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Bonanza Creek Energy, Inc. (NYSE:BCEI)

Q4 2012 Earnings Call

March 15, 2013 11:00 am ET

Executives

James Masters – Manager - Investor Relations

Michael R. Starzer – Director, President and Chief Executive Officer

Gary A. Grove – Director, Executive Vice President Engineering & Planning

Ryan Zorn – Vice President - Finance

Analysts

David A. Deckelbaum – KeyBanc Capital Markets

Irene Haas – Wunderlich Securities

Brian Corales – Howard Weil Inc.

Andrew Coleman – Raymond James

Michael Scialla – Stifel Nicolaus

Ryan Oatman – SunTrust Robinson Humphrey

Andrew Venker – Morgan Stanley

David Tameron – Wells Fargo

Mark Lear – Credit Suisse

Chad Mabry – KLR Group, LLC

Michael Hall – Heikkinen Energy Advisors

Nathan Churchill – Societe Generale

Operator

Good day ladies and gentlemen, and welcome to the Quarter Four 2012 Bonanza Creek Energy, Inc. Earnings Conference Call. My name Rachel and I will be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions)

I’d now like to turn the call over to James Masters, Investor Relations Manager. Please proceed, sir.

James Masters

Thanks, Rachel. Good morning, everyone. Welcome to Bonanza Creek’s fourth quarter and year end 2012 earnings call and webcast. Yesterday afternoon, we issued our earnings press release for fourth quarter and full-year 2012 and filed our 10-K with the SEC this morning. You can access both on our website at www.bonanzacrk.com.

Our remarks today will include forward-looking statements. These statements are subject to many risks and uncertainties that could cause actual results to differ materially from our expectations as expressed, but are based on our current views and most reasonable expectations. These factors are described in our 10-K and our other SEC filings which you can access through our website or the SEC’s website.

Also, during this call, we will refer to certain non-GAAP financial measures. 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.

Finally, as you know, during the second quarter we begin a divestiture process of our non-core California properties. Under GAAP we disclosed the results from these properties as discontinued operations in our 10-K and in the statement of operations and balance sheet in our press release. Our overall results discussed today reflect total operations including discontinued operations.

We are presenting our results this way to increase comparability with our 2011 numbers, which you are all most familiar. In the future, we will focus on our presentations on our continuing operations. On today’s call, Mike Starzer, our President and CEO will begin by discussing the highlights for the quarter, and end by providing comments on 2013. In between Gary Grove, our Executive Vice President, Engineering and Planning, will report results from our operations. Other members of management will be available during the Q&A portion at the end of the call.

With that, I’m to happy turn it over to Mike.

Michael R. Starzer

Thanks, James, and good morning, everyone. We appreciate you joining us today and look forward to reviewing what was a very positive quarter and a great year.

As James mentioned, I’m joined by Bonanza Creek’s management team who will be available to answer questions at the conclusion of our prepared remarks. I owe these men and women and their respective teams, my sincere gratitude for their outstanding work this year. By nearly all measures, 2012 was a terrific year and I’m proud of our performance.

I believe that we are well positioned to continue doing the things that have made us successful. In doubling production in 2012 and preparing for continued top tier growth, we added key members of our management team and strengthened the personnel, infrastructure to support a rapidly growing company. We have increased our horizontal rig count to four full-times rigs in the Wattenburg Field and are currently on schedule with our 2013 development program.

We are incredibly fortunate to have a large contiguous acreage position in the Wattenburg Field, one of the most economically attractive place in the United States. Our horizontal well results continue to improve over the course of the year, bringing our total program 30-day IP rates from approximately 470 Boe per day to over 500 Boe per day with very strong wellhead crude oil rates of over 75%.

In the Niobrara "B" Bench at 80-acre spacing were our only opportunity, we would have an attractive development inventory for many years. Buy as you all know, we and others were testing 40-acre down spacing and extended reach laterals in the Niobrara "B" Bench, as well as targeting the Niobrara "C" Bench and the Codell for horizontal development. These additional opportunities have the potential to significantly expand our portfolio of high return projects. Gary will talk more about these exciting results, but suffice it to say that we are very encouraged and are eager to optimize the value of this asset.

For right now though, let’s go to the results for the fourth quarter. Revenues for the quarter were $74 million, up 100% from the fourth quarter of last year. Our sales volumes for the quarter amounted to 11,994 Boe per day, a 26% increase over the third quarter and a 107% increase over the fourth quarter of 2011.

The sale of crude oil represented 7,960 barrels per day, or approximately 66% of total production. The strong quarter contributed to annual revenues of $236.6 million and 115% increase in sales volumes to 9,403 Boe per day. Adjusted net income for the quarter was $15.7 million, or $0.39 per diluted share on strong revenue and declining operating costs.

For the full-year, adjusted net income increased 194% to $52.2 million, or $1.31 per diluted share. Excluded from adjusted net income were unrealized gains from commodity hedges, stock compensation expense impairment, exploration, dry hole cost and gain on sale of oil and gas properties.

Our EBITDAX for the quarter was a record $54.1 million, that’s up 138% from the fourth quarter 2011 and our full-year EBITDAX was a very strong $162.1 million, up 136% over the previous year. Our balance sheet remains solid with liquidity of approximately $123 million at year-end and a leverage ratio of less than one times debt-to-EBITDAX.

As we have stated in the past, we expect to govern our sales and our growth by staying below a two times debt-to-EBITDAX threshold. We think the flexibility of our balance sheet is a competitive advantage and we plan to keep it that way.

Before I turn the call over to Gary to discuss our operations, I would like to address 2012 capital expenditures as that is an area that did not meet expectations. Our capital expenditures were approximately $341 million in 2012 versus a budget of $298 million.

Contributing to this overspend, our unbudgeted expenditures of approximately $23 million, which includes participation late in the year in non-operated Niobrara "B" Bench horizontal wells that had a marginal impact on 2012 production, along with micro-seismic and acreage acquisitions. Approximately $15 million was due to operational modifications made as we transition rapidly from a vertical to a horizontal development program in the Wattenberg during the third quarter.

This includes fracture stimulation improvements on our horizontal wells and increased costs due to reduced rig efficiency caused by the transition from vertical to horizontal drilling. The remaining $5 million is associated with drilling and completion issues on four of our 32 horizontal wells drilled in 2012. Key learnings have been incorporated into our drilling and completion procedures at any recurring costs associated with our experiences in 2012 are included in our 2013 capital budget.

