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Kodiak Oil & Gas Corp. (NYSE:KOG)

Q3 2012 Earnings Conference Call

November 02, 2012 11:00 a.m. ET

Executives

Lynn Peterson – Chairman & CEO

James Catlin – EVP Business Development

Jimmy Henderson – CFO

Russ Cunningham – EVP Exploration

Analysts

Brian Corales – Howard Weil

William Butler – Stephens

Dan McSpirit – BMO Capital Markets

David Tameron – Wells Fargo

Jason Wangler – Wunderlich Securities

Tom Bishop – DI Research

Eli Kantor – IBERIA Capital

Operator

Good morning. My name is Christie and I’ll be your conference operator today. I would like to welcome everyone to the Kodiak Oil & Gas Corp., Third Quarter 2012 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. (Operator Instructions)

Please be advised that our remarks today including answers to your questions includes statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include among others matters that we have described in our financial and operating results, news release issued yesterday and in our filings with the Securities and Exchange Commission.

We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology, and environmental and regulatory compliance. Our drilling schedules, capital plans, and other factors may cause our results to differ materially.

I would now like to turn the call over to Lynn Peterson, Kodiak’s Chairman and CEO for today’s prepared remarks.

Lynn Peterson

Thanks, Christie, and good morning everyone. Before we begin, let me introduce the members of our management team that are on the call today, James Catlin, Jimmy Henderson, and Russ Cunningham. Russ Branting is not available today.

As has become our custom, we are going to give some brief comments on our quarter, we’ll give some color into the upcoming quarters and then we’ll then turn it over to the Q&A session. We would ask that you please reference the news release and our filing on Form 10-Q, both of which were made available last evening for further details and full disclosure of the topics we are discussing today.

Last evening, we reported clean earnings per share of $0.13 per share, which is in line with the consensus expectations FOR Q3, 2012. We also reported adjusted EBITDA of $89 million, driven by oil and gas sales of $112 million. A week before, we reported our third quarter average daily sales volumes of nearly 16,000 BOE per day, which represents 25% growth from the second quarter of 2012 of 12,700 BOE per day and a 50% growth from the first quarter of 2012 on volumes at 10,600 BOE per day.

We remain oil weighted with an 86% crude oil reserve mix. When we look at the income statement, the oil value comprises 95% of our revenues through the first nine months. Gas pipelines and gas plants continue to be put in place and we expect the total gas sales to improve with time.

Another important development over the past few weeks concerns our expanding borrowing base, which as a result of a semiannual redetermination. Kodiak and its lenders entered into an amendment, which increases the company’s borrowing base to $450 million from the previous $375 million. At the present time, the company has not started to increase the aggregate electric commitment on the revolver from the current amount of $375 million. The revolver is an important source of balance sheet flexibility and liquidity for Kodiak as we continue on our growth trajectory.

I’d now like to turn to our drilling and completion activities. We will be operating seven rigs throughout the balance of 2012 as we are just releasing our eighth rig this weekend. We intend to keep the seven operated rigs as we move into 2013. All of the rigs have (inaudible) packages making their mobility a real asset for our pad drilling.

We continue to make strides in bringing down our drilling days. Our average drilling days from spud to rig release have been reduced to approximately 20 days to 25 days. We have certain rigs regionally that were released in less than 20 days. This compares the last year drilling times that averaged nearly 35 days, as a result we feel that we will drill more wells with our current seven rig count in 2013 than we did with eight in 2012.

On the completion side, we have employed a second full-time completion crew since mid-October. This additional crew was always in our budget as we got in a seventh and eighth rig in mid-year and each of those rigs are coming off multi-well pads. The two crews are working efficiently at this time and the number of days to complete wells continues to improve. We continue to be quite satisfied with the use of cemented liners and have not encountered any completion issues since initiating their use.

We have had great success utilizing zipper fracs, which is the process from which we have two or more well bores being completed from one pad at the same time and you simply alternate between the wire lining and perforating one well, where your fracs are stimulating another well bore. This process saves a lot of downtime and allows us to complete five wells to six wells per month per dedicated crew.

With two completion crews for the balance of 2012, we should be able to complete the 26 net wells scheduled in this current quarter. We provided a completion activity update in yesterday’s earnings release as well as a previous news release where we announced initial rates on five new wells and say that flow back work had begun on four additional wells.

