Kodiak Oil & Gas' CEO Discusses Q2 2013 Results - Earnings Call Transcript

| About: Kodiak Oil (KOG)

Kodiak Oil & Gas Corp. (NYSE:KOG)

Q2 2013 Earnings Conference Call

August 2, 2013 11:00 ET

Executives

Lynn Peterson - Chairman and Chief Executive Officer

James Catlin - Executive Vice President, Business Development

Jimmy Henderson - Chief Financial Officer

Russ Branting - Executive Vice President, Operations

Analysts

Brian Corales - Howard Weil

John Freeman - Raymond James

Brad Carpenter - Wells Fargo

Welles Fitzpatrick - Johnson Rice

Hsulin Peng - Robert W. Baird

Ryan Oatman - SunTrust

Mark Lear - Credit Suisse

David Deckelbaum - KeyBanc

Will Green - Stephens

Kyle Lutkewitte - Iberia Capital Partners

Gail Nicholson - KLR Group

Paul Grigel - Macquarie

Adam France - 1492 Capital

Kent Gren - Boston American Asset Management

Operator

Good morning. My name is Stephanie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Kodiak Oil & Gas Corp. Second Quarter 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 answer 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. Good morning everyone. As always we’ll take your questions at the end of this call. Before we begin, let me introduce the members of the management team that are on the call today, James Catlin, Jimmy Henderson, Russ Branting and two recent additions to the Kodiak team, Aaron Gaydosik and Trevor Seelye. We appreciate your time this morning to discuss our second quarter results. We have just closed another active quarter which has seen us grow our company in nearly every category. Please reference the news release and our filing on Form 10-Q for more details and full disclosure of the topics we are discussing today. Both of which were made available last evening.

We reported fully diluted GAAP earnings per share of $0.17 for the quarter ended June 30, 2013. We also reported adjusted EBITDA of $131 million for the second quarter driven by oil and gas sales of $173 million. Last week in our operations update, we operated oil and gas equivalent sales volumes for the period ended June 30, 2013 of $2.1 million BOE representing 8% growth from the previous quarter ended March 31, 2013 and an 83% growth over the same period ended June 30, 2012.

Our average daily sale volumes increased 23,200 BOE per day in the second quarter from an average of 21,700 BOE per day in the first quarter. Our production continues to increase which we will get into more detail later this morning on the call. Crude oil accounted for approximately 94% of revenues reported in the period. During the second quarter 2013 we invested 249 million on drilling and completion operations related infrastructure and lease hold acquisitions. We spent 204 million on our operated properties, 35 million on our non-operated properties and 9 million on infrastructure and acreage acquisitions. Through the first six months of the fiscal year we’ve invested 505 million on drilling and completion operations, related infrastructure and lease hold acquisitions. In June 2013, we announced the acquisition of approximately 42,000 net lease hold acres in the Williston Basin which brings our total net acres in the basin to nearly 200,000 net acres. We closed the transaction on July 12 and are in the process fully integrating these properties into our operations. The proximity of the acquired properties to our existing assets combined with our experienced integrating similar acquisitions has helped facilitate a smooth transition. We’re working to high grade our portfolio as we move forward and I’ll try to give you a little more detail on that later on the call when I rejoin.

At this time I’ll turn over to Jim Catlin for some operational comments followed by Jimmy Henderson our CFO who will hit on some of the key financial points and then Russ Branting who will discuss the progress on our well density pilot projects. Jimmy.

Jim Catlin

Thanks Lynn and good morning to everyone. We made some good progress operationally in the second quarter and work methodically to set ourselves up for a dramatic acceleration in activity and production in the second half of the year. Following the closing of our most recent acquisition we are again running a total of seven operated rigs and we expect to maintain that rig level through the remainder of the year. We’re firmly utilizing two full time completion crews; we picked up a second crew during the quarter and intend to utilize that second crew throughout the remainder of the year. In July, we also used a third completion crew to complete some wells that were acquired in the latest transaction. During the quarter in the June 30, 2013 we completed 25 drills, 21.5 net operated wells. We also participated in the completion of 2.5 net non-operated wells.

With our current completion schedule we expect to complete approximately 29 net wells in the third quarter including 25 operated and four non-operated wells compared to 24 net wells in the second quarter and 18 net wells in the first quarter. At this time let me turn the call over to Jimmy Henderson.

Jimmy Henderson

Thanks Jim. Thanks everybody for joining us this morning. During the second quarter 2013 we saw a slight decline in oil price realizations as the average differential in the quarter expanded to about 5.50 per barrel from WTI pricing. As WTI trading in the $100 per barrel range continue to experience some very solid economics from our drilling program with cash margins nearing $60 per BOE. We continue to maintain an active hedging program to take our capital budget with approximately 21,000 barrels per day hedged for the second half of 2013 mostly through swaps with an average price of around $96 per barrel. We have also hedged about 16,000 barrels per day for 2014 also again through swaps at around $92 per barrel.

As Lynn mentioned earlier on July 12, we closed on the acquisition of additional properties. Following post-closing adjustments for the March 1 effective date, we have paid around $732 million to the seller and including about $31 million of working capital. The transaction was fully funded through borrowings under the company’s revolving credit facility and in conjunction with the closing of the transaction and reflecting our legacy activities year-to-date. We and the bank group amended the credit facility to increase the borrowing base to 1.1 billion from the previous 650 million. Also last week we announced the senior notes offering after seeing strong interest from the investment community, the offering is upsized from 300 million to 400 million and price to yield 5.5%. This transaction closed on Friday and proceeds were used to pay down a portion of the borrowings outstanding under the revolver. In connection with that notes offering, our bank syndicate works with company and agreed to waive the callback provision that would have otherwise reduced the borrowing base. So, upon closing the bond offering, revolver balance was around $600 million with about $500 million available on that line.

