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Kodiak Oil & Gas Corporation (NYSE:KOG)

Q4 2012 Earnings Call

March 1, 2013 11:00 a.m. ET

Executives

Lynn Peterson – Chairman & CEO

James Catlin – EVP Business Development

Jimmy Henderson – CFO

Russ Branting – EVP, Operations

Analysts

Brian Corales - Howard Weil

David Tameron – Wells Fargo

Scott Hanold - RBC Capital Markets

Dan McSpirit – BMO Capital Markets

Hsulin Peng - Robert W. Baird

Welles Fitzpatrick – Johnson Rice & Company

Jason Wangler – Wunderlich Securities, Inc.

Gail Nicholson – KLR Group

Steve Berman - Canaccord Genuity

Ryan Oatman - SunTrust

Michael Scialla – Stifel, Nicolaus & Co.

Kent Green - Boston American Asset Management

Operator

Good morning. My name is Jody and I will be your conference operator today. I would like to welcome everyone to the Kodiak Oil & Gas Corporation Fourth Quarter and Full Year ended December 31, 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 that 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.

Lynn Peterson

Thank you, Jody. Good morning everyone. As usual we’ll take your questions at the end of the call, but before we begin let me introduce the team today. It’s James Catlin, Russ Branting and Jimmy Henderson are with me. We appreciate your time this morning as we walk through our 2012 results and then give an update on operations. I would ask that you 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.

I’m going to hit on just a few of the significant accomplishments for the past year. Last evening we reported fully diluted GAAP earnings per share of $0.12 which has been in line with the consensus expectations for the quarter ended December 31, 2012. We also reported adjusted EBITDA of $107 million for the fourth quarter, driven by low gas sales of $131 million.

For the 12 month period ended December 31, 2012, we reported fully diluted GAAP earnings per share of $0.49 which again were in line with consensus expectations for the year. We also reported full year adjusted EBITDA of $317 million driven by oil and gas sales of $409 million. We reported oil and gas equivalent sales volumes for the period ended December 31, 2012 of 5.3 million barrels of oil equivalent representing 267% growth than the previous year. Crude oil revenues accounted for approximately 95% of oil and gas sales reported in the period. Our daily average sales volumes increased from 7,200 barrels of oil equivalent per day during the fourth quarter 2011 to 18,200 barrels of oil equivalent per day for the same period in 2012, or an increase of 150%.

We grew our total crude reserves to $95 million barrels of oil equivalent or an increase of 138% over prior year's reserves. Approximately 46% of the 2012 total crude reserves are categorized as proved developed, producing. The related [pb-10] value of our reserves increased to $1.9 billion before income taxes. Based upon our internal estimates to date, we have drilled and converted approximately 10% of our potential drilling locations to proved, developed producing reserves.

We have also recorded 9% to 10% of the potential locations as proved undeveloped locations at December 31. This leaves the company with ample drilling opportunities for the next several years as we maintain our current rig count. During 2012, we saw our well costs decline by approximately 15% to 20%. The cost reductions were achieved through a combination of service cost decreases and through field level efficiencies. There continues to be a wide range for completed well costs in the basin. The spread in well cost published by different operators is largely due to where the lands are located and to completion procedures.

The key drives of well cost are formation depth, bottom well pressures, and completion techniques. As approximately 80% of our total acreage is located in the lower-pressured window and typically our wells are located in deepest part of the basin, we continue to use 100% ceramic [propping]. Currently our well costs range between $9.7 million and $10.2 million which when can be broken down to about a third of drilling and two-thirds for completion task. With efficiency gains and the cost reductions, we anticipate an additional cost savings of 5% or better as we move through the year.

For 2013, we have allocated $600 million of capital expenditure budget to the drilling and completion of 75 gross, 61 net operated wells. $140 million to non-operated drilling and completion activities, and $35 million to other items including acreage, acquisitions, water disposal wells, and well connections. During the second half of December 2012, we observed evidence of communication between wells during fracture stimulation procedures. As a result of that we decided to revise our completion procedures.

Based upon our new observations, we decided to [shut down] all producing wells within the immediate vicinity of completion operation of new wells. With this approach we are seeing a positive response from the shutting wells once they are returned to production. Which leads us to believe that we are initiating new fractures into the old well bores and finding new reserves. While this procedure has resulted in a delay of some production, it is our view that this approach will help us prudently manage the reservoir and enhance our expected long-term results.

We will continue to monitor our production through the first quarter and will provide additional clarity at the end of the quarter as to the impact, if any, the changed completion procedures have on full year guidance.

Now shifting to our operations, let me turn it over to Jim Catlin and he will walk everybody through it.

James Catlin

Thanks, Lynn, and good morning everyone. Currently we are operating seven drilling rigs. As oil prices have stayed robust we intend to keep the seventh rig into the second quarter of the year. We have seen sPUD to rig release days decrease to the low 20s for a typical 10,000 foot lateral well. With one recent well being drilled with a liner in the hole in 18 days, and that is a Kodiak best. We are operating nine work-over rigs, three of which are 24 hour rigs. Increasing our work-over fleet has assisted us in decrease our downtime for producing wells that require routine maintenance. At this time we continue to utilize two full time 24 hour completion crews. We anticipate that we will release one crew from time to time as our completion schedule evolves during the year. Year to date in 2013 we have completed 19 gross and 14 net wells. We drilled four salt water disposal injection wells during 2012 and intend to drill a like number in 2013. As we have mentioned often, the salt water disposal wells are helping to drive down our lease operating costs as we reduce our dependence on third parties for water handling and disposal.