We are in the final stages of fracture stimulation work on five additional wells that will be brought on to production in the next couple of weeks. This activity level demonstrates our completion work progress and a road map for our production growth.

We continue to work with our service providers and are seeing the benefit of reduced costs. Today our completed well cost are approximately $10.5 million down from nearly $12 million earlier in 2012. Much of the improved well cost can be attributed to the drilling efficiencies discussed earlier.

We recently renegotiated some third party contracts that should help us drive our completed well cost down below $10 million as we move into 2013. We continue to use a 100% ceramics on wells located in deeper part of the basin in southern Williams, McKenzie, and Dunn Counties.

In areas such as our Wildrose block in northern Williams, our Grizzly area in southwestern McKenzie and our Charging Eagle block in southeastern Dunn County will continue to adjust our completion design to include more sand and resin coated sand as we try to reduce well costs. As these lands are located in areas that have less reservoir pressure, we do not feel it as necessary to go with a 100% ceramics.

I would note that we recently completed one Three Forks well in our Wildrose project area that had initial rate of 1,000 BOE per day. This was the last three wells completed in this area that have been drilled by a prior owner of the acreage that we acquired in January of 2012. The well was stimulated utilizing white sand tailed in with resin coated sand and the well has produced 5,196 barrels of oil during the first 14 days of production or an average of 371 barrels of oil per day. Clearly, these wells do not meet the returns we are achieving on our earlier blocks of acreage to the south. However, we project completed well cost of $7 million to $7.5 million for these wells and we will look to develop this area with additional drilling in 2013.

Let’s now take a more in-depth look at our 2012 capital expenditures or CapEx. For the first three quarters of 2012, we invested $575 million for drilling and completion costs, water disposal well costs, leasehold costs, and infrastructure. We are projecting to invest nearly $175 million in the fourth quarter of 2012, which would put our full year capital spend on pace for $700 million for the entire year. This compares to our original CapEx budget of $585 million and an increase from the $650 million that we have discussed recently.

Our original CapEx budget assumes that a total of 51 net wells would be completed in 2012 comprised of 46 net operated wells and five net non-operated wells. As we look ahead to the fourth quarter of 2012, we expect our full year expenditures to include a total of 66 net completed wells with 55 wells allocated to our operated properties and the remaining 11 net wells to non-operated properties.

Our CapEx increase is primarily attributed to an increase in the total number of wells expected to be drilled and completed in 2012. The increased well count results from the company’s participation in wells drilled by other operators that were not part of our original budget and importantly a greater number of operated wells drilled and completed during the second half of 2012 as a result of operational efficiency gains.

When we further break down our CapEx between our initial budget and our expected year-end investment, we see a discrepancy in the expenses allocated to non-operated wells. The CapEx on non-operated properties is difficult to project since the timing is out of our control. At the time, we developed our initial budget, we allocated capital for five net wells that were projected to be drilled and completed in Dunn County by our AMI partner.

Looking at all of our year, full-year non-operated properties, we have revised our estimates upwards by $75 million to a total of $120 million to project 11 wells, that should be completed in this fiscal year. We anticipate investing approximately $13 million on these non-operated properties in the fourth quarter of 2012.

As the majority of the non-operated properties are located adjacent to or nearby our core acreage blocks, we feel like the quality of lands is excellent. The vast majority of our non-operated wells are being drilled and completed by high-quality operators. While we could choose to go non-consent on wells and suffer the penalty, we believe it is detrimental to the underlying value of Kodiak’s leasehold portfolio.

More and more operators in the basin are getting their operated properties into held by production status. As a result, we anticipate this level of drilling on these non-operated lands would decrease as operators go into more of a development mode.

Turning to our operated properties, we initially estimated that we would complete 46 net wells for the full year. As we look to exit the year, we anticipate this number of completed wells will be somewhere around 55 net wells. The increase from nine wells is directly related to our improvement in drilling time caused largely by more pad drilling and efficiency gains.

As a result of the additional wells, we have increased our CapEx related to our operated properties by nearly $90 million. As we move to the fourth quarter, our goal is to complete approximately 23 net operated wells. We always expect to have (inaudible) wells waiting on completion that would typically run 2 times to 2.5 times the number of rigs.

In summary, we anticipate in investing approximately $162 million from operated properties during the fourth quarter of 2012.