With that, I’ll turn the call over to Gary to discuss the outstanding operational results we achieved in 2012.

Gary A. Grove

Thanks, Mike. As you mentioned, it was a very positive quarter and I’m pleased to report on some of the exciting results we achieved on our test wells in the Wartenberg. But before I get to the quarter and year-end results and catalyst well update, let me first review our 2012 proved reserves, which showed an increase of 9.3 million Boe to a total of 53.0 million Boe replacing 371% of 2012 production. Our total proved reserves grew 21% and the PDP component grew by 47%. Proved developed reserves were 45% up from 39% a year ago. The proved reserve mix was 57% crude oil, 6% NGLs, 25% wet gas, and 12% dry natural gas.

Our Wattenberg drilling program for 2012 resulted in net reserve additions of 12.8 million Boe. This is 95% of the company’s total net reserve additions of 13.4 million Boe, excluding the California divestiture. The Wattenberg reserve additions were primarily due to our focus on horizontal drilling in the Niobrara. Our horizontal Niobrara “B” proved reserves increased by 236% during the year. The California divestiture accounted for a reduction of 0.7 million Boe.

Moving on to operational performance, let’s begin in the Rocky Mountain region where we averaged production of approximately 6,549 Boe per day, or 55% of company sales volumes during the fourth quarter and 4,568 Boe per day, or 49% of total sales volumes for the full year. Our production was split 75% to crude oil and 25% to rich natural gas and during the quarter approximately 56% of our volumes came from horizontal wells.

Also, I should point out that all of our oil is sold as crude oil at the wellhead with no associated condensate. At mid-year, the company made a decision to augment the 2012 budget to drill some catalyst horizontal wells and also begin to transition to a horizontal development program in the Wattenberg. The result was to add 12 additional horizontal wells and removed 20 vertical wells effectively ending our vertical development for 2012. Three of the new horizontal wells were drilled to test the Niobrara "C" Bench and Codell along with a "B" Bench extended reach lateral test.

Overall, during 2012, we drilled 32 standard 4,000 foot horizontal Niobrara "B" Bench wells for an average total well cost of $4.5 million. The average cost include additional data collection on a few of the 32 wells to increase our knowledge of the reservoir. We also experienced drilling problems on four wells, which had a negative impact on our total average.

Our average 30-day production rate for all Niobrara "B" wells to-date is 503 Boe per day at 76% crude oil, with our last 12 wells averaging approximately 537 Boe per day. Our 60-day rates also continue to improve for total program average of 405 Boe per day with our last eight wells averaging 476 Boe per day as a result of recent operational improvement.

We are also very pleased with our catalyst wells that I mentioned earlier. The Niobrara "C" Bench achieved a 30-day IP rate 444 Boe per day at 79% crude oil while the Niobrara "B" Bench extended reach lateral produced an average of 795 Boe per day over its first 30 days at 76% crude oil. We successfully drilled the wells at total lateral length of approximately 9,600 feet, but did encounter problems running the liner and only completed approximately 8,600 feet of the lateral length.

As a result of the lower lateral lengths completed, we believe we lost as much of the 100 Boe per day of every production. As reported in January, we drilled the horizontal well in the Codell formation achieving a 30-day average rate of 370 Boe per day at 81% crude oil.

Our average 60-day rate showed almost noted claim averaging 367 Boe per day. This was the first well, where we installed gas lifter in the flow back period, and we believe that has contributed to the improved 60-day production profile.

Finally, we continue in active leasing and acquisition program in the Wartenberg Field near our core area and recently acquired 960 net acres for approximately $1,250 per acre. Initially, this will add additional Niobrara "B" location and is also perspective for Niobrara "C" Bench locations.

Moving on to the Mid-Continent region, fourth quarter sales volumes averaged 5,402 Boe per day, a 67% increase over fourth quarter of 2011. Sales volumes for the full year averaged 4,689 Boe per day, a 90% increase over 2011. At mid-year, the company decided to drill seven additional Cotton Valley vertical wells, three five-acre space wells in Dorcheat field and four wells at McKamie-Patton. While we do not yet have 30-day results on the down spacing tests, early production results are encouraging. In McKamie-Patton, the initial 30-day average rate for the four wells was 137 barrels of oil per day comfortably exceeding our forecast of 71 barrels per day.

In total, we drilled 42 operated vertical wells and completed 80 upper Cotton Valley [pay ads] during 2012. The Dorcheat plant expansion continued in the fourth quarter to include another 12.5 million cubic feet per day of capacity. The plant recently became operational in February bringing our total capacity in the area to 40 million cubic feet per day.

Before I hand the call back over to Mike, I also want to touch briefly on operating and G&A costs for the quarter and full year. LOE for the fourth quarter was $7.81 per Boe, down from $13.20 per Boe in the fourth quarter of 2011. For 2011, LOE averaged $9.58 per Boe, 29% less than the previous year.

The decrease in per unit LOE is due primarily to increasing production volumes from the Wattenberg horizontals, which have the lowest per unit cost in the company. In addition, the disposition of some of our higher LOE California properties further reduced per unit LOE costs.

G&A for the fourth quarter was $8.15 per Boe and $9.13 per Boe for full-year 2012, a 17% improvement over 2011. We feel good about our staffing levels at this time as many of our added personnel were hired in 2012 to prepare for the 2013 program. As we communicated in our guidance earlier this year, we expect per unit G&A costs to continue a modest decline.

With that, I’d like to turn the call back over to Mike for final comments.

Michael R. Starzer

Okay, thanks, Gary. I wanted to conclude our call with a few thoughts about 2013, and how we view things going forward. I mentioned earlier in the call that we are well positioned to continue the success we achieved last year and the 2013 guidance we published in early January reflects that.

Based on our 2012 sales volumes, our guidance represents a 62% increase to the midpoint of the range, or 15,250 Boe per day again placing our growth rate in the top tier among our peer companies. In addition, the substantial oil and liquids component of our production mix affords us continued strong cash margins, particularly in this current price environment.

We are running four rigs in the Wattenberg, drilling 72 horizontal wells in 2013, including 56 Niobrara "B" Bench laterals, four Niobrara "C" Bench wells and four Codell wells, all standard 4,000 foot laterals. We are also going to drill two more extended reach laterals and six wells testing the 40-acre spacing in the Niobrara "B" Bench.