I’d like to spend some time this morning to discuss our two pilot projects. While we and other operators have tested closer well bore spacing between a few wells, Kodiak believes it is important to test this concept throughout an entire 1,280 acre drilling unit. We are moving ahead on both of our pilot programs with three rigs currently drilling in our Polar project and one rig just finishing three more wells in our Smokey project. In both pilot programs, we intend to drill six wells in the Middle Bakken and six wells in the Three Forks.

We have just completed coring operations on one of the wells in the Polar project area. We will be evaluating the core to determine the optimal location of well bores in the Three Forks. Taking into effect lease line setbacks, this places the individual wells in the Middle Bakken approximately 800 to 850 feet apart.

To reiterate our experience with these four basins, we have drilled wells this closely spaced several times. While we see pressure communication occasionally during fracture stimulation procedures, we have not observed any sustained interference between wells during production. We believe it is important to see what the impact of spacing is on a larger group of wells within the drilling unit.

We have set out to locate the wells in the Three Forks based upon an alternating sequence between the upper and middle intervals. The final location of all the Three Forks wells is subject to the results from our core evaluation. Throughout our entire acreage position, we have drilled a number of wells in what we refer to as the upper and middle intervals of the Three Forks as well as the TF3 interval that separates the two mentioned intervals.

Much of the work we’re doing with well bore placement in the different intervals within the Three Forks is exploratory and we will adjust our plans as necessary. Upon completion of the Three Forks wells, we should have a better understanding of the various intervals and how the reserves from each might communicate after fracture stimulation.

Completion operations in the Polar project area are scheduled to commence in midyear. We’re planning a micro-seismic project in the Pole area to gather additional information during the completion process. Completion operations in the Smokey area will be done throughout the year with full development completed after the Polar project.

Oil, gas and salt water disposal infrastructure has been completed into each of the pilot areas with the expectation of them being fully operational prior to completion operations. We would caution all of our listeners that we will not have immediate information about the pilot programs available publicly due to the length of time it will take to complete the operations and the time necessary to evaluate the production. However, we would hope to gain some useful information towards yearend.

The two pilot programs represent about a third of our operated drilling program and the information gained from the two pilots should have a significant impact on how we design our future development program.

With that, I’ll turn the call over to Jimmy.

Jimmy Henderson

Thanks Jim. Thanks everybody for joining us this morning. During 2012 we saw significant improvement in our oil price realizations. We’re currently experiencing about $3 to $5 deduct from WTI pricing as we saw in the fourth quarter. To that we typically add around $1.50 per barrel on the oil to get back to the wellhead for gathering costs. Looking back over 2012, we saw differentials widen to as much as $25 per barrel in February and March early in 2012 with an average of nearly $12 for the year. With WTI trading in the range of $90 per barrel, we’re currently experiencing some very solid economics with our drilling programs with cash margins in the $50 to $60 per BOE range. We continued to maintain our hedging program to protect our CapEx with over 15,000 barrels hedged for the remainder of 2013, mostly through swaps with an average price of nearly $95 per barrel. We have also hedged over 5000 barrels into 2014 primarily with swaps at around $92 per barrel WTI. We will continue to be opportunistic with our hedging program and weigh around additional hedges as we bring new volumes on to production. In addition to the salt water disposal improvements that Jim spoke of, in 2012 we saw a great increase oil and gas infrastructure in the basin.

Currently, we have about 85% of our wells connected to gas pipelines and approximately 50% of our oil production is also moved inside pipelines. We are currently building infrastructure in our Polar area and one step is completed. Our total oil moving by pipeline should be over 80%. We have cautioned that while our gas wells are mostly connected to gas pipelines, our sales are still curtailed by plant capacity and pipeline pressures.

2012 also saw the expansion of rail loading facilities for the transportation of crude oil. Now there are about 16 facilities with capacity to move probably 700,000 and currently moving somewhere around 400,000 to 500,000 barrels per day. Like other producers we have benefited by being able to access market that are currently trading at a large premium to WTI. Although we continue to sell our oil to well head or nearby central delivery points, we estimate that over 80% of our oil is currently moving by rail and receiving (inaudible) based prices.

We continue to focus on our production cost and note that we drove our lease operating expense from $8.67 per barrel of oil equivalent in 2011 to $6.04 per BOE in 2012. The decrease of 30% is largely a result of our improved handling of salt water disposal cost. We expect our LOE to remain in the range of $6 per BOE as we move forward. While we expected some reduction in cost from the water handling facilities, these costs will be largely offset by increased work over expense as our wells mature.