Now, I know all of you are probably asking where is the beat, where is the production? I would hope by now that you’re all comfortable with the quality of wells we’re drilling and the consistency of the production from our wells that we continue to complete. As a result, you should be able to take our remaining wells to complete in the fourth quarter and apply whatever rates you choose and then add that to our production numbers we disclosed on our earlier news release. Again, we are not including non-operated wells in this calculation, we do not know the timing of completions and production.

Much of the production increase at revolver 2012 drilling is going to occur near the end of the year and into the first part of 2013. I know everyone is focused on our 2012 averages and exit rate production numbers and we understand them. However, I would ask that you take a look at the company’s overall growth this year and the production growth of the entire basin that is now over 700,000 barrels of oil per day.

It has been a great year for Kodiak. We are involved in a world-class oil reservoir and the game is still in progress identifying the size of the price. Due to the size of this play, there is a marathon and not a sprint. We are getting a lot of questions regarding our 2013 CapEx budget. We are working through the final quarter and intend to announce our 2013 CapEx budget in December.

Let’s now turn our focus to some of the later innings, and talk about what will be happening in 2013 and where this play could head. A larger part of our early 2013 work will be focused on well bore density and evaluation of additional zones within the Three Forks. We are in the process of recurring two pilot programs to test and increase density.

The initial pilot programs will be tested in our Polar and our Smokey areas. We have commenced drilling operations on a drilling spacing unit in our Smokey project there where we are drilling middle Bakken wells based approximately 800 feet apart. This spacing will allow us to ultimately drill six wells within the spacing drilling unit once we obtain full regulatory approval.

We intend to drill a Three Forks well between the two middle Bakken wells, which will also have approximately seven feet of vertical separation. Our plan is to alternate between the upper Three Forks and the middle Three Forks, commonly referred to as first and second benches and separate these wells approximately 800 feet.

Again that will be something close to 50 feet of vertical separation between the upper and middle Three Forks wells. This well bore spacing will allow for six wells in the Three Forks, but divide it evenly between the upper and middle benches.

We have already drilled the first middle Bakken and the first Three Forks well in this particular DSU and these wells will be completed in the fourth quarter. We have set service spacing for four wells to be drilled of a current pad from which we intend to drill two wells in the middle Bakken and two wells in the Three Forks.

Drilling has already commenced on the first of the four wells, and we are in process of building two additional locations from which we will drill multiple well bores. This project will take us some time and the results will not be known until mid-2013, at the earliest. We believe that this is a mandatory test in order to determine how we effectively drain the reservoirs. We are planning a similar test in our Polar block, where drilling should commence in the first quarter of 2013. The results could be a significant game changer to the entire basin.

With that, we want to thank our listeners for joining us on the call. We always like to thank our shareholders for all your continued support, and I’ll turn it back to Christie, and we’ll be happy to answer questions. Thank you.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Brian Corales with Howard Weil.

Brian Corales – Howard Weil

Looking at the current rig count at seven rigs, is that something that, assuming that’s sustainable for 2013, can we assume like one well per month, is that what you all are kind of running internally?

Lynn Peterson

Yeah, I think with our efficiencies, Brian, certainly if we can knock these wells out around 20 days, 25 days, let’s call it, we would expect to get that type of number per rig.

Brian Corales – Howard Weil

And would you still need two crews for that?

Lynn Peterson

Completion crews?

Brian Corales – Howard Weil

Yes.

Lynn Peterson

We probably don’t need two full completion crews. I think we’re getting a little more efficient as we move along in that direction as well. At the end we’re running two here at the fourth quarter, the second one is not dedicated to us for the full year. But, again, as we look at the services within the basin, I think there is a lot of completion crew that are now available, our relationship with Halliburton continues to be rock solid, and we would expect that they will be available as new.

Brian Corales – Howard Weil

And just one more. On the test of the other facility, I guess, the second bench of Three Forks, is that going to be done close to where Continental has done their testing, can you maybe talk about where that falls in the basin versus where maybe some of the other companies have tested that?

Lynn Peterson

We’re trying to spread this out a little a bit. And we picked our Smokey block as the rocks are a little bit different down there. And so, that particular block would be located or maybe caught nearly 15 miles south of Continental’s test. On the Polar block we would be moving in the other direction, I guess probably 12 miles – 10 to miles 12 miles north.

Brian Corales – Howard Weil

Okay.