We are excited and believe that this program will lead Bonanza Creek into its next phase of growth and provide increased visibility on our development potential.

We will also continue our work in our Arkansas drilling 36 Cotton Valley wells and further testing down spacing potential in the Dorcheat-Macedonia field, which has the potential to significantly increase our development inventory in Arkansas.

We’re looking forward to communicating these results to you as they come in throughout the year. I want to remind everyone of our next event, our first Analyst and Investor Day on April 11 in Denver. We invite you to join us as we present our current analysis of the company’s resource potential with an emphasis on the Wattenberg Field.

We will update our potential inventory count to contemplate the impact of down spacing, the development of the Niobrara "C" Bench and the Codell formation, along with continued development of the Niobrara "B" Bench. This event will be webcast and can be viewed from our website for those not able to make the trip to Denver.

In summary, we intend to continue to execute on the plan, hit our targets, and aggressively develop our attractive asset base. We learned a lot about the Niobrara in 2012. And for 2013, I think we will learn even more about how to best develop the full resource potential of the Wattenberg Field.

Thank you all for being a part of the very successful 2012 and joining us as we embark on 2013.

With that, it’s time to open the call for any questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from the line of David Deckelbaum of KeyBanc. Your line is now live. Please proceed.

David A. Deckelbaum – KeyBanc Capital Markets

Good morning, everyone. Thank you for taking my call.

Michael R. Starzer

Good morning, David.

David A. Deckelbaum – KeyBanc Capital Markets

I just wanted to go back to the fourth quarter CapEx, so I understand there is no change, or there was no overage on an individual well cost basis as you went from vertical to horizontal relative to what you budgeted, or could you highlight a little bit more the inefficiencies that led to the dollar amount associated with just going from vertical to horizontal that you hadn’t budgeted?

Gary A. Grove

Yeah, David, this is Gary. A couple of things; we are guiding a little bit lower this year, 4.2 million from what we expect to spend in terms of what we spent last year, I’d say on average of 4.5 million. Throughout the year, we’ve obviously seen some things happened that we changed – that kind of drove that cost higher for the full year 2012. some of those things were some equipment issues that we found that we’ve changed out and has been progressively better through year, some pre-planning changes that we’ll do for next year and also quite frankly, we’ve seen some of our bids come in a little bit less than we had on the fracking side for 2012 into 2013.

As far as the transition from vertical to horizontal program and some of those rig inefficiencies is and there’s also some structural things that happened to at the surface. Quite frankly, making that transition, we’re looking to bring out a different rig to drill horizontally and add that extra rig versus the vertical rig that we had going at the time. And so, by doing that, we actually drilled some of our vertical wells at the end with that larger rig and we drove our cost up a little bit more than we had planned as we were shifting from that program again, vertically on those last 10 or so wells into the horizontal program.

The other side of that though is we had originally planned to drill more verticals as we talked about and we put in some facilities that would take more than one well, as you well know out there, we don’t just drill one vertical well and one particular production system. That being said, some of those cost in, therefore needed to be spread across the smaller number of vertical wells. And again, that led to some, just at the moment in that point of time, additional facilities that we had planned to spread the cost over additional vertical wells.

David A. Deckelbaum – KeyBanc Capital Markets

Okay. So it’s fair to say that all of those factors have already been incorporated and so that $394 million CapEx guidance for 2013...

Gary A. Grove

Make sure that David, along with everything else that we see going forward. We’ve got it fully analyzed with all of those key learnings from last year. And fully incorporated into what we expect to spend for next year. Along those same lines, I know we guided to about $8 million and still continue to do that for the extended reach lateral, and the cost for that particular well last year came in just a little under $7.5 million about $7.4 million. So we do see positive events as well.

David A. Deckelbaum – KeyBanc Capital Markets

Great. And last one if I may, just on the extended reach lateral, how do you compare, what you’ve seen at least on the portion of the lateral that you are able to complete versus the four wells that Noble has been able to bring online. How do you sort of reconcile the 30-day rate with type curves and the incentive to go from more of a shorter lateral to a longer lateral? And I guess to add on to that, how quickly could you give convert the program to using the extended lateral methodology more frequently?

Gary A. Grove

The first question, we do compare to those four wells. We feel like we are right in line with what we see from the results to-date that we can see from the public information. Based on the number of stages the we put into the lateral, it’s kind of how we look to determine, like I said, we think we might have been able to add 100 more Boe per day if we’re be able to get in those three to four extra stages.

That being said overall, we feel like we are tracking right in line with what we see from the four Noble wells, we also know it’s early. And we also know that we and they employ a kind of a reduced flow back period early on as we’ve all talked about we hold the wells back a little bit especially the extended reach wells. So we’re very optimistic for obviously going forward, however again it is early? So to address your second question about how nimble we are, we do have contingency plans set up internally already through the first portion of the year we decide that we want to maybe drill some further extended reach laterals into the latter half of the year. We don’t currently have plans for that and – but when we do, we’ll definitely make that announcement, as we see more production coming from, not only our wells, but also from longer-term on the offset Noble wells as well.

We’re looking into the future, that’s one of the goals from this year is to make some further decisions on what is the best efficient use of lateral lengths to develop this large acreage position that we have out here and quite frankly in the different benches as well.

David A. Deckelbaum – KeyBanc Capital Markets

Great. Thanks, Gary.

Gary A. Grove

Thank you.

Operator

Thank you. Your next question comes from the line of Irene Haas of Wunderlich Securities. Please proceed.

Irene Haas – Wunderlich Securities

Hey, thank you. Question on Bench B, obviously you guys have quite a bit of success and this is looking more predictable as such. And you’re still sticking with your 312,000 barrels a day EUR, could we expect maybe some upward revisions?

Michael R. Starzer

Thanks, Irene. Yes, for now we are sticking with our 312,000 kind of EUR, look at it. We still think, ultimately that EUR will be depicted by more impact of what we see in years two and three as we get more time behind us. We feel like we’re still in the early stages of that curve. We don’t really want to go beyond that. Even though, our IP rates have exceeded what we use for an IP for that curve. That being said, you’ll probably see us be a little slower to change our total EUR forecasts going forward. I guess, we’re comfortable with where we sit today.

Irene Haas – Wunderlich Securities

Great. So similarly, when could we expect sort of some EUR on your various benches and Codell and all that, when would you get comfortable in terms of releasing something that you feel good about?