As we continue to bring on new production and add new reserves, we are working with our banks to increase our borrowing facility. Having just completed year-end reserve work, we anticipate a commensurate increase to our borrowing base this coming spring. With that, let me thank our listeners for joining our call and I turn the call back over to the moderator to take your questions at this time.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Brian Corales from Howard Weil.

Brian Corales - Howard Weil

Can you walk through the pilot -- so you are drilling six wells in the Bakken and then -- is it six wells in the Three Forks, can you explain that again?

Lynn Peterson

Okay. We got to drill six wells in the Middle Bakken, put about 800 feet apart. Then we have drilled all of our, I think we drilled close to 53 Forks wells. Those have all been located in what we call the upper and middle intervals, commonly referred to as first and second [ventures]. And so what we have chosen to do is alternate between the upper and middle. And the reason we are doing that Brian, we are not convinced that intervals are not at communication with each other. We would like to believe that our frac procedures are opening this entire interval up. Again, lot of this work, we are doing this to evaluate that and see if that’s our feeling at this point. So we felt like spread them out, make the most sands. And again it's a real positive because you have got a bigger interval to work with here and got more oil in place.

Brian Corales - Howard Weil

But it's three like in the upper and three in the middle Three Forks. Is that right? And stagger them?

Lynn Peterson

That’s right.

Brian Corales - Howard Weil

Okay.

Lynn Peterson

You go to our corporate presentation. We kind of laid it out.

Brian Corales - Howard Weil

Okay. No, that’s helpful.

Lynn Peterson

And the question about 800 feet part was specifically...

Russ Branting

Maybe 40 to 50 feet between the verticals.

Brian Corales - Howard Weil

Okay. You know, maybe this is for Jimmy here, but you talked about much better pricing and we’ve seen the pricing. Can you maybe talk about what you’re differential to WTI has been for 2013 thus far?

Jimmy Henderson

Yeah. It’s been pretty tight. I’d probably say kind of at 3 to 4.50 range on average for general tab and going forward it still looks promising. I know the [sphere] between WTI and Brent narrows in the futures markets, but it seems like as they get closer to those front months it continues to lighten out and see what happens in the Middle East, et cetera that affects Brent prices. But internally here we’ve actually – we’ve adjusted our expectations. So, historically we use $10 off of WTI and now we’re more comfortable with $7, $7.50 Brian (inaudible).

Operator

Your next question comes from the line of David Tameron from Wells Fargo.

David Tameron – Wells Fargo

Lynn or whoever wants to take it. Can you guys comment on the way you just looked at the PUDs last time in the K and it looked like PUDs went up a little versus a year ago as far as what you could book on the EUR basis and can you address that? And then it also looks like you’ve booked a little bit less PUDs for each PDP. So can you talk about what if any upside there is in those reserve numbers?

Lynn Peterson

Truthfully I think we all feel like our PUDs are light compared to our well performance. Again I’ll take this as far back to just continue to give more historical production data. I think none of those wells involve third party reservoir work. I think they generally continue to be one PUD for a PDP almost at 1:1 basis. We have certain situations where we’ve drilled Bakken wells that they haven't been Three Forks, particularly over in our non-operated stuff in Dunn County. And so I think there’s a reluctance to book any Three Forks wells over until it was drilled on that block. So it’s an ongoing project, but I can’t tell you where – it’s something we’ve got to spend some time with and see if we can move them along and move them up the learning curve a little bit here this year because our well performance certainly exceeds our PUD working significantly in some of our key areas.

David Tameron – Wells Fargo

What about as far as – it looked like you only book in three years versus five years out. Can you just – is that (inaudible).

Lynn Peterson

Yeah and again I guess it goes back to this idea of booking 1:1 and again this is a resource play. We think truthfully you could certainly book a lot more. You can book up to five years under the rules. But we’ve also felt like it’s probably not the most significant item. I think our wells speak for themselves and you have knowledge of the basin certainly you can see the upside of what we’ve got here. It’s a pretty conservative approach I think at this time.

David Tameron – Wells Fargo

Just general comment on, are you seeing any tightness in getting rigs, work over rigs, any current bottlenecks in the basin? And then if you just talk about weather comes and goes. Can you talk about what you’ve been seeing over the last month or two as far as weather if that’s ….?

Lynn Peterson

Russ Branting is here. Why don’t you go ahead and give you a feeling for what’s going on there.

Russ Branting

Effective for our working rig, general work to nine right now. Obviously we’ve got three 24 hour rigs. Everything is working very well on that end. You’d see a lot more services available than you did like in the last couple of years and you’ve get a lot more experience up there in the shale. Prices are coming down due to the competition and also the weather hasn’t been the biggest factor as it was back a couple of years ago. So we’re out of the deep freeze right now and there’s very little snow, a little bit of ice and I don’t think that’s going to pose a big problem for us going forward.

Lynn Peterson

And then too Russ, a lot of new rigs are coming into the basin. Some of the older rigs are getting laid down. So the more modern type. We’ve been fortunate that not a lot of ours, well of ours were built for us and brought up here for the purpose.

Russ Branting

That’s correct.

Lynn Peterson

Certainly you can get a rig today where you couldn’t do it a year ago.

Russ Branting

That’s the venture.

Lynn Peterson

And you could buy a good PUD tomorrow if you wanted to.