Lynn Peterson

We’re trying to do these two areas where we’ve got good well results and where we have a lot of future development here.

Brian Corales – Howard Weil

Okay. Very helpful. Thank you.

Lynn Peterson

Thank you, Brian.

Operator

Your next question comes from the line of William Butler with Stephens.

William Butler – Stephens

Can you all talk a little bit about on the – you talked about on the CapEx side, the non-op, how about on production volumes given the increased activity from the early part of the year, how those tracked in the second and third quarter versus your estimates, and are there some possible sort of delays in terms of paperwork on that that might help towards the end of the year in terms of production?

Lynn Peterson

Hey William, we haven’t really built much in for our non-authorization as far as production. I mean, some of things, I mean, all operators do a lot of different work out here, and a lot of different methods. Over in Dunn County our non-operated properties in that situation, it moved back on to existing pads. They’ve taken four wells down, while they drill additional wells on those pads. So, I mean, you lose some production and then you’re going to get them completely, all come back on, so it’s very difficult or at least we find it very difficult to project. And so, we kind of kept it pretty flat with very, very limited growth until we know what we’re doing. Our focus is on our operated wells.

William Butler – Stephens

And then, I think you’ve got several pads this quarter, there is one that’s a three well to four well pad and one that’s a two well to three well pad, any update on the timing of those?

Lynn Peterson

We’re moving ahead. Like I said, we’re coming off of I think we got a three well pad that we’re finishing up here this weekend probably. A four well pad that should be done in the first of next week. It’s blocking and tackling right now. We’re moving from pad to pad and we’ve got all multiple well pads and we don’t have any single well pads here to complete, everything is on lease too. So, now that’s full speed ahead.

William Butler – Stephens

Okay. And then any update on the natural gas hook-ups?

Lynn Peterson

Again it’s improving every day and our wells are hooked up for the most part to gas sales. It’s plant capacity, it’s new plants coming on, getting all the start-up time figured out. So again, I think we kind of figure around the 60% sales of production right now. We certainly believe that will improve. Do we get to 80% by year-end? I’d like to hope so still.

Again a lot of that’s out of our control. We have to take it as it is. And as we talk numbers, we’re talking barrels of oil here, and when you look at our production come on in fourth quarter, you can do the number just on barrels of oil throughout the gas you get there.

Operator

Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Good morning and thank you for taking my questions. With respect to the increase in CapEx on the non-operated drilling activity to hold your interests on that leasehold, how much acreage are we talking about?

Lynn Peterson

As we have given, say, $25,000 or so, yeah maybe 20% of our acreage there.

Dan McSpirit – BMO Capital Markets

Okay.

Lynn Peterson

Somewhere in that -

Jimmy Henderson

Total range, Dan.

Lynn Peterson

Yeah.

Dan McSpirit – BMO Capital Markets

Okay. And with the -

Jimmy Henderson

What we’re seeing with some operators moving in trying two or three wells on the upper pads so we had some more wells drilled from time to time.

Dan McSpirit – BMO Capital Markets

Got it, okay. And will the opportunity ever present itself to buyout any of that interest and effectively become the operator?

Lynn Peterson

Well, typically on non-operated properties, you have the smallest interest. So again these are with – for the majority of our wells where we we’re at, they’re all the main operators we all know out here. So, everybody is doing the same thing I think.

Dan McSpirit – BMO Capital Markets

Okay, and the last one from me, just turning to northern Williams County, how encouraging are the early results in the context of retaining that leasehold versus maybe monetizing it?

Lynn Peterson

Well, I mean, we actually think we got some pretty wells and we’re quite pleased with the results. Again as I said, if we can get our well costs down to the $7 million, $7.5 million range, we’re seeing the work and we’re laying out drilling program for 2013 and tend to save everything.

Dan McSpirit – BMO Capital Markets

And the drilling complete cost today on the two wells, the middle Bakken and the Three Forks.

Lynn Peterson

Again, you know, as far as our northern block there.

Dan McSpirit – BMO Capital Markets

Right.

Lynn Peterson

We haven’t drilled any wells up there, those wells were all drilled by the previous owner. And so, all we’ve got in is complete these and I think, Jim, correct me, but I believe we used ceramics for one, we used combination of sand and resin on the next two, until we’re tweaking our completions a little bit.