As always, we appreciate the strong banking relationships and the efforts of the bank syndicate and investment banking community in getting all of these transactions accomplished in a timely manner. Now, we believe our balance sheet and liquidity are in great shape with availability under our revolver and continuing increase in our operating cash flows, we believe our CapEx program is funded through remainder of 2013 and on through 2014.

Now, shifting to our well density pilot projects, I will turn it over to Russ Branting.

Russ Branting

Good morning. Since we last spoke in early May, we have made significant progress with our two pilot projects. To remind everyone, we are testing the two down-spacing programs in two areas. In both areas, we have drilled the middle Bakken wells approximately 800 foot apart, which allows for six wells to be drilled in the 1,280 spacing unit. We have also placed six wells in the Three Forks, the same distance apart. However, the wells were drilled on an alternating sequence between the upper and middle intervals. Four wells were drilled from three separate pads. This type of spacing equates to roughly 200-acre spacing for wells drilled in two separate formations.

In our Polar area, in Williams County, we have completed all 12 wells in the pilot program. In the last night’s release, we provided initial rates for the polar wells, which we believe to be very encouraging. That said, it is still early and we caution everyone the use of this data. We would like to see at least six months of data before making any definitive conclusions. We have completed a total of 331 stages in all 12 wells, with the (inaudible) volume of 41 million pounds on an average of 28 stages per well in an average of 3.4 million pounds per well. The average initial production rate for the 12 wells was 22,550 barrels of oil equivalent, which is consistent with our other Kodiak operated wells in the area. We have modeled infinite connectivity fracture happenings of approximately 135 to 153.

As we previously mentioned, we also included micro-seismic work around pilot program and the data obtained is currently being processed along with the core evaluation. We expect most of this work being completed later this year. Again, I would like to reiterate that the producing time of these wells is too short to make any meaningful judgment or evaluate the thirst of the increased lateral density. Our evaluation of increased lateral density in the Middle Bakken and the Three Forks will continue through the next several quarters. In McKenzie County, where the Smokey pilot program is located, we have drilled all 12 wells and a total of 8 wells have been completed. The remaining 4 wells should be completed in the third quarter. The two pilot programs represent about a quarter for the operated drilling program and the information gained from the two pilots will have a significant impact on how we lay out our future development programs.

With that, I will turn it back over to Lynn.

Lynn Peterson

Thanks, guys. Clearly, we are excited about the early results from our down-spacing. As we get more clarity on the production, we can then start to project impact it will have on the company’s drilling inventory. I think it’s safe to say that we are comfortable telling you we currently have more than 10 years of drilling inventory and that number has a good chance to increase significantly.

In addition, we are pleased to close the transaction to acquire the additional lands that were announced earlier. These acquired properties did come with a higher percentage of non-operated interest than we typically like to own. That said, we have been working diligently since a transaction was closed to high-grade properties and increase our operated interest. That work includes efforts to sell-down our interest in certain lands, swapping non-interest, for interest in our operated units, and the acquisition of additional interest in our operated units throughout the basin. There are a lot of items in the par at this point, but what can I report today is that we are making great progress on this transaction. Our land team has successfully reached a couple of agreements and has closed on one deal earlier this week to increase our working interest in some of our Dunn County acreage to 100%.

When all of the dust settles, we hope to keep our net acreage in the basin at a similar level to what it is today, where we want to have a more consolidated higher working interest position, which lead to more efficient development and better operational and capital visibility. I was asked by some callers last evening to give some color on these transactions. I’ll tell everyone it's way too early to predict our ultimate success and what it means to production, divestiture dollars, and acreage numbers. I would ask for your patience as we move through these items. Next I would like to give you some thoughts on our production, projections for the second half of the year. With the ongoing property clean-up I would caution that there are lot of moving parts so please bear with us for a good time.

Last week we announced revised production forecast of 2013 will range at 30,000 to 34,000 boe per day. We also announced that current production was approximately 34,000 boe per day. As we look at this current level of production our legacy production grew with our expectations and we gained the benefit of the production from the acquired properties for only the second half of the month.

Based upon our current production rate plus acceleration and completion activities noted earlier for the remainder of the year we believe we’re on track to meet our 2013 production forecast. Turning to our capital expenditures I’ll talk about where we’re today and how we do our capital investment over the rest of the year. In conjunction with the updated production guidance last week we announced to revise CapEx budget for the year of upto $1 billion. We currently expect to complete approximately 100 net wells in 2013 and that includes wells completed on the acquired properties. We have run our budgets using the assumption of $90 WTI less $7 differentials.

With oil currently occurring (ph) at above $100 and a strong hedge book we feel very comfortable with the budget where it stands and think we should achieve significant growth at this levels investment. Finally but certainly not lastly we have continued to add significant manpower to our team. We have recently brought on the new production format for our Williston district that will be responsible for operations and properties located in Southern Williams County as well as some of our Northern Mckenzie county properties.

For those in the financial community I would like to note the additions of Aaron Gaydosik and Trevor Seelye to the Kodiak team, both Aaron and Trevor will be joined in the finance team and bring strong backgrounds and experience in capital markets and they will be actively engaged with the investment community. We invite all of you to reach us them independently. With that we want to thank our listeners for joining us on the call. I’ll now turn it back to the moderator and we will be happy to take your questions at this time.

Question-and-Answer Session

Operator

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

Brian Corales - Howard Weil

Couple of questions, are you all planning on doing four well pads, it's kind of the standard going forward?

