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Kodiak Oil & Gas Corp. (NYSE:KOG)

Q3 2013 Results Earnings Call

November 1, 2013 11:00 AM ET

Executives

Lynn Peterson - Chairman and CEO

James Catlin - Executive Vice President, Business Development

Jimmy Henderson - Chief Financial Officer

Russ Cunningham - Executive Vice President, Exploration

Analysts

Brian Corales - Howard Weil

Hsulin Peng - Robert W. Baird

David Tameron - Wells Fargo

Michael Hall - Heikkinen Energy Advisors

David Deckelbaum - KeyBanc

Eli Kantor - IBERIA Capital

Jeffrey Campbell - Touhy Brothers Investment Research

Operator

Good morning. And welcome to the Kodiak Oil & Gas Third Quarter 2013 Financial and Operating Results Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. (Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Lynn Peterson, Chairman and CEO. Please go ahead.

Lynn Peterson

Thank you and good morning to everyone. I hope everybody has recovered from Halloween last evening. As always we will take question but (inaudible) before we begin, let me as always introduce our members that are going to participate in the call this morning, James Catlin, Jimmy Henderson and Russ Cunningham.

We have disclosed both on another record quarter for Kodiak. The solid company produced more oil and generates more cash than we have in our history, while also adding meaningful way to our drilling inventory through our downspacing programs and property acquisitions.

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 which were made available last evening.

We reported fully diluted GAAP earnings per share of $0.12 for the quarter ended September 30, 2013. We also reported adjusted EBITDA of $214 million for the third quarter driven by oil and gas sales of $300 million.

Last week in our operations update, we reported oil and gas total sales volumes for the period ended September 30, 2013 of $3.3 million barrels of oil equivalent. It’s represented 54% growth from the previous quarter ended June 30, 2013 and 123% growth over the same period ended September 30, 2012

Our average daily sales volumes increased to 35,400 barrels of oil equivalent per day in the third quarter from an average of 23,200 barrels of oil equivalent per day in the second quarter. Our production continues to increase which we will get into a more detail later this morning on the call.

Crude oil accounted for approximately 96% of revenues recorded in this period. During the third quarter 2013, we invested $305 million on drilling and completion operations related to -- related infrastructure and lease hold acquisitions. Through the first nine months of the fiscal year, we have invested approximately $800 million on drilling and completion operations, related infrastructure and lease hold acquisitions. In July, we closed the acquisition approximately 42,000 net lease hold acreage in the Williston Basin which brought our total net acres at that time to nearly 200,000 acres.

At this time, I am going to turn the call over to Jimmy Henderson, our CFO, who will hit on some of the key financial points. He will be followed by Jim Catlin and Russ Cunningham for some operational comments and discussion of some of the progress on our well density pilot projects. Jimmy?

Jimmy Henderson

Thanks Lynn. Thanks everyone for joining us this morning for our quarterly call. During the third quarter of 2013 we saw a healthy improvement in our oil price realization as WTI remained approximately $100 level for most of the quarter. The average differential in the quarter expanded to about 7.50 per barrel from WTI pricing, bringing our netback prices to the high $90 per barrel level. With that realized price, we continue to experience very solid economics from our drilling program with cash margins around $70 per BOE.

Historically, October, November are months with scheduled refinery maintenance and low finished product margins and as such -- as a result, we expect to see the differential from WTI widen in the fourth quarter to something around the $12 to $13 range. We continue to maintain an active hedging program to protect our capital budget with approximately 23,000 barrels per day hedged for the fourth quarter of 2013, mostly through swaps at an average price of $97 per barrel.

With the increase in crude prices, we also acted opportunistically this quarter to add about 8,000 barrels per day of hedges to our 2014 book and now have about 24,000 barrels per day hedged next year, mostly through swaps priced around $93 per barrel.

During the fourth quarter, we successfully completed a notes offering that was upsized to $400 million and price-to-yield 5.5%, with the proceeds going to pay down a portion of the borrowings outstanding under our revolver facility. At this time, we are currently undergoing a semi-annual redetermination with our bank group to update the borrowing base under our existing credit agreement. As a reminder, following our mid-year reserve review and July acquisition, we increased our borrowing base to $1.1 billion from a previous $650 million. While we are still on the redetermination process, we do expect an increase in the borrowing base again, as a result of our drilling program since the [last drilling].

The current revolver balance is about $680 million. So we have about $420 million available before the ongoing re-determination. We continue to believe our balance sheet and liquidity are in great shape with availability under our revolver and continued growth in our operating cash flows, we believe, the necessary funding is in place for the remainder for the year and 2014.

Now shifting to our operations, I'll turn the call over to Jim Catlin and Russ Cunningham, and Jim can start.

James Catlin

Thanks, Jimmy and again good morning everyone. I am pleased to say that we carried the operational momentum from the second quarter into the third quarter and so our continued success from our drilling and completions programs. Before I get into our third quarter results, I would like to quickly run through some of the significant changes we have seen in the Williston Basin over the past eight years.