Michael R. Starzer

I think we’ll be able to shed a little more light in our Analyst Day Presentation as we talked through that. But that being said, we now have one well in the Codell, one well in the sea, and one extended reach lateral on our property, obviously taken into account the offset work that’s being done, that drop, that moves that well count higher. But I would expect we want to see some results from our 2013 program and all of those and then kind of – it’s kind of zero in on what an EUR would look like.

I would comment a couple of things. Our EURs, we feel comfortable about. But again remember, we feel like our oil split is really high. And that then tends to lead us to fill, that if you say, we won’t want to really move that up right now, because we’re seeing such high oil percentage and the returns are so much greater with even a lower EUR amount.

But overall on those catalyst wells, as we go through the year, we’re seeing similar early day production on the “C” Bench well and the Codell well. As what we would have expected, the “C” Bench is kind of in line with our normal “B” Bench wells that we’ve seen out there for sure. The Codell was a little bit lower in rate. But as we mentioned, the 60-day rate was much flatter than we’ve seen historically, and does agree with some of the offset operator Codell wells also.

So we’ll kind of round out a better number for you in the proceeding two to three months, I think on EUR expectations.

Irene Haas – Wunderlich Securities

Great. Thank you.

Operator

Thank you. Your next question comes from Brian Corales of Howard Weil. Please proceed.

Brian Corales – Howard Weil Inc.

Good morning, guys, and congratulations on a very good 2012.

Michael R. Starzer

Thank you, Brian.

Brian Corales – Howard Weil Inc.

Just kind of on the inventory question, I know you’re still experimenting, I wouldn’t say experiment, but testing some of these other zones. Is the “C” Bench, is that perspective throughout your whole 32,000 acres and what about the "A" as well?

Gary A. Grove

Each year it’s Brian to see we feel it’s perspective across the acreage. We’ve got geologic mapping that we do out there and with the 3D seismic in the vertical well control. We feel very good about the prospectivity of the sea across the entire acreage position. The "A" Bench is perspective across the entire acreage position as well. Although, quite frankly, we haven’t looked to go ahead and drill in the "A" Bench wells this year. I believe as you know and everybody knows that, Noble has a couple of "A" Bench test very close to us in their Wells Ranch area in Section 24 and work intend to wait and see what the results look like there, before we go ahead and embark on putting an "A" Bench on our property if you will and maybe the latter part of 2013 or 2014.

That being said, we are also looking vertically through the column to see how we can drain independently between the A, B and "C" Bench and the Codell together.

Brian Corales – Howard Weil Inc.

Okay. And then there was a very good extended lateral well. How much of your acreages can you drill extended laterals? Or is it, I have a pretty contiguous acreage block, I’m just kind of curious on, could we see the majority of wells being drilled with the longer lateral?

Gary A. Grove

We do have a very contiguous acreage block. And that is something that we feel like we can control a lot of, probably as much as, maybe half or little or up three quarters of the future wells we have drilled could kind of enter into that fully controlled extended reach lateral condition. But that being said, I would also like to comment that, even if we only owned a portion of extended reach lateral, we feel like the neighbors that we have out there, like the potential of that as well. And so subsequently, we may drill much less wells, and maybe operate some of those extended reach laterals or where we have a less than position in the acreage, we would be a non-operated partner with someone on the other side to go ahead and employ the extended reach lateral concept.

Brian Corales – Howard Weil Inc.

Thank you. And if I could just do one more, just on the infrastructure side, last summer we saw some, I guess some volumes being pushed out, how does that look going to go into this summer? Has it for Bonanza Creek, I mean are we going to see similar type kind of production curtailments, or has that been already taking care of?

Michael R. Starzer

We fully expect to continue to see high pressures out there on the gas side through the first half of 2013, until DCP installed their next processing plant, which they expect to do in the third quarter. I think right now, the latest we heard is August. And that will increase capacity in an area by 110 million a day. We did see some impacts of that last year although in the 100 to 150 Boe per day range for the second and third quarter, we put that into our guidance forecast for 2013. So we do expect to still see that continue a little bit probably in those same ranges for us, but we feel like we’ve incorporated that into our guidance for 2013.

Brian Corales – Howard Weil Inc.

All right, gotcha. Thank you.

Michael R. Starzer

Thanks, Brian.

Operator

Thank you. Your next question is from the line of Andrew Coleman of Raymond James. Please proceed.

Andrew Coleman – Raymond James

Hi, thanks, Mike and good morning folks.

Michael R. Starzer

Good morning, Andrew.

Andrew Coleman – Raymond James

I was just looking at the 10-K here, on the constant curve there was $400 million spent, which I guess on the spending for the year was $340 million. I guess, what’s the delta for that? Is that the facing of activity or?

Gary A. Grove

I think it’s probably best described in probably three categories Andrew. Mike mentioned that, we had about $23 million of what we would call unbudgeted piece to that, that would mainly fall in the line that we participated in non-operated wells later in the year, and so we hadn’t planned on doing that. We also...

Ryan Zorn

Andrew, are you talking about – are you – this is Ryan, are you talking about acquisitions being involved in that $400 million number for the cost incurred?

Andrew Coleman – Raymond James

Yeah, I was just looking at, if know the – when I look at the income statement – probably the cash flow statement you’ve got around $300 million spent, you’ve got, you guys talked about $340 million, $400 million on the cost incurred,so...

Ryan Zorn

I think your delta is the state land board attrition there.

Andrew Coleman – Raymond James

Yeah, okay.

Michael R. Starzer

$60 million.

Gary A. Grove

I’m sorry Andrew, I misunderstood your question. Thank you.

Andrew Coleman – Raymond James

I’m sorry. I can see that anywhere on the balance sheet as well, I imagine we’ll get some data on that next month at the Analyst Meeting?

Michael R. Starzer

Well, as you know, we are paying that $60 million that stage in over five years, $12 in 2012….

Andrew Coleman – Raymond James

Okay.

Michael R. Starzer

But we will obviously pay that installments over the next four years.

Andrew Coleman – Raymond James

Okay.

Michael R. Starzer

But the entire $60 million or $57 million or so hit our top numbers in total.

Andrew Coleman – Raymond James

Okay, fair enough. And then thinking about the reserve booking side with a lot of your horizontals coming on in the second half of last year, does that I guess slowdown some of the booking potential for 2012, and so I assume we’ll see a acceleration as we look at 2013 numbers here, another year?