Lynn Peterson

Brian I would tell you that it's going to be in most case it will be four well pad or more. We still got a few three well pad, we have been drilling but I think as we look at on a go forward basis we’re leaning towards the four. It seems to work well both on the drilling side and certainly at our completion work. We got a dam now with a simple tracking, given four wells completed kind of in the 15 to 20 day range. So it's working well for us.

Brian Corales - Howard Weil

And then with the recently acquired assets is that production? I think I can’t remember it's 4500 or 5000 barrels a day? Is that relatively stable or has that been declining? I mean where is those operations stand today during that period from the announcement to closing, has the production declined or did operations continue?

Lynn Peterson

They have been pretty stable, I think as we reported the June production average around 5500 barrels boe per day. They have got one rig running or they have had one rig prior us taken over so it's been pretty steady. We recently completed a couple more wells over there that will be coming on production here in August, so now we’re pleased with those numbers I think they are pretty good.

Brian Corales - Howard Weil

And then one final question more for modeling, current realizations I mean you talked about a $7 differential. Can you may be tell about what that differential is to TI that you’re seeing kind of recently?

Jimmy Henderson

Yeah I think that well in second quarter, as I said, we averaged I think 550, but its (inaudible) were that first quarter and early second quarter was pretty tight with pretty good differential between Brent and WTI and that starts, it’s widened a bit since then. Going forward, probably more in that kind of $7 to $8 range, kind of what we are seeing right now?

Brian Corales - Howard Weil

Okay. Alright, guys. Thank you. A good quarter.

Lynn Peterson

Thanks, Brian.

Operator

Your next question comes from the line of John Freeman with Raymond James.

John Freeman - Raymond James

I was trying to get little bit more specifics on an update on the saltwater disposal wells, I think last quarter you all were up to 10 or 11 that have been drilled and right half of those that were actually operational just where that stands now?

Lynn Peterson

Yes, John, good morning. I think all of the wells that we drilled are operational at this point. We are continuing to work on connecting them to the individual pipelines. That’s an ongoing process that we hope to have pretty much completed here in third quarter. Russ, is there anything you would like to add to that?

Russ Branting

I think we should have most of the SWD saltwater gathering by probably the end of third quarter or first and fourth.

Lynn Peterson

Okay. And we certainly saw it in our LOE, we are still tracking a fair amount of it, but we are tracking at a shorter distance, which is helping us bring down our cost. And we believe we’ll see a little more reflection of that as we go through that the rest of the year here.

John Freeman - Raymond James

Okay. And then just last one from me, Lynn, obviously, we have talked a lot in the past about how the completed well, the cost that you all show is not just a completed well cost, but it’s a cost equipped to wells go into production etcetera. I am curious if you could just sort of break out what’s just the actual completed well cost is? So, it makes a little bit better of an apples-to-apples comparison with some of your peers?

Lynn Peterson

What I think, and Russ correct me if I misspeak here, what I think when we looked at drilling a well we are kind of in that $3 million range, there may be $3 million to $3.2 million that would have a liner in the hole, fully cemented liner in the hole. As we look at our completion side of it, I think it typically is going to run maybe in that $6 million to $6.5 million range. So, I think if we look at just to drill and complete without equipping, we are probably in the $9 million to $9.2 million range.

Russ Branting

Absolutely.

John Freeman - Raymond James

Perfect. That’s very helpful. I appreciate you guys.

Russ Branting

Alright. Thanks John.

Operator

Your next question comes from the line of Brad Carpenter with Wells Fargo.

Brad Carpenter - Wells Fargo

Hi. Good morning, everyone.

Lynn Peterson

Good morning, Brad.

Brad Carpenter - Wells Fargo

Just a couple of quick ones, I guess the first one will be for Jimmy, it sounds like you are pretty comfortable with your current levels of liquidity where it’s at, but as we look over the 18 months, how should we think about the borrowing base moving as you work through CapEx over the next or through the 2014, I guess?

Jimmy Henderson

So, yes, I think definitely the borrowing base will continue to increase. We did add four banks to our syndicate with the closing on the Liberty acquisition, a related increase in the borrowing base, and all of these banks – all 16 banks have significant capacity to continue to grow why we have chosen to have them in the syndicate. So, we do certainly expect it to grow at a pretty good rate through the year, through foreseeable future. Now, as I pointed out earlier really with just the current availability and increase in cash flows, we are very comfortable with our liquidity position, which certainly as that borrowing base grows beyond where it is now, it’s even more of a cushion for us, what’s correct order for the future.

Brad Carpenter - Wells Fargo

Okay, great. And would you look to term out any more of your revolver balances, markets remain open later this year?

Jimmy Henderson

Yes, not at this time, like I think as we look into 2014, we want to have the ability to reduce our debt, and so we will probably keep pretty good portion of it variable, and on a shorter term type facility.

Brad Carpenter - Wells Fargo

Okay. And so status quo, I guess no additional large acquisitions, you don’t feel the need to issue any more equity at this point, is that a fair statement?

Jimmy Henderson

That is a fair statement. We are not planning any equity at this point.

Brad Carpenter - Wells Fargo

Okay. And then just my second quick one would be either for you Lynn or maybe Russ, just curious as far as your expectations for differences in well performance between the middle and upper Three Forks as you work through these Polar and Smokey pilot project.

Lynn Peterson

You know Brad we’re probably going to ask for a little bit of time you know as we, we have some data out of this the wells and just completed and this is really our first chance to have the well side by side. We’re seeing a lot of similarities, again as we get more information to see if they are really separate intervals or are we just dealing with a larger tank (ph) here, I think we’ve been pretty clear to we’re not convinced either separate (inaudible) we think we’re seeing communication between the two intervals and thus I think we’re seeing pretty similar production at least in the near term, rest you want to add anything?

