct five acre offset. So I think we will probably be a little, if you want to call, conservative that is fine, in timing of adding any five acres at this year end reserves.

With that said though, we have looked at the property and I think we have mentioned it in our investor presentation. That upside looks to be 200 plus locations at five acre drilling, if we deem it that it ends up being successful with what we are looking at the date and everything at this point is pointing to very encouraging results.

Ravi Kamath - Global Hunter

And then, a second question on the Wattenberg vertical production, looks like that came down to about just under 700 Boe per day from about 1200 in Q2. How much of that would you say was related to the flooding and what do you expect that to kind of do in Q4, if you could just comment on that please?

Tony Buchanon

This is Tony. I will take first stab at that. The vertical production basically very minimal impact due to flooding, I mean we had a hand full of -- we shut in proactively 26 vertical wells, we have most of those wells back on minus. So we have minimal impact due to the flooding on the vertical wells. We have about 255 total vertical wells to give you a flavor for how much that is.

With most of the production in fact on the vertical wells has been really due to offset frac into by a horizontal program. Those wells get fraced in to, they knock the wells off. And then, of course, during this time period -- and third quarter is included in that, emission season, with the emission season being more strict through the end of September bringing those vertical wells back on line is more difficult to do. Typically, we can open tanks and let those wells kickoff on their own. With the emission season we were not able to open the tanks to do that, and so therefore the wells would require swabbing to get back on line.

Compounding that obviously the high lime pressures. When you have high lime pressures, the vertical wells are the most affected. And so, when you try to do all those things and then used to have high lime pressures, the wells may not come back on line and stay on line. So what I think you can see going forward is that we will make a obviously a better -- we are going to be more getting those -- more of those wells back on line, starting in the fourth quarter, but it is all tied to with the O'Connor plan coming on line and our internal and infrastructure project we brought on line here early fourth quarter. That is going to help those vertical wells come back.

Again, we will economically be proven on getting those things back on line. Obviously, we have some of that, we are going to be fracing another horizontal well in that area, we are probably not going to spend the money to get it on line until we have all the fracing done, so that we can get back after get it on line at that time and be able to leave it on line. So I think you could see us to bring those back on line gradually here in the fourth quarter and early in the first quarter next year.

Operator

Our next question we have come from the line of Michael Scialla for Stifel. Please go ahead.

Michael Scialla - Stifel Nicolaus

Tony, you mentioned the Pronghorn area was particularly impacted by the high line pressures. Can you say how many horizontal wells were affected there?

Tony Buchanon

Well, to be honest with you Mike, all the wells in our pronghorn area were impacted by that. I'm going to say on a well count we probably have about 20 to 30 over in that area. So all those wells were impacted by that line pressure, every single one of them. And it was obviously hit with the highest lime pressures. That area we are going to get some relief now. It would be Sullivan Compressor Station that is coming online. We have just added what we have DCP, just added additional capacity up there. So we are starting to see those line pressures come down. And it has been pretty dramatic in that area, we have had a -- we spiked up the 400 pounds over there. Right now, most recently, in this past couple of weeks we are seeing it down in the 225 to 250 range, still not perfect but a whole lot better.

Gary Grove

And Mike, this is Garry. Just add to what Tony said is, if you look at the wells that were drilled in this calendar year, a lot of those wells on that eastern pronghorn area we drilled earlier in the year. So we kind of just directionally the way the rigs were moving for the year, just giving idea of where those wells are positioned. So a lot of those wells drilled there in the year have been seeing that high line pressure over that pronghorn area throughout the year.

Michael Scialla - Stifel Nicolaus

Okay. And if I heard you right, Tony, you said you thought it was about a 100 Boe per day kind of impact on a 30 day rate for those wells?

Tony Buchanon

Yeah, actually probably Mike, yes, it's about 100 Boe per day and actually if you had even more pressure what we're looking at is about 5 Boe per day per psi. So if you got a well that's more impacted by pressure you might even be looking at something a little more than 100 Boe per day.

Michael Scialla - Stifel Nicolaus

And is that something that just started to impact the horizontal wells this year or was that a factor on horizontal wells last year as well?