Jimmy Henderson

Right, yeah we used – well, actually we did all three, one was primarily sand, but we’ve done them all differently. And our completion process are significantly less than the wells in the deeper part of the basin, but we can’t give you a drilling and completion cost because we haven’t done a ground floor well yet.

Dan McSpirit – BMO Capital Markets

Got it. Thank you.

Operator

Your next question comes from Welles Fitzpatrick with Johnson Rice.

Unidentified Analyst

This is (inaudible). I have the quick question, you’ve mentioned lower cost from midstream build outs in the basin. Can you give any updates or how we should look at this going forward?

Lynn Peterson

Go ahead, Jimmy.

Jimmy Henderson

Yeah, I think, I assume you’re alluding to water infrastructure that we’re putting into the basin. And we’re starting to see that already, just kind of comparing what you’ve seen in the last couple of quarters compared to this time last year, quite a bit of an improvement despite the increased activity that we’ve had. (Inaudible) expected to at least maintain where we’re at, I think we’ve generally comfortable in that $5.50 to $6 range, but as we get more gathering infrastructure in place, you can see that trending downward as we’re getting off the trucks and using our own gathering lines.

Unidentified Analyst

Okay. That’s great. That’s all from me.

Operator

Your next question comes from Hsulin Peng with Robert W. Baird.

Hsulin Peng – Robert W. Baird

Can you give us your 2013 CapEx number for December, but just in general, is it fair to assume that your 2013 CapEx will be somewhat similar to 2012 level because I think – rig and one completion crew, that will imply a CapEx 2012 will imply additional, some point in 2013.

Lynn Peterson

Yeah. We’ve got cut off there a little at the start Hsulin, but I know you’re trying to get to our 2013 budget, and I think the numbers you laid out, again (inaudible) telling me how many wells we believe we can drill in a year’s time. We intend to have seven rigs. And you can see our well cost, we’ve laid them out there. So, again I believe we start to say giving it out. So at this point I think you can assume something similar and we’ll work towards that and get it out to you here in December.

Hsulin Peng – Robert W. Baird

Okay, now that’s fine. And then second question is, so in the third quarter the difference between your production and sales volume was about 1,300 BOE per day and I understand that’s mainly due to flared gas. So, I was wondering, you (inaudible) 27,000 BOE is production, not sales, but I was wondering at year-end do you think the difference between the production and sales will still be around 1,300 BOE and how does – how would that trend potentially in 2013?

Lynn Peterson

Yeah, again, all those numbers that does get a little bit confusing, Hsulin, I think, and we look at it. We’re looking into oil to get to our numbers and we sell most of our oil that we produce, so those numbers are usually pretty tight.

We can’t tell you exactly what we’re going to sell every month and what these wells are going to produce. So I think you saw – we said we had a production of 19,000 BOE to 21,000 BOE, you can assume sales are slightly less than that and it will continue through there – through the fourth quarter and beyond. So, I’d like to think our exit rate is going to be pretty close to our sales, but we will just see how (inaudible) shakes out.

Hsulin Peng – Robert W. Baird

Okay. And then last question, just thinking about – I know you’ve said you would fund CapEx from cash flow and revolver, and I’m just wondering if you assuming that you continue to term out your bank debt, how does that impact you on volume base when you term out bank debt?

Lynn Peterson

Go ahead Jimmy, take a try.

Jimmy Henderson

I’m not sure I quite understood, but if we – you say if we term out the – you mean replace the revolver -

Hsulin Peng – Robert W. Baird

The revolver.

Jimmy Henderson

...with high yield or something?

Hsulin Peng – Robert W. Baird

Right. Right.

Jimmy Henderson

That’s, I guess there is a rule of thumb that it’s about 20%, 25% reduction of your borrowing base for what you have on high yield. But that’s just – that’s not always all true and it kind of depends on the relationship with your (inaudible) that’s been negotiable in the past, so I guess all I could say is the rule of thumb is around 20%, but I don’t necessarily plug that into the model, it’s a bit of a negotiable difference.

Lynn Peterson

And I would also keeps its complete, a third of the wells in the fourth quarter that were nearly for the full year. Now we’re seeing 23 net operated wells out of 55 total. You’re going to see a big ramp up in our model base through your – into next year too. So, this is a big time for Kodiak and we’ve got a very important quarter ahead of us, that’s going to grow into the first quarter 2013. So -

Hsulin Peng – Robert W. Baird

No, it sounds good. Looking forward to – first quarter of 2013. Thanks.