Jim Catlin

No we just need to have some time so we can give it (inaudible) these wells IP (ph) wells and little comparable other four prospects. Right now everything works well.

Lynn Peterson

And the thing will well is through that is our micro seismic evaluation and we will get some early information that we truly we need probably another 60 days to try to circle the ranking.

Jimmy Henderson

Well yeah obviously the micro seismic is a key component determining exactly where the fracs flow horizontally and vertically and we’ve seen some preliminary data but it takes couple of months to process and interpret all of it so we’re little ways away from having anything yet.

Operator

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

Welles Fitzpatrick - Johnson Rice

Am I spotting the two lower three forks test correctly, are those early to that didn’t have any issues to 16H 3B and the 14H3 (ph).

Lynn Peterson

Welles I’ll be honest with you I don’t have the math in front of me here. You know the one that had the smaller IP it was a plugging issue that hole, we didn’t want to take the time to rig down and clean it up with a point when we put on production it's doing very nicely now we have got it all cleared up and everything is moving ahead. You know if want to ping us back after the call I would like to cut a forward map and go through the individual wells. Again I think it's gross I will say that when we look at the up and middle wells right now we’re not seeing great differences and they look very similar and again at this time I think we still believe these are in communication that we’re accessing reserves from the two intervals when we complete our wells.

Welles Fitzpatrick - Johnson Rice

I guess was the communication that you saw between the Bakken space at 800 feet was that similar to what you saw with the three forks even with the Chevron pattern or was there a difference there?

Lynn Peterson

We’re just having streaming of communication between, Welles, you’re going to get a traction once in a while and things are going to run along but as far as when we did each of the stages trying to repressure in the offsetting wells we really did not see much in the way of communication. Again this is all early day and we do want to be careful here and reiterate that we need a bit of time here to see others work from a pressure drawn (ph) standpoint.

Welles Fitzpatrick - Johnson Rice

And then one last one, how applicable I mean I would assume after you had the Polar and Smokey test that you would be pretty well honed in on Koala at is that an accurate statement?

Lynn Peterson

We’re, I think as you look at it honestly Polar, Koala they are same acreage I guess didn’t get prospect and interest in the South of the river and North of the river. So, we look at those fabulous acreage I think all of the wells we drilled through the beginning I think in 2010 forward a little bit that (inaudible) type production number. Yeah it's working great I know.

Operator

Your next question comes from the line of Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird

So my first question is regarding the (inaudible) divesting and saving from non-core properties. I know there is a lot of lean pieces still but overall should we anticipate a cash inflow or not capital outflow I think. Is that correct?

Lynn Peterson

Hsulin, as I said, we have a lot of things going on right now. And we are trying not to make judgments one way or another. Clearly, we are trying to work within our capital restructurings or as we see it we are trying to keep this clean. We have only had the properties for roughly two weeks. I think we have been very pleased with the reaction to our proposals. So far, we are certainly right on guide where we want to be. So, again, I am going to hold you off. I am not going to – we are not going to put numbers out there. We will bring everybody up-to-date as we move along here.

Hsulin Peng - Robert W. Baird

Okay, that’s fine. And then second question is I guess fast forward, I know you mentioned you want to see I guess with another six months to see the production data on Polar, and I guess I am trying to kind of gauge as to what do you need to see and what is the next step after you see the 180 days in your production data?

Lynn Peterson

Jim or Russ, why don’t you – again, we just need some time. We can’t stress that enough. You guys wanted to…

Jimmy Henderson

Lynn, I’ll take a little step with answering. And I think we have kind of already answered it really. And it’s not 180 days isn’t the magic number, that’s just kind of the guess. What we want to see is we want to watch the wells. See if we see any unusual pressure draw-downs or anything that doesn’t fit our normal pattern. And obviously, at this point, we think this is going to work fine or we wouldn’t have drilled the 12 wells in the spacing unit, but until we see some production data, we want to be a little careful in making statements that this really works or doesn’t work, but over the next few months, we’ll get more information. And if we don’t see anything unusual in the press release sponsors and production draw-downs, then we’ll move ahead.

Russ Branting

We just need some time to actually do the engineering part, where we have raw production data. We can tune in our historical – history matches. We can run our stimulators. We tie everything back to our well – pilot well in that section. And then we got to get the data from pilot wells, so we can (inaudible) it’s all going to take a matter of time. So, if you just – could just give us some time or we are working diligently and we’ll have some answers.

Hsulin Peng - Robert W. Baird

Okay, that’s fair. And then a last question is, I don’t know if you can kind of help us out, but in terms of the – of the production ramp in the section half of ‘13 was – I mean, I know it’s going to be lumpy, but with Smokey coming – if you guys completing Smokey pretty soon here, can you just kind of help us what the shape of that lumpiness in the third and fourth quarter?

Lynn Peterson

Again, Hsulin, I think I don’t really buy that’s going to be that lumpy. We’ve got two crews running. I think since we got through the end of the quarter, we have got another six wells that are just about done here. Some didn’t finish up today and the rest will be finished up next week. You are going to see a continuation of this grow. Probably one that will be linear, but I think as we look quarter-to-quarter at this point, we are clicking along on most cylinders. I think we are pretty pleased with what we are seeing from operations and we are keeping our completion crews active. We are trying to shorten the time down between move the rigs off of locations and getting our first well completed. So, again, I had that our staff and our third-party services, I think we are all working together. We are getting more efficient as we do every pad. So, I think we have laid out pretty clear to everybody where we are heading. And I don’t see any concerns at this point.