Gary A. Grove

Yeah, Andrew, a couple of high point comments and if you wanted anymore detail, Lynn’s with us today and she can talk to that. But I think a couple of things and we’re going to talk a little bit more about that on our Analyst Day as well. Couple of high-level comments, yes, lot of it occurred during the end of the year, so we didn’t book any offsets to like the Codell or the "C" Bench at all. All of our bookings right now are still in Niobrara “B”. We also – our extended reach lateral did not come on until January. So there were no bookings associated with that or any offsets associated with that.

And then lastly, as we started this transition to a horizontal program out in the Wattenberg, we’ve also started reducing and making some revisions taking off some of our PUD locations that were vertical. And so, you’ll see kind of that transition as we move forward, kind of have a little bit of impact on full-year reserve add this year and maybe even into next year as well.

Andrew Coleman – Raymond James

Okay. And thank you for the clarity.

Michael R. Starzer

Thanks, Andrew.

Operator

Thank you. Your next question is from the line of Mike Scialla of Stifel Nicolaus. Please proceed.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Good morning, everybody.

Michael R. Starzer

Good morning, Mike.

Gary A. Grove

Good morning.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

I just wanted to confirm, I know you sell your gas – sell wet gas at the wellhead in Wattenberg. Just wanted to confirm that those 30 and 60-day rates that you quoted were wellhead rates, so there’s no uplift in there for NGLs, is that right?

Gary A. Grove

That is correct.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Okay. And the – based on what you’ve seen, I know you don’t have a lot of data yet, but maybe what you’ve seen between your wells and also some of the offset operators, do you have any feel yet for what kind of vertical communication you might be seeing between the different benches and also between the Codell and the Niobrara?

Gary A. Grove

Well, we think right now the results we’re seeing are consistent, and that’s the nice thing about the area that we’re in is not only the results we have. But our offset neighbors Noble, PDC, Bill Barrett were all seen very similar results in terms of early day rates and tight curves and EURs and those types of things.

I think you’ve hit upon something that we feel is one of the things that we look to understand more during our 2013 campaign as what is that contribution vertically in this column between the A, B, C and the Codell and what ultimately is the right for want of a better term stacking arrangement for the horizontal wells into their particularly benches.

So right now, we’ve done some micro-seismic work. Noble has published a lot of work they’ve done with their fiber optics and their micro-seismic. We’ve done some coring work. They’ve done some coring work obviously and others are doing continued work out there. So it’s a little early to make any strong conclusions. But definitely, we feel like we do see some contribution up and down the three reservoirs in the Niobrara and the Codell.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Okay. And then if I heard you right that 40 acre pilot that you’re doing, that’s going to be “B” Bench only, right? You’re not going to try and stagger them in different horizons?

Michael R. Starzer

That’s correct, yes.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Okay. And then just one last one; did you happen to run any sensitivities on your – you provided a PV-10 in your press release. I’m just wondering if you ran any sensitivities in terms of maybe a higher gas price?

Michael R. Starzer

If you were to run at last year’s pricing, we would have added a little over $100 million in PV-10 value. If you ran this year’s reserves, at last year’s pricing and predominately it is the gas movement there. Mike, you’re right. So that’s the sensitivity that I get to share with you today.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

That’s helpful. Thank you.

Operator

Thank you. Your next question is from the line of Ryan Oatman of SunTrust. Please proceed.

Ryan Oatman – SunTrust Robinson Humphrey

Hi, good morning gentlemen.

Michael R. Starzer

Good morning, Ryan.

Gary A. Grove

Good morning, Ryan.

Ryan Oatman – SunTrust Robinson Humphrey

That Codell test has held up better than the Niobrara test. How much of that is geology versus the gas lift?

Ryan Zorn

We think some decent percentage of it is, the gas lift, because we are obviously augmenting it in a very favorable way with the reservoir conditions. The other thing though there is, we feel like there is a geologic component to it as well. You’re exactly right, because it is the sandstone. It does have better permeability proxy characteristics than the Niobrara well naturally.

So we think that’s a combination of those two. Quite frankly there we’re seeing uplifts in the Niobrara by installation of gas lift also, so we know that we are contributing to that challenging of the decline from the operational improvements we have made.

Michael R. Starzer

Ryan, I might inter checked also that the first 30 days, we had a pretty strong controlled flow back on the well, and we want to make sure that the frac yield is being our first Codell horizontal on our acreage. And when you look at the 60-day results, I think that was a very good decision by our technical team.

Ryan Oatman – SunTrust Robinson Humphrey

Yeah, absolutely that well was certainly held in there. I mean to me just from 30,000 feet, it looks like you should have the higher EUR with that in typical Niobrara “B", is that fare?

Gary A. Grove

I think it’s early. So I don’t want to sound too conservative. But we’re excited about what we’ve seen in the first 60 days performance. But depending on the location, yeah, and depending on the cuts in terms of oil and gas from what we’re seeing there, yeah, we feel like it could compare very favorably to a Niobrara “B” Bench EUR.

Ryan Oatman – SunTrust Robinson Humphrey

Okay, okay. Thank you. And then what differences do you see in results across your acreage position, north to south, east to west, is there a significant variability as you move one direction or the other?

Gary A. Grove

We do see variability across the property. I think a lot of it has to do with the geologic positions that we see out there. Sometimes we won’t counter some faulting, sometimes we will not as much. I think overall, there is some very, very high level general trends based on resistivity. So where we obviously see a less than resistivity out there, we would expect to see may be a little bit less recovery and that’s probably been the major trend.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. Is that on the west side, is that on the east side, north, south, is there any sort of broad color there across the position where you find a gradient one direction or the other?

Michael R. Starzer

Probably the broadest color would be, as we move to the north-east and directly east, I mean really just on the farthest east of side of our properties, we see that resistivity dropping off and that’s where we would expect to see may be some lower ultimately EURs. We also generally in that direction may see higher oil cuts though too. So that’s kind of the broad color mix there.

Ryan Oatman – SunTrust Robinson Humphrey

Okay, appreciate that. And then one final one if I may, there has been questions around last year and now that 2013 capital program, I guess looking on what you guys have proved up and accomplished in a relatively short period of time with these additional benches, how could 2014 look given the company’s clean balance sheet, how comfortable and how fast could the company go in 2014?