David Tameron – Wells Fargo

All right. And then just no flooding issues as far as breakup?

Lynn Peterson

Russ just came back. He spent a week up there. So that’s why we didn’t have him talk about it because we weren’t sure if the flights would get back in time. So anyway, you might just tell how the weather looked?

Russ Branting

No, actually it was nice up there then was in November and let's say the dust is flying right now.

Operator

Our next question comes from the line of Scott Hanold from RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Couple of questions here for you. You know first when you look at the differential, what is the amount of production right now you are getting on rail versus piping? Where do you think that is going to go in 2013 for you guys?

Jimmy Henderson

Hey Scott, it's Jimmy. We are probably -- we think probably 80% of our production is moving by rail and as we have talked, we saw most of our production that's still at the well head or [CVT]. So we don’t really have control over that all the way to the market. But we know based on who we are selling to and our discussions with them and the pricing that we are getting quoted, generally [harden] moves. We don’t actually have commitments along the railroading facilities, more pipelines to control the movement of the oil. But we do other (inaudible) sell to them and we are getting the best prices. And right now that’s on rail and accessing the coastal markets, so the waterborne markets.

Going forward during the year, I think it's still dependent on what is the best pricing for us. At present we have -- the lack of commitments that we have -- we have ultimate flexibility to how that oil moves. So we are going to move to the best market as most as we can. We have got working purchases that we know are going to move to barrels. So those particular purchases are moving on pipelines as in the future more pipelines to [ourselves] becomes a better market and it does direction will go that side.

Scott Hanold - RBC Capital Markets

Fair enough. Good. And another question on your reserves in your PUD wells. I guess if I look at, I guess your PUD bookings and the reserve side divided by kind of your net PUD count and obviously account for royalty interest, that it kind of implies somewhere between 550,000 to 600,000 barrels EUR that’s booked for your PUDs. Is that a fair assessment and how do you kind of -- when you step back and look at your view of kind of EURs on your Bakken assets? How do I kind of square the circle on that a little bit?

Lynn Peterson

You know, again, I think we kind of look at our Dunn County stuff, our Polar, Koala and Smokey. I mean there is a difference between the east side and the west side. Over in Dunn County, one of the things we always like about that area is the GOR as well. So when you see our numbers, they were really primarily oil numbers. I think as you move to the west side, we certainly see a much higher GOR. So while BOE numbers have a tendency to be high over there, actual well values based upon oil, I think you are going to take it in consideration. So I would put Dunn County as our top and then I think you put the Polar, Koala, Smokey in that range. And I think when we talk of reserves over there, we are thinking 650 to probably upwards to 800 type numbers. Dunn County, well a little bit higher over there. We think we are probably looking at maybe 750 to 900 type numbers over there. And that falls in line with what we have got in PDP bookings. So those are third party numbers.

Scott Hanold - RBC Capital Markets

So PDPs look like that and in my -- so when I look at PUDs and PUDs look like they are like still a little bit south of 600. Is that just conservatism in the way the engineers are booking them right now? Or am I just missing something on the math here?

Lynn Peterson

You know it seems to -- that’s the way we feel about it. Unfortunately, we received our reserve kind of late in the game here and we had to run from an accounting standpoint to have everything done in time. And I think going forward we are going to try to push -- a lot of this work done earlier in the year than just roll it forward so we can spend little more time with them. And, again, some of this has to do with just get a little more data for them and production history. I think if you look at our Polar area when we [bought that], the blocks. Our team has driven the values forward here and so we have got better numbers out of our well that we have drilled and completed than we had out of wells that were drilled previously. And some of that has to do with lateral length but also give our guys credit, but also give our guys credit from a completion standpoint. So I think that’s an evolving situation a little bit and we try to be pretty careful on trying to push one to another, let them to do the work and then we’ll go forward and get our production enlarging continue to work on that as we move ahead.

Scott Hanold - RBC Capital Markets

And one last one. Obviously people talk about the lower bench opportunities in the Three Forks. I guess yesterday there was another Bakken operator that talked about this Middle Bakken silt. Is it a prospective formation or is it that you could get 15, 16 miles in a section? What is your view on your acreage to prospectively of either or both of those?

Lynn Peterson

Go ahead Jim. We’ve got to talk about that one a little more.

James Catlin

Well, we think there’s a great deal with the Three Forks less prospective and we don’t think that we know all the answers yet frankly. We’ve drilled a number of wells in the upper bench that have been good wells. We’ve got some in the next bench that are good wells. We’ve drilled some in between that are decent wells. We haven’t yet drilled any deeper, but we’re certainly looking at it. We think that the Three Forks – we just feel like we have a lot to learn and we’re cognizant of what other people are doing, that there’s been some success in the third bench down and again terminology gets a little mixed up from time to time. But part of the reason we’re doing our exploratory work in the pilot programs with extensive core work and long work is to get a better handle on the various benches and we’re going to test everything that looks like it’s potentially productive.

Lynn Peterson

In regards to the silt under, we encountered this a year ago, a year and a half ago when we first started drilling our Smokey block. So we’re well aware of it and it was nothing new from our perspective.