Tony Buchanon

It's more of a factor on the wells this year.

Michael Scialla - Stifel Nicolaus

And then the two wells that you had to shut in for the offset fracs, is there anyway to quantify how much those were impacted in terms of Boe per day on those 30 and 60-day rates or is that too difficult?

Tony Buchanon

I would probably fall back to say its around that 100 Boe per day per well. I think that would be pretty sufficient, Mike, on that one because it is a little difficult as you bring those wells back on the early time flow back time. But we definitely did see the impact for sure and those wells do have a flatter production profile as we brought them back online as they cleaned up.

Michael Scialla - Stifel Nicolaus

And then you were asked about the long laterals and it sounds like, if I heard you right, its something that you're going to continue to work on and maybe slowly ramp up? Do you ever foresee I mean, given the performance not only of yours but Noble and Anadarko as well, do you ever foresee I guess the chance that that becomes the standard for Bonanza Creek or do you think it will always just be a smaller portion of the portfolio?

Tony Buchanon

Mike, no, actually I do see it continuing to grow and if the results continue to follow and most importantly if we can mechanically execute these things over and over again like we can our 4,000 laterals I think that's the biggest thing. We wanted to get repeatable for the success rate of the extent of each laterals are the same as our 4,000 foot laterals were you can basically drill them and count on them coming online every single time. But with that being the case and where we're progressing and I think you can see the programs evolving to where a majority of your program would be medium reach or extended reach, a variety of those kind of things but definitely longer laterals than 4,000 feet.

Mike Starzer

Mike, this is Mike. I might interject also that the key learnings that we have over the next 12 months with the super-section testing, that its not mutually exclusive to extended reach lateral development application out there on the field. So what we're learning maybe come aside about is it culminating altogether in 2014, both extended reach lateral technology as well as super-sectioning optimal stacking technique. And we come together as we plan 2015 and the future.

Michael Scialla - Stifel Nicolaus

Got it. And I'll look forward to that extended lateral super-section coming up. One last one for you, Mike. You'd mentioned you will be aggressive looking at opportunities within your core area. Just curious was that Marathon acreage of interest to you at all or was that outside your core?

Patrick Graham

Hey, Mike, it's Pat. Some of the Marathon acreage is pretty spread out kind of like since those definitely come in our core area although relatively small to the overall size of the package. But, yes, there was definitely some piece of that were of interest.

Operator

Thank you. The next question comes from the line of Irene Hass from Wunderlich Securities. Please go ahead.

Unidentified Analyst

Actually this is Mo dialing for Irene. Good morning everyone and congrats on a good quarter.

Mike Starzer

Thank you, Mo.

Unidentified Analyst

Two quick questions. First question on the Codell. Based on the three wells you've completed so far, are you seeing a higher GOR than originally anticipated for Codell?

Tony Buchanon

Mo, this is Tony. No, we're not. Actually I think its pretty consistent with what we expect to do in the Codell. The Codell has always been a little bit more gassy than the Niobrara. So totally I think we're within our expected range of outcomes on that.

Unidentified Analyst

And my second and last question about on the extended reach lateral, looks like the second well had a flatter decline compared to the first well. Can you speak a little bit about what caused that?

Tony Buchanon

Well I think on the second well first is the first well the biggest thing is that we got the entire lateral completed on the second well. If you remember, our first well that we drilled last year we were lacking about 1,000 foot a lateral that we were able to complete. So you're really comparing an apple and an orange there I think. But we successfully completed this well and successfully fraced it, cleaned it out and put it online. So this is kind of a good test of a well completed extended reach lateral well.

Unidentified Analyst

Did you have the oil cut for the 60-day rate?

Tony Buchanon

We're looking for that, Mo, real quick. We'll get that to you here shortly.

Bill Cassidy

Mo, I tell you what --

Mike Starzer

We'll get back to you.

Bill Cassidy

Can we get back to you on that, Mo, because we'll have it handy (inaudible). We don't have it on our fingertips.

Unidentified Analyst

Absolutely, thank you very much.

Operator

And so the next question we have comes from the line of Brian Steck from Mangrove Partners.