Lynn Peterson

Thank you, Hsulin.

Operator

Your next question comes from David Tameron with Wells Fargo.

David Tameron – Wells Fargo

Good morning Lynn. I guess you alluded this, but you had previously said, you expect to the cash flow neutral in 2013, I don’t know if I missed that in prepared remarks, but where do you currently stand given where everything is out in in the field?

Lynn Peterson

Yeah, I don’t think we’re going to be too far out, and Jimmy stop me if you think I’m wrong, but I think we’ve always projected here is kind of first half of the year would be in an outspend position and the second half we turn into – turn the corner here and I think we – again, we’ll get all these numbers out to you guys as soon as we can here to get through the quarter and early December we should have everything out to you, but that’s still our goal here. And I think as we’ve become more efficient with our drilling and our costs would come down, I’d certainly would. Jimmy do you have…

Jimmy Henderson

No, I think that’s fair, I think we can’t see the second half, as it’s turning the corner, I don’t know if it will shake out that we’re cash flow neutral or positive for the whole year, but I think that’s generally the shape of the curve if you will.

David Tameron – Wells Fargo

Okay. And then just the bigger picture, I think Lynn, in the past you kind of said that 200 or 225 is kind of an effective rig limit capacity in the basin. Is that kind of where we’re at today and if so, what – what is the service cost moving over the next year to two years?

Lynn Peterson

I don’t know the exact rig count. I think it’s actually below 200 now. And I think it really speaks to a changing out of some of the older rigs, older iron being replaced by newer more mobile type rigs. And I think everybody, not just Kodiak has drilled more wells with the same number of rigs. And so, I think that’s a real positive event for the Williston Basin.

Again, obviously we could, the rig count could get cranked up, but I’m not sure it needs to be. I think we’re all focused on gaining operational efficiencies and I think that’s what’s so cool about what’s going on right now.

The service side, I think is probably finally reached up in that what the exploratory side was, and you can get services now, it used to be that you had the hope that you could them out there within a few weeks, and today they’re pretty readily available. I think as we look at our side of it, we see our service companies who are having backup equipment now which is very important, and it’s really helped us in the completion side of these things when equipment breaks down, we no longer have to wait days. We typically are down to hours. And that’s a very big number for all of us.

So, where these well costs are going to go? I mean, I don’t have the crystal ball, I mean, we firmly believe we can get down below $10 million here, and again, I’m talking about the wells in the deeper part of the basin, so they’re going to be roughly 11,000, 11,500 verticals depth. We’re going to use a 100% ceramics, something we’re giving you our highest priced well.

We think we can get it into that, say 97, 98 range here pretty quickly with what we’re guiding. Again, I think it’s going to take the first or second quarters of 2013 to see those numbers flow through our financial, because we’ve got a time delay between when we’ve drilled well and when we’re completing them. Guys you got other, any other thoughts -

Jimmy Henderson

Well, I think it really, Lynn, has hit the key point, but one of the most important things is that because services are more readily available and has stabilized for almost everything we do now, we’re able to look to a number of contractors and bid these things. And it used to be, even a year ago that, if you needed something you were desperate You could just whoever you could find to come out and do a job whether they’re really good or not, you’ve got them.

Well, that’s changed. And we can bid things out ahead of time and when we can pick and choose the better contractors in. It’s just kind of the mature greatly and things are more efficient and smooth now, and we expect that to continue and there will be some reduction in well cost, some additional efficiencies.

David Tameron – Wells Fargo

Okay. That’s helpful. Thanks guys.

Jimmy Henderson

Thanks David.

Operator

Your next question comes from Jason Wangler with Wunderlich Securities.

Jason Wangler – Wunderlich Securities

One quick one up in Wildrose, about how much of that’s held by production and you talked a little bit about the activity up there. What do you see, is it one rig or is it kind of spot to couple of wells up there as you look into next year?

Lynn Peterson

We haven’t put all that together yet, Jason, probably hold it up a little bit. I mean that’s really the one area we’ve got to get our acreage HPP, so my guess is we’re going to have rig running up there (inaudible) a little bit. I think – again, as we get more and more well rigs, we also get more comfortable, we’ll kind of lay that out, so maybe I’ll ask you just hold off and we’ll kind of lay that out here in our final budget.