Operator

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

Dan McSpirit – BMO Capital Markets

Regarding communication between wells that you’ve observed generally, is that specific to a certain area on your leasehold?

Lynn Peterson

Not really. I’d say it depends exactly where we’re doing the work, where we’re at, but again I think we’ve seen some situations where we moved fluid quite a distance at a half a mile away. And so if you get a nice fracture it will move, but Jim, you want to…?

James Catlin

Yeah and Russ is here too and he can add his comments. But what you do see, you get different fractures. Some of the individual fractures go a long ways and fluid will go a long ways, but we’re not packing propane out there. Our propane packs within a few hundred feet of the well bore we believe. So occasionally you see the fluid travel over a distance. We have seen wells that were producing, actually communicating with a fracked well nearby and so we’ve been very careful to shut all of our producing wells in when we frac. But we are not seeing communication or we’re not seeing interference during production. It changes once you take that, you release that pressure, flow the wells back, the cracks that you open up over a long distance seem to heal up and where we have fracked wells near producing wells, the producing wells tend to get better. And as we mentioned in our remarks, we believe that as we frac wells more closely together we’re going to create more fractures and actually enhance the production. Russ, I don’t know if you have anything to add there.

Russ Branting

That’s all just the difference between your hydraulic link and your prop link and like Jim said, we’ve seen hydraulic links over a couple of thousand feet into existing well bores. But to close, usually our performance is a little better on the existing wells.

Dan McSpirit – BMO Capital Markets

And you spoke about in your prepared remarks at the top of the call, you spoke about a potential change to production guidance for the year. Could a negative impact to your production guidance mean a positive impact to recoveries per location if in fact new fractures mean new reserves?

Lynn Peterson

Well, we knew we’d get the question, Dan. The whole idea – again we’re 60 days into the year. We have changed a little bit of how we’re doing, but we have seen some positive responses when we’ve brought some wells back on production. And so we’re not sure it’s going to be a negative impact whatsoever at this part. Again, there may be a little bit of delay in the production but I think the biggest part of our whole planning is, we, for most of our part backlog is the production again because we have lot of bigger well pads coming on in late second quarter, coming into third quarter. We did try to allow for weather conditions and these types of things early on. So we just want to [sort out] that we are evaluating this and it's something will be ongoing anyway. But it's way too early to tell. We are pretty pleased where we are at today.

Dan McSpirit – BMO Capital Markets

Okay. And I think you have answered my next question with respect to the production growth profile for 2013. Back-end loaded is not the wrong assumption here?

Lynn Peterson

No, it isn’t at all.

Dan McSpirit – BMO Capital Markets

Okay.

Lynn Peterson

And I think you can look at our (inaudible), we have got 2 four well pads, we just came off of three well pad that we came last. So that’s 11 wells that we are going to start moving on here. It will be probably end of March we get rolling. So you can see them coming in second quarter. Again, you look at these two 12 well programs, the Polar in particular, we are going to start completing all these wells in May and June. And so it's a big onslaught of large multi-well pads. So we think we are excited about the year, we think we have given it a lot of consideration. We are very comfortable where we are at.

Dan McSpirit – BMO Capital Markets

Okay. Great. And one last one for me and maybe this one if for Jimmy here. Just confirming the $6 per BOE lifting cost figure. That’s a good per unit figure to use here going forward?

Jimmy Henderson

We think so. As I said earlier, we have got a couple of offsetting elements to that with additional -- with a growing number of wells in our portfolio. We do have more work over rigs and we do have more expense on that side. And all of those type expenditures are expensed through LOE. So there pad number is growing a bit as we move forward but as far as we offset by implementing water cost, and as Russ and his team get more water gathering in the ground, we are going to see water cost continue to decrease there. It really hasn’t impacted the numbers just yet, so net-net we are pretty offset and can maintain where we are at.

Operator

Our next question comes from the line of Hsulin Peng from Robert W. Baird.

Hsulin Peng - Robert W. Baird

So mentioned that we won't get results from the two pilot projects until, likely until year-end. What I was wondering, I you can comment on like your expectations are in terms of -- you know for the well results in terms of well interference or that sort of thing.

Lynn Peterson

Our expectations I think are to find well just like we found. And, again, we don’t believe that this basin is going to hurt us whatsoever. But we want to caution, I mean we have had some many callers who have said, when you are going to start putting up dry easement well. And we are not going to do that. It's just not going to be that way. We are going to get all the wells completed. We are going to give them time so we can draw some conclusions. I mean this is a big step not only for Kodiak but I think it's a big step for the entire basin. What will these rocks give up here and how many wells can you drill in this basin, you know like this. So we are very optimistic of what we are doing. Obviously, we don’t think we are stepping out at all. We have done this testing over and over and now we are just putting it into a [DSU] and saying you put six wells [frac] here, as a minimum it's going to have draw-down more than the run from (inaudible). And we just need to find out this information.

Hsulin Peng - Robert W. Baird

Okay. No, that sounds good. And then second question is on more general strategy. You had mentioned that you anticipate getting to cash flow neutral by year-end. And so I was wondering, once you get to cash flow neutral, do you put your thought on accelerating NAVs versus staying cash flow neutral. Just trying to understand how do you think about that.