Hsulin Peng - Robert W. Baird

Okay. Well, great quarter. Thank you.

Lynn Peterson

Thank you.

Operator

Your next question comes from the line of Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust

I guess my first question would be we are seeing these initial rates from down-spacing task and to me they look good or better than recent results in the area. I mean, do you guys disagree with that characterization and can you talk a little bit about how the choke sizes and pressures on these down-spacing 24-hour rates compare with the results you reported before? Thanks.

Lynn Peterson

Ryan, this is Lynn. Yes, I think every well that we have completed since 2009 has been completed on a very similar basis. Our choke sizes have always been in similar range. Surely we change from time to time as we want a 29 certain things but all of these results are right in-line with all of our expectations and I don’t think anybody will be surprised one way or another again we give some greens to this IPs but that’s not what it really drives our operation here it's more of the production we see them at on more sustainable base. It's that we got to get 30, 60, 90 day numbers we will have a much better hand of it but I think we’re all pleased and I don’t think we saw anything unusual again Jim if you want to chime in?

Jim Catlin

Well I don’t have a lot to add is as we have lots of times it's so far it's what we have expected. As you complete wells some of them come a little stronger, some don’t but that’s just routine. They are very much exactly like what we expected.

Ryan Oatman - SunTrust

And just a quick follow-up to that, again you know I know it's early in the process so let’s just it's 6 to 9 months out from our, you declared polar counts raising successfully. In terms of implications for your other acreage I mean what do you guys see there and I guess second follow-up to that do you see areas within your current acreage positions that doesn’t seem to work or doesn’t seem like it would work for Bakken or Three Forks own facing? Thanks.

Lynn Peterson

Well I think Jim has stated there was time we tried to our property acquisitions down what we think the we got the biggest part of our hydrocarbon system, the deeper over-pressured reservoir as soon as we think about our Polar, Koala and Smokey yeah this is good acreage and what we recently acquired. As we think about I think our stuff up in Northern Williams to Dun County some stuff on the South Western side over by the grizzly area. We don’t anticipate this type of down spacing at all, again what that number is going to be is way too early to say but you know I think clearly we do anticipate it for successful here that it will cover vast amount of our acreage. Again you know we get over Dun County we file some more natural fracs than we have on the west side of the Nesson, we may get by fewer wells over there. So, way too early for projecting anything here. I think it's again we have all stated this morning this is very positive today, we’re pleased with that but we just need to get a little bit of time and then we will try to keep everybody as to what ultimately it means not only to us but a lot of the whole basin. I think I achieved for everybody out here. Does that help?

Operator

Your next question comes from the line of Mark Lear with Credit Suisse.

Mark Lear - Credit Suisse

Looking at the results from the Liberty guys and that you recently acquired and just less (ph) than you. It seems like they have delivered some really good results, I was just curious if you can talk about how they were doing things different or similar to you and are there things they have been doing that you guys would think upon. I guess there was some discussion they might have cracked some code out there and I’m just curious on your commentary on that.

Lynn Peterson

Mark as I have stated in a lot of the meetings that I’ve had subsequent to that accusation, we commend for the work they have done quite frankly I’m pretty proud and pleased with what our team is doing here. You got to be careful with the data to get out in the public filming. There is a lot of difference now, people (inaudible) how they quickly put them on top and I’ll calculate all these things. Again we think we have bought some good acreage here. We think we’re doing a good pretty job of completing wells. We also continue to look at all operators, there is a lot of good work being done by a lot of people out here right now we’re well aware of it. Our techniques are changing too. I mean we’ve changed our completion in several years, we’re pleased with some of the results. So I would probably caution you not to make too much out of any of this. I think a lot of operators, most operators are doing pretty good work here and results are pretty similar but I like what our team is doing here.

Mark Lear - Credit Suisse

That’s good, I mean that’s definitely on shot I guess there is just looking it was coming from the data, but are they doing things different from what you guys are, and then I mean not to say that you guys are not successful, because you are delivering some great well results, it’s – just seems like further less, you would expect the results not to be strong as what you have seen kind of in the center of the basin and it seems like they have kind of done better than you would have expected out that far west?

Lynn Peterson

Well, I mean, they are being completed different even more of a slick water technique or (inaudible) technique, but I think part of this is how much – how far you could reaching after these rocks and thereby having more near well bore connectivity and we are trying to get a little bit further away from the well. Again, I think there is a lot of production data that needs to be seen in all of the stuff…

Mark Lear - Credit Suisse

Okay.

Lynn Peterson

These wells are relatively new and we have access to the lot of data at this point or all the data at this point I guess. And we continue to work through it. And again, I reiterate that everybody in the basin I think is watching everybody else, I think we are all aware, things that are going on and some of the stuff does get a little bit distorted truly just because of lack of information of how these numbers are derived and put into the database. So, guys, do you want to add to this at all. Russ, do you?

Russ Branting

On the Liberty purchase, you have to be aware that we are coming out of the basin in TBDs or shallow waters. So, it depicts different design, but these are slick water design like Lynn said. We had smaller drop. They are using ISP like ourselves, we are trying to reach out further with our fracture carefully and contact more reservoir and with more fluid at the end of the day than what the Liberty design will yield, but also we just need more time to evaluate all this.

Mark Lear - Credit Suisse

Understood. And then just on the pads and I know it’s way too early, but I guess going into it, I mean is there a certain level of EUR degradation you guys would assume or I guess what’s the threshold I guess that determine success ultimately?