Brian Steck - Mangrove Partners

I just have one question. You've done a wonderful job of answering a lot of questions here, and so I just have one query. I was hoping that you could comment on what our reserve expectation should be going into the year end report in the Rockies? I appreciate that you're not going to be overly aggressive and adding reserves five acres basin and the mid continent, but my recollection was in the Rockies there were some offsets last time around because of some vertical wells that would be coming off. And wondered that was going to continue to be the case, and also wondered if the horizontal wells that you're drilling this year, how many of those were PUDs versus otherwise?

Gary Grove

Yes, Brian, this is Gary. I'll go ahead and answer that real quick. As far as the number, we haven't guided any reserve number for the end of the year and quite frankly we just won't -- we won't be doing that as well. Obviously, we've drilled a lot of wells that haven't been in our proved reserve ledger in the Watternberg. And about approximately 85% of the wells we drill this year in the Watternberg horizontally were not in our proved reserve ledge as of the end of the year last year. So you can kind of get a feel for that looking forward on that kind of number.

But you did hit on another point I don't want to ignore and that is the fact that we did have vertical wells out there. In our PUD reserves and even a little bit of PDNP work for refrac work, and as we move forward we did renew some of those. We'll continue to do that as we transition our reserve ledger combination of vertical and horizontal wells to what looks today to be mostly a horizontal development going forward.

So there will be some slight impact of that at the end of this calendar year as well. We may or may not decide and transition all of those out; it may take one more year. But that's very similar to some of our neighbors here again who have been just a little bit in front of us maybe on their program by a year or two specifically Noble like you pointed them and, as I think we mentioned in the past, they took about three years to completely kind of move off of their old vertical PUD type of reserve ledger, if you will.

Mike Starzer

Brian, this is Mike. I might interject that we had our resource, being a strong resource oriented company with over 350 million barrels potential through our 3P or as we did the catalyst testing and we received more results and key learnings we will be adding crude reserves. But as we've mapped it out in to the future we stayed top quartile reserve additions on our proved reserve growth. And I think its safe for me to say that with that large resource base.

Gary Grove

And I think just to add to that one little last piece is as folks well understand and look at these kind of resource plays, proved 1P reserves are important but 2P and 3P reserves are much more important here in these resource type place than they are maybe a more conventional type of opportunity. And as Mike mentioned, its really just definition driven. The definition that we use for SEC parameters kind of put blankets or put brackets around, if you will, what we put as approved reserve for any given year.

Operator

Thank you, ladies and gentlemen, that concludes your question and answer session. I would now like to turn the call back over to Mike, Bonanza's CEO, for closing remarks.

Mike Starzer

Thank you, Carolyn. Thanks again to everyone for your support of Bonanza Creek. To summarize our key takeaways for this quarter; first, our assets continue to produce consistent, predictable and highly economic results. Companywide production was up 32% while Rockies production was up 41% over last quarter and we achieved an overall cash margin of approximately $58 per Boe. And second, our early results from catalyst wells continue to impress and support our view of an expanding resource with many years of highly economic inventory. The Codell is outperforming the Niobrara B bench tight curve while Niobrara C bench is being delineated across our acreage position.

And then finally, number three, the recent 36% increase to our borrowing base provides Bonanza Creek with nearly $400 million of liquidity. We continue to have one of the strongest balance sheets among our E&P peer group by investing in projects that provide some of the highest economic returns available in the United States today.

I'm proud that Bonanza Creek has consistently been one of the top performers in our sector since our IPO. We believe the diligent management of Bonanza Creek's rapid growth and investment, revenue and cash flow will continue to underpin our top quartile returns for owners. The strong operational progress we're seeing across both regions combined with our focus on disciplined investment and operating excellence provides confidence in growing long term sustainable cash flow and increased shareholder value.

We also continue to be active as assisting our local communities and trade organizations to promote good corporate citizenship and public education of the E&P industry, particularly the responsible use of advances and pressure stimulation technology.

Before we go, as alluded to earlier, we expect to announce our 2014 budget and annual guidance in early January. So we don't talk to you before then, we wish everyone a very happy holiday season.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. That concludes the presentation. You may now disconnect. Have a good weekend.

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