Lynn Peterson

We kind of move ahead day to day and now as we get to that situation we will evaluate it all year long. I mean what our oil price is going to do and all the things we are working on right now. There is a lot of moving parts to our operation here and we constantly think about our acceleration. But I think one of things again, talking back to this pilot program, these are important to us so we can figure out how to space our well bores and I think if we can get to a positive cash flow going into 2014 sometime it’d be a great situation, give us a lot of options.

Hsulin Peng - Robert W. Baird

And then I guess for comparison purpose, can you give us the breakdown of your 2012 CapEx that you had in 2010. How is that split up between drilling versus for operated wells, non-op and other expense?

Jimmy Henderson

For 2012?

Hsulin Peng - Robert W. Baird

Yes, for 2012.

Jimmy Henderson

Is that in the K?

Lynn Peterson

Yeah. Hsulin, I think…

Hsulin Peng - Robert W. Baird

It’s in the K? Okay.

Lynn Peterson

We put that in the 10-K, but maybe if we can just direct everyone’s attention to there. We broke out between operated and non-operated as well as other expenditures both for 2012 and for our 2013 plan.

Jimmy Henderson

There’s some you don’t have there so maybe we can address that offline here.

Hsulin Peng - Robert W. Baird

Okay. That sounds good. I can look through there. And then last question just for housekeeping. What’s your expected income tax rate for 2013?

Jimmy Henderson

37.2%.

Hsulin Peng - Robert W. Baird

Very precise. Okay, it sounds good.

Jimmy Henderson

Yeah. Just to clarify, 2012 obviously was a transition year for our tax situation going from non-accrual to accrual. So it should be cleaner in 2013. So I think generally you’re seeing about a 37% tax rate all deferred. Unless something changes in Washington.

Operator

Our next question comes from the line of Welles Fitzpatrick from Johnson Rice.

Welles Fitzpatrick – Johnson Rice & Company

It seems like it’s too early to know the fact that the shut-ins during fracs has on EURs. Can you give us an idea as to the bump in production that you get off those wells when you do bring them back on?

Jimmy Henderson

I don’t think we really want to go into that detail. We can share some of this stuff offline, but I don’t think it’d mean anything, Welles. We’ve seen some improvement in our wells certainly, but how long it’s going to last and all that still early.

Lynn Peterson

Yeah, we just got – everybody wants instant information here and that’s really not the industry. I think we need to give ourselves time on this stuff to see what the ultimate impact could be.

Jimmy Henderson

You’d have to see at least 90 day numbers to even talk about it.

Lynn Peterson

Yeah. That’s the shortest time.

Welles Fitzpatrick – Johnson Rice & Company

Fair enough. And then I was under the impression that the testing in the lower member had been put on the back burner because it’s really more present in the Polar, Koala, Smokey versus your other acreage as opposed to being a quality call. Is that right?

Lynn Peterson

I’m not sure I understand exactly where you’re heading. We’re not really testing the lowest, what’s called the third bench or we call the lower member. Again this is all subject to our core work that we just completed and we want to evaluate it and see where we want to place our well bores. Again I think it goes back to we’re trying to do something that we’re very comfortable with and we believe that the upper and middle intervals will provide us the reserves that we’ve seen in the past and we’ll work on the gather again as well bore spacing, what kind of communication we see if any between the two intervals and how we go forward. So there is –continental is doing a lot of work in the third and the fourth and that’s great. We appreciate the work they’re doing and we’re all watching it. But we’re not going to step to that degree at this point.

Operator

Our next question comes from the line of Jason Wangler from Wunderlich Securities.

Jason Wangler – Wunderlich Securities, Inc.

Just had one as far as the shut-ins. Could you just give an indication of the time that it is shut in from when you do until you turn them back on and just the vicinity about how many wells. I know that will be variable, but just to get an idea of the landscape.

Lynn Peterson

We’ve been shutting in the closest offsets because of the new frac in the well down for approximately 10 days to two weeks. Again it depends how many wells we’re fracking. If we’ve got a 12 well PUD it’s going to be difficult than a one well…

James Catlin

Or one well offset.

Lynn Peterson

But it’s all over the board.

Operator

Our next question comes from the line of Gail Nicholson from KLR Group.

Gail Nicholson – KLR Group

You mentioned additional cost savings in 2013 in the wells to bring down well costs about 5% or better. I was wondering if that is going to come from the drilling or the completion side.

Lynn Peterson

I am going to cut across the board.

Russ Branting

(Inaudible)

Lynn Peterson

I mean some of those things would be our continued efficiency that we are bringing on. I think as we go to more wells on pads, it's helping us in all these areas. And clearly I think if you look at our well costs, we have been drilling tasks in completion cost. The completion costs are two-thirds of our total well. So I mean if you want to get why dollars are being spent, that’s not the way we are pushing those. I think our drilling guys have brought our cost down significantly in 2012, largely because we shared our days off. On a little averaging less than 30-35 days probably a year and half ago and today we are down to low 20s. So it's a big number for us. And we hope we can get some benefits to the completion side and we have seen some changes on the completion side. We saw late in 2012 and it's carrying over here in '13. So we are seeing some cost improvements across the board I think.