Lynn Peterson

Fine. I can’t express it’s enough, we just need some time. We didn’t go in this place and these are results we are going to drop a lot from our other wells. Present work is worth some dollars, but ultimately EURs is pretty important to us. So, we really didn’t feel like we were going to see a degradation of our EURs here and at least a substantial amount. Again, Mark I just plead for a little bit of time and we were yet, we didn’t want to really put these numbers out too early with our NDSC where we have to. We don’t want anybody to jump to too many conclusions, give us some time, we’ll keep everybody up-to-date.

Mark Lear - Credit Suisse

Fair enough. Thanks guys.

Lynn Peterson

Thank you.

Operator

Your next question comes from the line of David Deckelbaum with KeyBanc.

David Deckelbaum - KeyBanc

Thank you for taking my questions. Just had a couple, one I guess as you look at Polar and you have talked about doing the four well pads and larger perhaps, how do you see that design impacting your well costs going forward, and perhaps you can share what sort of the average well cost was on the first 12 in the down-spacing unit?

Lynn Peterson

Again, Kodiak was one of the early ones and not the earliest one here did pad drilling. I think we look back over the last four years of activity. We have had a handful of single wells, all of our wells have been anywhere from two to four well pads. Certainly, we see some efficiency and we see in a lot of different areas and that simple things is pushing snow in the wintertime to hold the water, but there is advantages and efficiencies. And when we have these three rigs running up there side-by-side it was an opportunity, we took full advantage of it last winter. And I think our well cost again we got to get through the quarter see where they fall, but I think we’ve been pretty clear that we believe our well costs are trending to the 9.5 range here as we go into the third quarter. We certainly got well cost down close to 9 right now depending on these and how they are completed and these type of things. It’s a good time. It’s a good time in the basin. We are seeing a lot of things happening. And I think across the board all operators are bringing their well costs down. And certainly I took my hat to our whole engineering team. They have done a great job and guys in the field are working hard and we are trying to work with our third-party services and they have been cooperating with us and we continue to tweak our completions and I can’t stress at that enough I think each of the wells we do are all different and they can’t all be thrown in one box and to treat the same. So I think we’re pretty pleased where we’re at.

David Deckelbaum - KeyBanc

I guess you stress on patience earlier and not just with you know the conclusions on what

these wells are going to do but also one production as you get in the back half of the year but also express confidence. You know how would you characterize the downtime that you would expect to experience in the back half versus perhaps what you had in the first half and certainly 2012 was a little bit different. But are you factoring in more downtime into that guidance as you incorporate the Liberty assets?

Lynn Peterson

You know guys we try to do our guidance to give you fair numbers, clearly we look at our operations historically see what our downtimes have been you know again I always tell guys we’re not here to sand bag either we’re trying to give you legit numbers. We like where we are at I think our team is doing great work as far as keeping our wells on production, understanding pad drilling how we work on these, how we try to limit shut-in time. So making progress in all these areas. I’m not going to go in specifics I will calculate everything but we tried to honor past information, we tried to honor current operations and we have tried to project where we’re heading in the future.

David Deckelbaum - KeyBanc

On the Polar pad was there, how many offset producers were there to that pad just one?

Lynn Peterson

Realistically two, we had three wells to the south and another (inaudible).

David Deckelbaum - KeyBanc

Okay and are those back online now?

Lynn Peterson

Yeah.

David Deckelbaum - KeyBanc

Are there conclusions to draw for how those wells are able to come back online after the 12 well pad is completed?

Lynn Peterson

Came back to our normal production.

Operator

Your next question comes from Will Green with Stephens.

Will Green – Stephens

I wonder if we can talk, I know we have talked a lot about the Polar pilot but did you guys tweak the frac at all to try and tighten the wings there, any color on that completion versus any polar test would be great.

Lynn Peterson

You know Will all of our wells have been completed pretty much the same here for the last 18 months.

Jim Catlin

(Inaudible) we use 28 days we use roughly 315 people stage plus or minus, we use roughly a 135,000 to 150,000 pounds in our Bakken well little Bakken wells typically our Three Forks are in the lower end of that part (ph) of our designs. We can actually work with fluids and we are not consorting (ph) out there every one what we’re doing here but I think our guys have done a great job. So minor tweaks that’s how we like to work.

Will Green - Stephens

And then we talked a little bit earlier about kind of the 9 million drill and complete you guys are seeing maybe in 1 million or 1.5 million or so on equip. If we’re that you’re seeing 12 wells per 12.80 how much of that 1 million – 1.5 million of equipment becomes kind of redundant I mean do you see costs reductions through that further cost reductions through that, any color there would be great.

Lynn Peterson

Let’s make sure we’re all clear here. I mean we have talked about $9 million to grow wells and you drill another 0.5 million bucks in certain facilities. You know sure as we get more pipe in the ground things continue to change and give more of our water disposal cleaned up.

You’re not going to see big numbers on those, they are going to be pretty consistent and again we’re making progress on our well class. Again if you look at our acreage blocks we can’t be compared to some operators in the basin that are drilling in really more shallow areas where they get than ours much pressure but these wells that we’re talking about here in 2013 are really the majority of them are drilled right down at the heart of the play, deep part of the play.

We have seen our well cost drop from 12 million down to the start talking to the mid-9s here, we’re delighted with that. We think we have got a little bit more room to squeeze. And we have brought our drilling days down dramatically. Sometimes you have some great successes and we are seeing some down in the mid-teens or slightly lower. We have also (inaudible) as you go along here. So, we are pleased where we are yet. And again (inaudible), I think that the guys are working hard to try to shade days off drilling, working with our fresh scrubbing services to try to drive down our cost in any way we can. So, our days from spud 2D for Q2 are 18.5 and then we did have a record well for clearly look at 11.5 days 2D. So, we are making great strides there. All across the board on certain class, we have seen some of our philosophy coming down significantly and we keep driving that. And no doubt the development of the play it will continue to get better. I mean, I think we are still pretty good.