Ryan Zorn

This is Ryan. Obviously we’re just going to really govern ourselves on keeping the best-in-class balance sheet and given ourselves ample liquidity, headroom we feel like there’s still a lot to learn as you point out. As we move to this year on just the configuration of laterals, the sequencing of laterals, and how these benches behave with one another. So I think as we move to the year, we will have a clear picture on that. But I think we are not sure that we’ve got a strong focus on the balance sheet and maintaining that what we believe the competitive advantage there.

Ryan Oatman – SunTrust Robinson Humphrey

Okay very good, I appreciate it.

Ryan Zorn

Thanks Brian.

Operator

Thank you. Your next question comes from the line of Drew Venker of Morgan Stanley. Please proceed.

Andrew Venker – Morgan Stanley

Good morning, guys.

Gary A. Grove

Good morning, Andrew.

Andrew Venker – Morgan Stanley

Just wondering, did you see the opportunity for anymore acreage bolt-ons in the Wattenberg and surrounding areas; any state lease sales to pick up, size in terms of acreage.

Ryan Zorn

Drew, I think the one that we’ve been chasing for quite a while that we picked up in early August last year, to see that blocky of acreage right around us is difficult. There aren’t that many opportunities available. Everything that does come available, we chase. But I think what you’ll see are more predictable will be small bolt-ons that we’ll continue to add like we mentioned earlier on the call. There’s definitely a scarcity of product of the Niobrara within the Wattenberg because a lot of folks have been there operating for many years, and it’s fairly cored up.

Andrew Venker – Morgan Stanley

All right. And just unrelated, but can you offer anymore color on service cost trend?

Gary A. Grove

Service cost trends have been relatively flat that we’re seeing. We’ve secured our services on rigs and profit and we’re securing a lot of supply for the Wattenberg as well this year. We did see as I mentioned earlier some of the fracking services going down a little bit year-over-year, in terms of their bids. But overall, we’re kind of considering kind of a flat scenario out there in the vendor community, not only in the Wattenberg Field, but also down in Arkansas as well.

Andrew Venker – Morgan Stanley

Okay, thanks.

Gary A. Grove

Thanks Drew.

Operator

Thank you. Your next question comes from the line of David Tameron of Wells Fargo. Please proceed.

David Tameron – Wells Fargo

Hi, good morning. Just can I get back to what you’re saying about the Codell and the Niobrara and some of the gas? Are you guys putting on pumps, are you talking artificial gas or are you talking – is that what you’re referring to?

Michael R. Starzer

Yeah David, it is. We’ve changed and so probably the best way to describe that is just tell you exactly what we do today.

David Tameron – Wells Fargo

Okay.

Gary A. Grove

So we’ll go ahead and drill the well, drill a lateral length. We’ll go ahead and run the liner. And it’s a – pack and sleeve combination. And then we’ll go ahead and go ahead and frac the well and all the stages that we’ve put in the horizontal. And then we will go ahead and before we flow it back at all, we’ll go ahead and clean it out, with coiled tubing clean everything out. And the next thing we’ll do, we’ll go ahead and run in with tubing and gas lift mandrels, and packer.

Then we will start the flow back of the well bore and we will do it under controlled conditions to allow the fracs to heal, to allow us to make sure that we’re taking care of the near well bore areas, especially. And then as that well continues to flow back and starts cutting oil and gas and starts lifting itself obviously, under natural conditions and it will get to where it’s flowing naturally.

As it starts to then not flow naturally anymore, at that point in time, we start to assist with the gas lift that we had, those mandrels that we had installed initially. And initially it would be very small just to aid it and then ultimately going to full time gas lift over the first and depending on the well and depending on where it’s at in its natural strength, anywhere from 30 days to maybe as 120 days to where we convert over to full gas lift. Ultimately down the road, we may in a two to three year timeframe, take that off and put it on rod pump or some other form of artificial lift, whatever we feel is most efficient at that time.

David Tameron – Wells Fargo

Okay. So you’re putting on within the first, call it 20days, 30days; that is when you officially put it on pump?

Gary A. Grove

Yeah, maybe depending on the well and how it’s flowing back and the conditions that it will has, and if we do, again depending on the well, it maybe just a small amount initially, obviously then increasing to where we’re fully assisting with gas lift.

David Tameron – Wells Fargo

Okay, and do you do anything different between the Codell and Niobrara? I’m trying to figure out why, I guess you guys are trying to figure out more than we have. Why the Codell seems to be hanging in better for some operators as far as that shallow decline rate, I’m trying to figure out is because the wells are being chock back before they put on or if there is some being done different or you’re fracking into the Niobrara? Do you guys have any comment on that and contemptibly do anything different between the Codell and Niobrara when you complete them?

Michael R. Starzer

A couple of things, we’re not really doing much differently between the two in terms of how our fracs are stimulating them, I mean some minor things, maybe some minor fluid changes just depending on our experience out there in the area. Pumping rates are pretty similar. But that being said, I think you got to remember too that the Codell as the sandstone it has better, again reservoir parameters.

David Tameron – Wells Fargo

Yeah.

Michael R. Starzer

We’ve seen the Niobrara naturally and that’s definitely having an impact on that. I wouldn’t say so much that we’re fracking up into the Niobrara or other zones would be a leading contributor at this point in time. Not saying that it couldn’t be, it just saying I don’t think the information that we have right now would lead us in that direction. Overall, yeah, we are encouraged by the less in decline. I’ve contributed to partially the geologic nature of the Codell and then partially to the operational conditions that are being employed on those wells by us and our offset neighbors.

David Tameron – Wells Fargo

Okay. And then final question, maybe you’ve covered this I apologize if you have, because the four wells that you had issues with, can you talk about technical, geological? Can you just talk about what happen if there is any theme among the four?

Michael R. Starzer

Sure, I think as far as the theme, I think probably the biggest theme was more geological than anything else. And I think it helped us understand a little bit better the use of the seismic, the 3D seismic that we have in hand in all the preplanning that we’re doing.

We obviously have a more rigorous preplanning screen on everything we’re doing going forward based on the learnings that we had from last year. That’s probably the two biggest, two of the four wells have that problem where we had to pullback in and basically re-drill the lateral, because we got in a position we didn’t want to be in. We did have a standard mechanical problem on one of them, we got stuck and got unstuck pretty normal got some drill pipe stuck on it.

David Tameron – Wells Fargo

Okay.

Gary A. Grove

Those things may continue to happen obviously we don’t want those happen, but I can sit here today and tell you those won’t happen again, because that’s the nature of our business.