Jason Wangler – Wunderlich Securities

Could you just provide me just about how much acreage is out there and maybe just a percentage of what’s held versus what you need to do?

Lynn Peterson

Yeah, right at 20,000 acreage as I recall, and probably we’ve got a – probably a third of that is HPP maybe or 40%.

Jason Wangler – Wunderlich Securities

That’s helpful. Thank you.

Operator

Your next question comes from Tom Bishop with DI Research.

Tom Bishop – DI Research

With regards to the – where does the (inaudible) I know too many people probably expected the hike of a hockey stick that was getting this year. I mean I think you don’t have my – I still have the power out there, I still have my press release, but I think like the Q1 was about 12,000, Q2 was about 13,000 and now we got 15,800 in Q3 and we’re going to exit the year with 27,000, I mean I know what you said that a lot of this skewed towards Q4, but can you just put a little more meat on that or remind us of what’s behind that kind of hockey stick?

Lynn Peterson

Yeah, I think most of our shareholders had a pretty good feel that it was going to be a ramp up in the fourth quarter till we got our sixth rig in, we brought in the first of the year. Our seventh rig, we brought in about May. Our eighth rig we brought in August. We put all those on full well pads. We saw just from a timing standpoint, you got to drill the wells. You got to look at the time, get the location prep and you’re here completing and we – I thought we laid this out very clearly all the way through that we were anticipating build a multiple completion crew. So, I don’t think there should be any surprises there at all.

Tom Bishop – DI Research

Well, okay – another question is that you’re spending another $170 million this year on production and yet the target remains at 27,000 BOE. So, what am I missing on that one?

Lynn Peterson

Well, again, everybody wants these numbers so quickly. We think we’re going to have a big ramp up and we’ve set there with the 27,000 BOE and we’ve heard it all, this entire year that we wouldn’t get to that number. I think we clearly get to that number now and certainly get, you know, as we look at the first part of 2013 is where you’re going to see these, most of those production rollover. Again, I’ve pointed out, we’re completing 23 net operated wells in the fourth quarter. No 23 -

Jimmy Henderson

And…

Lynn Peterson

In the fourth quarter, but we have total of 55 for the year. So, you’re going to see a big change in our production.

Tom Bishop – DI Research

What is the production level exiting Q3 as compared to and even currently?

Lynn Peterson

We’ve put it out there the news release two weeks ago, 19,000 BOE to 21,000 BOE is our current production. These things don’t change on a daily basis. So, I think that’s still good number from a production standpoint.

Tom Bishop – DI Research

All right. Thank you.

Lynn Peterson

Thank you.

Operator

Your next question comes from Eli Kantor with IBERIA Capital.

Eli Kantor – IBERIA Capital

Just a quick question on acquisitions, you guys are pretty aggressive in 2011 buying properties. We haven’t seen you guys making deal yet this year, just wondering what your appetite is for making additional acquisitions going forward?

Lynn Peterson

I think our attitude remains, we’ve said, you know, we always look for quality acreage, there has been some things we’ve looked at. You can’t win them all. So we’re going to continue to pick through it and we will see if we come up with something we like.

Eli Kantor – IBERIA Capital

All right. Thanks, guys.

Lynn Peterson

Thank you, Eli.

Operator

And that does conclude our question and answer session for today. I’d like to hand the program back over to Mr. Peterson for closing remarks.

Lynn Peterson

On closing, I’d like to thank our staff both here in Denver and in the field, as well as all the service companies that continue to help us to execute our program. We are on course to deliver our stated goals.

The well performance continue, that we continue to experience, it’s solid and it’s really a world class resource play that we’re involved with and Kodiak is a meaningful operator out here. The efficiency gains that we have made over the past two quarter have been significant, the infrastructure build out has been remarkable and all these items help us set the table which should be really exciting fourth quarter for Kodiak, I think as we look into the next first quarter of 2013 and beyond, the story continues to grow. We’re excited about it.

I would like to reach out to all of our friends in East Coast, and New Jersey, and New York and tell you all our thoughts are with you guys. We hope for a speedy recovery and we look forward to meeting you here in next few weeks of conferences. But hope all your safety as well. We’ll talk again in 120 days, and we’ll see several of you at the conferences as we move along here. And this time I’m going to go ahead and sign off and I hope everyone has a great weekend. Thank you.

Operator

This does conclude today’s conference. You may now disconnect.

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