The service industry has built out rapidly in the Williston. We have access to more services than probably we ever have. And not only more services, but probably higher quality, I mean everybody is getting better with their personnel and people had a time to have some continuity with all that becomes, I think you create efficiencies. So, again, it’s pretty good time.

Will Green - Stephens

Thanks for all that color, and congrats on the early success in Polar.

Lynn Peterson

Alright. Thank you.

Operator

Your next question comes from Eli Kantor with Iberia Capital Partners.

Kyle Lutkewitte - Iberia Capital Partners

Good morning. This is actually Kyle Lutkewitte on Eli’s behalf.

Lynn Peterson

Good morning.

Kyle Lutkewitte - Iberia Capital Partners

I just had a quick question. Did I hear correctly that you all aren’t looking at any other acquisitions in the near-term?

Lynn Peterson

Clearly, we are working in the Williston Basin. And we will always look at everything that’s around. We are happy where we are at. It’s all about the quality of acreage. It’s not the number of acres. We can’t say that often enough and we have been very true to our word.

Kyle Lutkewitte - Iberia Capital Partners

Okay, great. And then it looks like Zenergy has put themselves up for sale, have you seen any other packages of size that are available to buy?

Lynn Peterson

You guys see everything as much as we do so. Again, there is things going on in the basin all the time. We are not going to sit here and tell you every deal that’s available. We are aware of some things out there.

Kyle Lutkewitte - Iberia Capital Partners

Okay, thanks.

Lynn Peterson

Thank you.

Operator

Your next question comes from Gail Nicholson with KLR Group.

Gail Nicholson - KLR Group

Good morning. Two quick questions. I wanted to get an update on the Grizzly Wildrose activity, I know previously you guys have stated that you are going to do some stuff in the latter half of ‘13, I just wanted to know if that is still the plan?

Lynn Peterson

We’re true to our words, Gail.

Gail Nicholson - KLR Group

Okay, excellent. And then could you give an update on the gas infrastructure?

Lynn Peterson

Yes, I think again Jimmy chime in here, but we continue to kind of sell anywhere from 65% to 70% and some of this depend on where we are bringing these big pads on and all the pipes in the area. Yes, it’s supply capacity, it’s not well hookup. We’ve got our wells hooked up. We have done really I think a great job in that regard and again it speaks to our acreages. It’s in the heart of the play, where there is a lot of pipeline in the areas. That work has all been done. We have just got – we hope to see continued improvement on the plant side. Jimmy?

Jimmy Henderson

Yeah, I think that’s pretty much says it all. We are also getting connected and then the issues are more on the compression and pipeline capacity and then on downstream to the processing capacity. We are selling a lot more gas than every month. We sold more gas month before. As a percentage, it’s hard to make a dent in the gas flared number as we bring on additional wells and as everybody in the basin is bringing on wells. Its tough treadmill to overcome, but we are making strides and working with our third-party service providers, they are expanding their systems, trying to keep up with the activity.

Gail Nicholson - KLR Group

Okay, great. Thank you.

Operator

Your next question comes from the line of Paul Grigel with Macquarie.

Paul Grigel - Macquarie

Hi, good morning. You guys had mentioned that you are running your budget off of $90 with WTI remaining elevated above $100. What are the thoughts going forward, and just at a high level obviously there is a lot of moving parts from accelerating activity if there is a sustained crude price of above $100?

Lynn Peterson

We like where we’re at today, again. We don't have a crystal ball see what oil well is going to do, we’re as Jim in his portion, , we are going to run seven rigs and we are going to continue that activity level for the rest of the year.

Paul Grigel - Macquarie

And then turning to take away capacity obviously you saw at the well but given the compression recently between Brent and WTI , could you guys speak to just what you are seeing on the basin between pipeline and real balance from the marketing community?

Lynn Peterson

Yes, it is going to change pretty rapidly between rail and pipeline right now the market is on pipeline with reduced oil coming out of Canada with same crude turnarounds there, where the demands are right now, everybody wants to on pipe and bit off of well but rail is still moving a very significant amount of the production out of the basin that’s slightly lower margins or slightly wider differentials if you could say versus pipe but there is probably a percentage moving by rail overall hasn't changed a whole lot from what we said before is still probably two thirds of the oil.

Jim Catlin

Yes. And I'd like to applaud our marketing team here. Here they've done a good job as we ramped our production up. I think they have been able to stay ahead of our growth, they've been able to reach out to the markets where we're achieving some pretty good pricing and we do have some flexibility the way we're doing that and I think have done a great job trying to achieve those better prices.

Paul Grigel - Macquarie

Okay. And then as you guys continue to gain critical mass in the play. Is there any thought to becoming more active on the marketing front be it through contracts or longer term initiatives?

Lynn Peterson

We are growing all the way, we’re going to continue to evaluate all the stuff and again I think our group has done a really good job. We'll address all these issues as we move along.

Operator

Your next question comes from Adam France with 1492 Capital.

Adam France - 1492 Capital

Kind of a bigger picture question, look at all these basins with a horizontal development it seems like they are all 80 acre or less, do you know on spacing do you know enough about length of laterals or reservoir characteristics say the Bakken at best, the lower limit is 160 or a 100 acres spacing.