Gail Nicholson – KLR Group

Okay. And then are you guys kicking any lower Three Forks expense cores on the Grizzly and Wildrose prospect?

Lynn Peterson

No.

Gail Nicholson – KLR Group

Do you have any plans to do that?

Lynn Peterson

No immediate plans. No.

Gail Nicholson – KLR Group

And then do you guys, the (inaudible) do you guys have any plans to do one in Dunn County like in 2014 timeframe or you are just going to see how the two units perform currently and then from there?

Lynn Peterson

We are working towards that and we have done a lot of work over there and so it would be an obvious next step.

Operator

Our next question comes from the line of Steve Berman from Canaccord.

Steve Berman - Canaccord Genuity

Follow-up to Gail's first question, on the 5% savings. Lynn, is that baked into your CapEx guidance for this year, and if not, do you see yourself pocketing that savings or maybe spending the same amount in just drilling more wells, and not necessarily in the year but.

Jimmy Henderson

Yeah. If you look at our CapEx we ran right at basically $10 million per well. I mean that is our current cost again it ranges from 9.7 to 10.23. But we have got (inaudible) net wells at $600 million, so I think that’s pretty straightforward, and now that we did the same thing on the non-op. Again, we hope and we believe we can drive these costs down but until it's done we didn’t want to project those numbers.

Lynn Peterson

Everybody wants to talk about what we are going to do if we can drive these costs down, I mean, again we have got to see what our pilot program is. We have some results out here so we now to put our well bores. We actually think this is a pretty important step for us. So we don’t keep just drilling in to the issues and mess our spacing up long term.

Steve Berman - Canaccord Genuity

And one more question, maybe this is better for offline. But in your proved reserves release last week you have said you had 836 non-proved locations. Do you have a breakdown of that by project area and Bakken versus Three Forks?

Lynn Peterson

Well, obviously, internal we do. We didn’t put that out for public consumption. I just think all of it starts right at this time and then we can certainly walk through our ideas in the way we look at it. I mean I think we have been pretty clear down to the core, the play, which we really believe the core of the development kind of encompasses with our Polar, Koala, Smokey and Dunn County. We think we can drill certainly seven, if not more, wells here. So the area of Wildrose Grizzly area, we don’t think we have that type of density at all.

Operator

Our next question comes from the line of Ryan Oatman from SunTrust.

Ryan Oatman - SunTrust

Most of my questions on the doubts specifically have been answered, but I wanted to shift through how are your completion counts going. You know it looks like about 13.5 net wells year-to-date, is that tracking above or below your expectations. I mean what impact, if any, should that have on annual CapEx and production.

Lynn Peterson

Well, as Jim said, we are right at 14 net wells, I think, through the end of February here. So I think when we lay this out we felt we could do five to six wells per month. So that’s tracking pretty close. I mean this is winter time and there is North Dakota, we have had our cold moments out there. We haven’t had a ton of snow this year, it was at least operable but we have had cold weather that slows everything down. So I’m pretty pleased that we’ve – I think we’ve got 19 gross, 14 net wells completed through the first 60 days basically and I’m pretty pleased with that number. I think that we’ve all said that was pretty progress. Now as we go into the springtime here we’ll have to see what the rain and the snow amount is not going to be significant, but the rain certainly could come. How does that bog down when we get into pass sores, moving equipment. I don’t think we’ve had a lot of days with icy roads where we haven’t been able to move trucks. That’s been fortunate for us here the first two months. So overall we’re pleased, but we do ratchet it up a little bit again as we get down into late second quarter where the weather turns warmer. We get more on these bigger well PUDs that we’re doing right now. We should be able to come along pretty good.

Operator

Our next question comes from the line of Michael Scialla from Stifel, Nicolaus & Co.

Michael Scialla – Stifel, Nicolaus & Co.

Jim I think alluded to this in his prepared remarks, but to see you get to the end of the year and you’re all happy with what you’re seeing from your pilot test. Is there anything from a regulatory standpoint or anything else for that matter that would prevent you from laying out a 2014 plan that incorporated 12 wells for DSUs more on a field wise basis at least in your core area?

Lynn Peterson

There’s nothing from a regulatory point of view, no. Basically you go back at – in north the total you have to go to the submission for our hearing for increased density and generally speaking they’re pretty cooperative and we believe that 12 for DSU is the proper number, I don’t see anything regulatory at all that would prohibit us from moving ahead that way.

James Catlin

Yeah. And Mike, maybe to add a little bit. There’s been work being done by other groups to even more drill than that. So we’re not going to be restricted to 12. We may find that we can get further than what we’re doing and certainly with that door still open to us.

Michael Scialla – Stifel, Nicolaus & Co.

And again if you’re happy with the results in those two areas I assume that along with some offset operator work that you feel pretty good about drilling at least that many in Koala as well. Is that fair?