David Tameron – Wells Fargo

Yes, all right. Wells, thanks for all the color. I appreciate it.

Michael R. Starzer

You’re welcome. Thank you.

Operator

Thank you. Your next question comes from the line of Mark Lear of Credit Suisse. Please proceed.

Mark Lear – Credit Suisse

Hey, good morning.

Michael R. Starzer

Hi, Mark.

Mark Lear – Credit Suisse

Just thinking about how you guys are going to spend allocate capital in the Wattenberg next year, do you guys have an idea how you put activity between Codell B and C?

Gary A. Grove

Yeah, absolutely, we’re going to drill other 72 wells we have plan for next year. 56 of them if you will are going to kind of be just that standard 4,000 foot lateral on the Niobrara "B" Bench, and then six we’re going to use that are going to be 4,000 foot lateral as well in the "B" Bench, but we’re going to use those to test 40-acre down spacing, and have already actually got a couple of those drilled to-date. And then two more will be in the "B" Bench, but there will be extended reach laterals. As far as the "C" Bench in the Codell goes, we’re going to put four additional horizontal wells in each of those zones in 2013 as well.

Mark Lear – Credit Suisse

Gotcha. And when you think you will have data on 40 acres?

Gary A. Grove

We follow on 40 acres. We are actually – I believe the first well we completed already, I would like to tell you we would maybe some initial information by the time of the Analyst Meeting on April 11, but I’m thinking we probably will not have a 30-day rate on that, we maybe or we will add some additional color at that time. So probably look for something after that if you will really truly on the 40-acre spacing that we’ve seen in 2013 so far.

Mark Lear – Credit Suisse

Okay. And then you talked a little bit about some mechanical issues you had. Is there anything, whether it’s bolting or something else that adds any sort of additional mechanical risk to going to these longer laterals?

Ryan Zorn

Not necessarily from the mechanical standpoint, I think it more just knows where we want to place the lateral during the drilling portion of the program. So it’s not like it’s, we’re going to have a mechanical failure by going through a certain area. I think from what we’ve learned, we may try to avoid things or approach it differently as you would do in any condition. But not really, nothing – I wouldn’t say that there’s an additional layer of mechanical risk associated with that at this point in time.

Michael R. Starzer

No Mark, definitely what we’ve learned is it’s important to have 3D Seismic. That’s why we’ve got most of acreage with 3D Seismic. So that it resolves the faulting very clearly for us. And so we go into placing the well trajectory in a know area with the use of that 3D Seismic.

Mark Lear – Credit Suisse

Right; I know you have seismic on the extension, but do you have seismic on the Wattenberg?

Gary A. Grove

Yeah, we have seismic covering pretty substantially most of our acreage. And what we don’t have, we’re acquiring this year, I believe to finish that out. And so that’s definitely a key component of our pre-planning process.

Mark Lear – Credit Suisse

Understood; thank you very much.

Michael R. Starzer

Thank, Mark.

Operator

Thank you. Your next question comes from the line of Chad Mabry of KLR Group. Please proceed.

Chad Mabry – KLR Group, LLC

Thanks, good morning.

Michael R. Starzer

Good morning, Chad.

Chad Mabry – KLR Group, LLC

Had a question on the Mid-Continent where you actually, I noticed in your Q4 production; saw another sizable increase from Q3. Was most of that growth driven by expansions to your processing facility? And then what are you expectations for growth from the Cotton Valley going forward this year?

Gary A. Grove

Yeah Chad, I apologize. I couldn’t quite hear the first part of that question, would you mind repeating that please?

Chad Mabry – KLR Group, LLC

Yeah, now, of course, I just noticed that your Q4 production growth over Q3 was – just curious what was driving that if that was mostly driven by expansions to your processing facility?

Gary A. Grove

No, at that time we brought the processing, the additional capacity on in February of this year. So we were still working under the conditions that we had by the plants that we had in place at the time. I think we saw a nice increase, because we just continue to work in our program. We saw – we drilled some of those McKamie-Patton wells as I talked about in the fourth quarter and they came on line. And then the other thing that we do is, we do a lot of PDNP work as we were able to go ahead and increase some of that PDNP work, it’s not a lot of capital driven necessarily. But when we hit some of those more prolific Cotton Valley zones in the shallower part of the well bores, they can have a definite impact on our production.

Chad Mabry – KLR Group, LLC

Okay. And then do you expect to grow that production in Arkansas a year later?

Gary A. Grove

We do, sorry about that, I remember the second part of the question. I would say that overall for 2013, you would expect to see a 10% growth rate down in the Arkansas area based on the capital of one point down there.

Chad Mabry – KLR Group, LLC

Okay great. And just one quick follow-up on that, it looks like some very encouraging results in McKamie-Patton, any plans to increase some, or I guess the version CapEx seem to drill this year. And then, maybe how much outside potential could that open out for you?

Gary A. Grove

Yeah it’s not quite as large as Dorcheat-Macedonia field and we’re – that’s one of the things that we are currently looking as what’s the increased opportunity there at McKamie-Patton. It is a referenced though, one thing I want to point out there is that, we do show a lower expectation for those wells, but they were 100% crude oil. So there is no gas associated with that rate at McKamie Patton. So when we’re showing you that the wells made a $130 plus in rate that’s all oil.

And so yes, we’re encouraged by that. As far as outside opportunity, we haven’t put those numbers together and haven’t put them out there publicly yet, it’s something that we’re looking at. We maybe able to share some light on that in our Analysts meeting, but probably a little bit after that as we continue to look at, how much production out there at McKamie.

Chad Mabry – KLR Group, LLC

Okay.

Gary A. Grove

What we essentially did is, we took some of the things that we’re doing at Dorcheat in terms of the pinpoint fracturing and moved it over to the McKamie Patton field that just to fill there and we’ve had good results as you noted today, and we’re excited about it.

Chad Mabry – KLR Group, LLC

I appreciate it. Thank you.

Michael R. Starzer

You’re welcome.

Operator

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

Michael Hall – Heikkinen Energy Advisors

Thanks. Good morning, everyone.

Michael R. Starzer

Good morning, Michael.

Gary A. Grove

Good morning.

Michael Hall – Heikkinen Energy Advisors

Just I guess trying to get a – in the Wattenberg, just trying to get a better feel on kind of where you’re at in terms of cycle times and how you’re developing your acreage block currently? I mean do you expect all those wells drilled to be put on sales during 2013? And then how much of your for drilling would you say is targeting sweet spots that have been identified with the last year’s program versus still kind of getting to know the acreage if you will?