Lynn Peterson

Again we're when we look at six wells in the middle Bakken 1280 acres that gets you down to roughly 200 acres. There has been some talks, some other operators has done something’s. We've drilled some wells a little bit closer you put a 7th well and there you get it down a little bit tighter spacing. Again I guess we're just got to get some production days to see where we go but I think the Three Forks will perhaps see more questions quite frankly and there are some deeper intervals, people talked about how productivity will respond in those intervals so we'll take a little bit of time and I think that one we still have some questions on how this all is going to shake out. So you know I guess I just go back to the I think if you look at the good shale plays and there is only a handful of them there is lot of shale plays out there but I think the good ones which you guys all know are overtime, spacing has typically gotten a little bit tighter, reserves have trended upwards and cost have trended down. So I think the Bakken is definitely one of the top two or three oil plays in the America and we're pretty pleased and proud to be here.

Operator

Your next question comes from the line of Kent Green with Boston American Asset Management.

Kent Gren - Boston American Asset Management

Yes, my question have to do with this recent controversy where you supposedly put yourself up for sale could you give us a little more clarity of that one and what was rumor and what was fact?

Lynn Peterson

You know we're a public company we got our head down, we're trying to grow the company do people have interest in what we're doing absolutely I think that's a positive thing. Again, we are not going to get into all the details but we’re growing our production with that, has a come a lot of interest and what we are up to. So, we’re in the right basin and as I have told a lot of our investors over the last couple of weeks, I’d much rather have interest in what we’re doing than be up somewhere where nobody can care what we’re up to. So I think those are all positives.

Kent Gren - Boston American Asset Management

And then another question on acquiring acreage is it possible that there is still some acreage out here other than just the picking up or will you mostly concentrate on increasing your working interest as much as possible?

Lynn Peterson

Probably, there is little bits and pieces as we move along here. We are focused on trying to cleaning up our working interest and (indiscernible) will stay over and over this package. It was different than what we have typically done. And we are trying to get our staff. We want to drill high working interest wells. So, we utilize our staff’s time and I think that’s our focus. And clearly, we always look to high-grade our portfolio. We are trying to move where we see reserves. We think are positive also just from an infrastructure standpoint. We want to be where we can control what we are doing and get us oil on the pipe, get it to markets, get our gas and the gas plants, get a water disposal. So, I think having the blocked acreage that we have, I think it’s been really important to go yet. I kind of think it’s allowed us to do some things a little bit quicker than maybe some of our other operation in the basin did because of their scattered nature of our acreage. So, nothing has changed. We are just continued on doing more what we have been doing for last five years.

Kent Gren - Boston American Asset Management

Finally, probably for Jim, the retired Chairman of Enron Oil and Gas claims we’re not going to have any oil glut from the shales like we have a gas glut, because he says, the rock is so dense and obviously these things are going to be levered and then getting 8% of the oil out of the reservoirs, you have any comment on that?

Lynn Peterson

I think we are still some of this work– we are going to have a lot better feel. We have been doing a lot of work on oil and plays numbers try and see what this down-spacing does, what kind of recovery we are going to get out of this. There is a lot of unanswered questions. I think to all these plays at this point, but I think as it’s pointing in positive direction and Jim, go ahead.

Jimmy Henderson

Well, yes, I am not sure that we really know yet what our percentage recovery is. Like Lynn said, it’s a little difficult to actually figure out exactly how much oil is in here to start with. We’ve got oil in the shales and these are hard things to calculate, but as far as whether we are going to have an oil blood or not, I am not sure whether we are qualified to try to answer that. We see a great market for Bakken crude as far out as we can see, then you really – that’s really what we are concentrated on and where we are headed.

Kent Gren - Boston American Asset Management

Finally, one final question, you’ve always said you are going to have separate wells into the Three Forks and the Bakken. Is there a major breakthrough sometime in the future or you will complete the well in the lower formation to look at up, but then bring it back up be able to complete it in the upper formation or will the continuous small amount of oil after these wells fall off make that still economical to start with a new well?

Lynn Peterson

Yes, I think one of the deals think about our industry, the technological advances are – have been very rapid. I think we continue to see changes. There was an unnamed company that tried that procedure. It didn’t work out to understand. So, I can tell you near-term, I don’t see Kodiak doing it and again technology changes, prices change, everything changes. So five years, I will remind you that this play wasn’t even around seven years ago. The first well was drilled in 2006 during the stage completion. So, it’s a relatively short timeframe. We have come a long way. So, I think technology will advance again. And then I took my hat to all the research that goes on and all the tools that are developing. It’s remarkable what we can do today that we couldn’t do few years ago, and we think about that when our rigs, the changes in drilling rigs have been remarkable and that’s continued to advance quickly, so.

Kent Gren - Boston American Asset Management

Thank you. Great quarter.

Lynn Peterson

Thanks, Kent.

Operator

At this time, there are no additional questions. I will turn it back over to Mr. Peterson for closing remarks.

Lynn Peterson

Thank you. At this time, I would like to extend a big thank you to all of our employees. Everyone continues to show great dedication and loyalty to our company. Our entire staff is excited about our continued operational ramp up here in the second half of the year and everybody's working extremely hard to achieve the goals we have set forth. Without a doubt this is a very exciting time to be a bear in the Williston Basin, we’re experiencing some very robust oil prices. We have seen the infrastructure build out, we're seeing our cost trend downward. And lastly we’re starting to see some early results from down spacing and they are both pretty promising for the future.

We'd like to thank all of you for your time this morning and your continuing support at Kodiak. We'll be back on the conference circuit here in the next few weeks as well as meeting many investors on the road. I'd like to wish all you a great weekend and thank you very much.

Operator

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

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