Lynn Peterson

Yeah. Polar and Koala are the same. They’re separated by the Missouri river and so they were offshore absolutely the same. Some of our best wells are in the Koala area. So that’s why we’re excited about this and we really think we’re going to make some good wells here. We’re offsetting – our Polar project is offsetting a couple of wells we drilled probably midyear, early last year and they’re really solid wells. So again we believe this is going to work. We think it’s a good pattern and we’re anxious to get to work there and get the results out.

Michael Scialla – Stifel, Nicolaus & Co.

And then you mentioned that your pattern could possibly change a little bit based on what you see from the core. Is that just dependent on if you think – is that more of a where you would land these things vertically rather than how you’d position the distance between them? Is that what you’re hoping to learn?

Lynn Peterson

Well, we’re hoping to learn several things. The Bakken is a fairly discrete interval that’s the target. The Three Forks and obviously it has a number of benches, we know from core work and long work that there’s oil present in all those benches and some have more potential reservoir than others. But yeah, we’re trying to see the profit between well spacing. We’re also curious between the upper bench, the middle bench, what if any communication we see there when we frac the wells. But the Three Forks is much thicker overall interval than the Bakken and again we’re just trying to learn a little bit more about spacing both vertically and horizontally.

Michael Scialla – Stifel, Nicolaus & Co.

And last one for me. I know it isn’t an important area for you, but you’d mention a pretty interesting rate. I think it’s 1,000 barrel a day rate for one of your Wildrose wells last quarter. Just curious if you have any better idea what you’re seeing up there, if you’re still encouraged by that area and if you are still looking to get the well costs under. I think you were targeting $7 million for that area.

Jimmy Henderson

Yeah. I think we’d look at that area. We may be concluding the Three Forks it looks much – maybe better than the Bakken up there. Again, these are not the same reserves that we are looking for where we are drilling our current wells. Where is the range going to be here? Is it going to be 350 to 450? You know if we have those type of numbers I think you got to get to well across down to about 7.5 million plus or minus range to make it commercial. And again, even at those numbers it's not going to be the same rate of return we are achieving down south. But we have seen some encouragement and we are going to continue to monitor, but we are planning to drill some wells out there later this year. Again we had never drilled and completed one like Kodiak. The three that we completed at Wildrose were drilled by the predecessor company. And so we are going to do some work and we think we can get these well cost down and again a big part of it's going to come on the completion side of it, how we change our techniques. And we are seeing the same thing down the Grizzly area.

Operator

Our next question comes from the line of Kent Green from Boston American Asset.

Kent Green - Boston American Asset Management

How much you are recovering now and are you inferring any or is that pretty well set up, your infrastructure?

Lynn Peterson

We kind of lost the first part of your question there, Kent. I guess you are asking about the gas?

Kent Green - Boston American Asset Management

Yes.

Lynn Peterson

Yeah, you know today we are probably selling about 65% of the gas we are producing. Again, that number should improve. There is some gas plant expansion going on that we think we can hopefully drive that number north here as we go through 2013. Again, as Jimmy mentioned, we have got really majority of our wells up to, I think, what do we say, 85%-90% of our wells connected. So it's not like we have got stranded wells that we can't connect to. We have got everything done and we just needed a bit of reprieve from the plant side.

Kent Green - Boston American Asset Management

Second question about your people count. Have you -- is that going to start leveling off now that you had a pretty big surge that you are at a regular amount of wells that you are drilling per year?

Lynn Peterson

You know I think we are adequately staffed. We continue to bring in what we think are quality people to drill different venues. I think when we compare ourselves to other companies, we are extremely lean. Again, I think the team has done a good job. I think quality is a bigger concern of ours than quantity. Out in the field level I know, Russ, has made a real effort to try to find more experienced people to help us move forward here and help training young people too. So it's a dual job for these guys. And I think we have improved that situation immensely. So there is going to be some growth. It's not going to be as dramatic as seen in the past. But we are still pushing, we are trying to make something happen here and grow the company.

Operator

We have reached the allotted time for the conference call. I will now turn it back over to the presenters for closing remarks.

Lynn Peterson

Thanks, Jody. Thanks to all of our listeners here. You know I think we can take a step back, you know the entire basin is undergoing a shift to really the exploratory phase and saving acreage to more of a development phase here. You know a lot of the learning curves to date have been steep. I think the industry itself has a lot to learn. We have a lot to gain as we move forward through this development period. I think the work being completed by our team at Kodiak here as well as other operators, to test well bore facing both in the Middle Bakken and in Three Forks, is going to have a huge effect on the, not only ourselves but the entire basin here. You know, we will no doubt continue to tweak all of our procedures in all phases, and we have done it just accordingly. And while looking back over the last four to six years, I think our results have more been smooth but I would tell you what, I am pretty proud of what we have accomplished here. I think it's been an exciting period for the company. I think we have made huge strides. And with that, again, I want to thank everybody for your time this morning and continuing support. And importantly, I want to thank our staff for their efforts. Certainly without everybody involved here we wouldn’t have been able to get the company where we are at today. So with that I wish everybody a great weekend and we will see you, I guess we will talk in 60 days after the first quarter, or at the conferences we will be attending here. So thank you very much for your time.

Operator

Thank you. That concludes today's conference call. You may now disconnect.

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