Gary A. Grove

Cycle times, I would say that we drilled spud to spud, 12 to 15-day range. We’ve been done better than that and obviously depending on how the well goes maybe a little bit to the upper end of that range. But overall, I know without the concept of pad drilling, which we’re doing a little bit this year, we averaged about 45 days spud to first production.

Michael Hall – Heikkinen Energy Advisors

Okay.

Gary A. Grove

On the – lot of wells out there. And what was the second part of your question? I apologize.

Michael Hall – Heikkinen Energy Advisors

Yeah, I mean it’s somewhat related to that. So I guess if you’re not doing a whole lot on real pad-type development, then is this fair to say that the wells aren’t necessarily targeting identified sweet spots as opposed to really delineating the acreage?

Gary A. Grove

Yeah, that’s very true. And we’re not so much as delineating the acreage. We feel like we did that in 2012 quite frankly. But we’re continuing to drill off the acreage if you will, if that’s fair. I think one of the things we’re doing is we’re looking to go to that pad concept more and more into the future. But at the same time we do want to keep an eye towards our reserve growth as well. And by doing that we’re currently sticking with the convention or did that at the end of this last year, which is the once offset rule.

And so by doing that, if you were to put everything in one particular section at this point in time, we’d show great production growth, but maybe not corresponding reserve growth and we want to make sure that we’re kind of accurately portraying that as well. Now, once we’ve felt very comfortable about that and we’re talking about cost reduction as well, we’ll move to more of the pad concept in total.

Michael Hall – Heikkinen Energy Advisors

And how long do you think about that kind of transition period, if you will, running. Is that a couple year process, few years?

Gary A. Grove

Yeah, I’d say, yeah, one to two years or something like that.

Michael Hall – Heikkinen Energy Advisors

Okay. I think that helps. Thanks very much.

Michael R. Starzer

You’re welcome.

Operator

Thank you. Your next question is from Michael Scialla of Stifel. Please proceed.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Yeah, just had one follow-up, Mike in the past, you’ve talked about your desire to do acquisitions. Just wondering if you can talk about from a high level, what kind of packages you might be looking at or they well established plays or are you looking at doing something more on a grasp roots levels?

Michael R. Starzer

You bet, Mike. In know when you look at or history, we’ve been very successful at growing both through the drill bid as well as through acquisitions. And I think that’s important for our company to keep a balanced look. Now, we still look at a tremendous amount of opportunities and probably the best way to describe it is, it will be somewhere to what we acquired in August from the State Land Board, that will be very predictable. Appealed to our strengths, horizontal drilling and multistage frac, definitely fractured technology within the Bonanza Creek is a core competency. So there will be types of opportunities like that.

Now as you know Mike, we’ve got such a fantastic organic growth runway that just continues to expand as we do more work in Wattenberg. And so that’s where our top priority is to make sure we fully delineate and expand and develop our Wattenberg acreage. Any transaction that we make would have to compete with that organic profile that we have.

Michael Scialla – Stifel, Nicolaus & Co., Inc.

Great, thank you.

Michael R. Starzer

You’re welcome.

Operator

Thank you. Your next question is from Ryan Oatman of SunTrust.

Ryan Oatman – SunTrust Robinson Humphrey

Hi guys. Just to follow up here on the Arkansas property; can you walk us through the location count by field and help us understand how that figure could move higher or lower with success? Is that five acre down spacing is that McKamie-Patton; just a little bit more color there?

Gary A. Grove

Sure. At the end of the year 2012, we had – at both locations we had 120 gross, 99.9 net in the Cotton Valley, in the Dorcheat-Macedonia field at 10 acre spacing. We only had two locations booked. We only had two locations booked at McKamie-Patton at the end of the year. So those are the remaining – and they’re both 100% wells. So those are the kind of current state of their fare if you will, in both Dorcheat and McKamie-Patton. I think what we’re going to add is some color around what the potential is in the five acre spacing at our Analyst Day presentation. So we haven’t released any of that information in the same thing on the McKamie-Patton at this point in time, although McKamie-Patton again as I mentioned earlier is definitely a smaller sister field.

Ryan Oatman – SunTrust Robinson Humphrey

Okay, thanks for that I will stay tuned at the Analyst Day.

Michael R. Starzer

Thank you.

Gary A. Grove

Great.

Operator

Thank you. Your next question comes from the line of Nathan Churchill of Societe Generale. Please proceed.

Nathan Churchill – Societe Generale

Good evening gentlemen. Just on the learning curve side on Niobrara, I’m wondering if you can help us appreciate how far long you think you’ve moved along that curve particularly with well placement, frac stages, et cetera. And within that if you are able to glean anything from how the non-op wells that you’re participating in are being designed?

Michael R. Starzer

Obviously, we feel like we are pretty far-up that learning curve in a lot of ways. And then we obviously know – feel like we know everything. And so we’re always I think the key thing we talk about internally is we’re never satisfied, right. So looking forward, we feel pretty good about well-placement, we feel pretty good about how many stages we’re putting in a lateral, in terms of the communication although we’re obviously always testing that process if you will, both on our technical modeling and in fracs as out in the field.

As far as the information from the non-operated wells, those wells along with all of the other wells, even though we don’t have ownership in, we incorporate all of that information into our decision making process going forward. So we have some great neighbors, they are very smart folks, they have some great ideas and some of those have returned great results, and we have been able to use that information to show those same good results on our property. At the same time some things that we have done, they will take and use as well and apply that to their areas of as it’s very standard out here. So I don’t really want to try to put a number on it, how far we’re up in that learning curve because quite frankly, the next time we’ll find something else out and like we said, we’re never satisfied. But it’s definitely – we feel pretty high up along that curve in what we’re doing today.

Nathan Churchill – Societe Generale

Okay, that’s helpful. And on the borrowing base, when is the next revisit of that, the date?

Michael R. Starzer

Yeah, so we’ll be doing that in the next month or so.

Nathan Churchill – Societe Generale

Okay. Great, that’s all for me. Thank you.

Michael R. Starzer

Great, thank you.

Operator

Thank you. There are no further questions. So ladies and gentlemen, I would like to thank you for joining today’s conference. This concludes the presentation and you may now disconnect. Good day.

Michael R. Starzer

Thank you, Rachel. Good day.

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