As we look back at the drilling history of Kodiak, we've operated 194 gross wells since stage completion technology was introduced into the basin in 2006. Our very first two wells were drilled on a two well pad in Dunn County in 2008. Of the total 194 gross operated wells since inception, seven have been drilled on single well pads with the remaining 187 gross wells being drilled on multiple well pads. Today we are primarily drilling on four well pads with a few six well pads scheduled for 2014.

During this time period, we've seen drilling days come down from the mid 30 days per well to under 20 days with our quickest wells drilled in under 15 days. We are currently able to drill 13 to 14 wells per rig during a calendar year's time compared to eight to nine wells when we began drilling in the basin in 2008. There continues to be much advancement in completion technology in the basin. In our opinion, nobody has the one magic completion formula. Completion technology continues to advance and change with different methods used suited to different parts of the basin.

Kodiak has always been a believer in ceramic proppant and we continue that same belief today due to the location of the majority of our acreage, which is typically in the deeper and higher pressure parts of the Williston Basin. As we get to the edges of the play, where a small portion of our leasehold is located, the Bakken petroleum system is shallower and lower pressured and in those areas, we change to a mix of white sand and resin-coated sand or in some cases just white sand.

Initially in 2008, we began drilling 5,000 foot laterals that were segmented into separate intervals of approximately 800 feet using swell packers and utilizing sliding sleeves. As we shifted to the 10,000 foot laterals in 2009, we moved to a hybrid type of completion, utilizing both sleeves and plug-n-perf operation and condensed our stages to approximately 600 feet per stage. We also began using mechanical packers during that time.

In early 2012, Kodiak moved to cemented liners and started using all plug and perforation completion with each stage being approximately 325 feet. As we’ve gone into larger pads and more stages, we have utilized the technique referred to as a zipper frack for we can be setting a plug and perforating in one well while we are pumping a frack stage in an offsetting well, which eliminates the significant amount of downtime.

To illustrate the time-savings and efficiency gains, one well will take approximately 7 to 10 days in the early days where now we can routinely complete four wells in 15 to 20 days for an average of four to five days per well. I mentioned all of this to show everyone the developments that have assisted in lowering our cost and improving our performance.

In our opinion, this basement still has more room to run in both more efficient drilling as well as enhancements and completion methods. We believe our cost and performance will continue to improve.

Moving along to our current operations, we continue to run a total of seven operated rigs and expect to maintain that rig level to the remainder of the year. After releasing our second full time completion crew in early September, we re-engaged that crew in mid-October and planned to utilize the two full times crews through the remainder of the year. During the quarter-ended September 30th, we completed 29 gross and 24.5 net operated wells and participated in the completion of 6.6 net non-operated wells.

With our current completion schedule, we expect to complete approximately 25 net wells in the fourth quarter, including 21 operated and four non-operated wells, which compares to 18, 24 and 31 net wells completed respectively in the first three quarters of this year.

At this time, I’ll turn the call over to Russ Cunningham, who will discuss in some detail our downspacing programs.

Russ Cunningham

Thank you, Jim. Good morning everyone. I’m pleased to report that we continue to see positive performance indicators in our downspacing pilot programs and feel we have made strides towards determining the optimum development plan for our assets in the space. However, we will continue to test ideas as I will touch on later.

To remind everyone listening, we are testing downspacing programs in two areas. In both cases, we drill the Middle Bakken wells approximately 800 feet apart, which allows for six wells to be drilled in a 1,280 acre drilling unit.

We also placed six wells under Three Forks, which we drilled on an alternating sequence between the upper and middle intervals. In early third quarter, we brought all 12 wells on our Polar pilot program onto production and reported initial production rates to the market in August.

We continue to be pleased with the individual well performance in this DSU and still have not seen anything that would indicate the increased well bids that has adversely impacted production from the individual wells. As we evaluate these wells after 90 to 120 days production and compare to eight other wells in the immediate area that were completed in the similar manner, we find well results are very comparable.

We are currently drilling two Middle Bakken and two Three Forks wells based approximately 600 to 650 feet apart in the DSU located immediately to the east of the initial Polar pilot project. We have applied for additional permits in this DSU to test the titer spacing over a full DSU. This spacing pattern results in up to eight wells drilled in both the Middle Bakken formation and the Three Forks formation within the DSU.

As we drill out this DSU, we intent to place at least one Three Forks well into the lower portion of the formation to test commerciality of the entire Three Forks interval. As potentially, total of 16 wells per DSU, which is quite remarkable considering it was not long ago, we believe seven total wells could be the optimal well spacing.

It’s important to note the well spacing is probably not uniform across the entire Bakken, Three Forks play area. About 28 miles to the South in our Smokey prospect, we brought the final seven wells of our 12 well pilot program onto production recently and posted the initial numbers in our new release a week ago.

The average initial production rate for the 12 Smokey wells was approximately 2,000 barrels of oil equivalent, with 30 day rates averaging approximately 800 barrels of oil equivalent per day, both of which are consistent with other Kodiak operated wells in the area.

Again, we have evaluated other wells drilled in the same area and completed in the same manner. We do not see degradation of the production. As we have said before, while we're encouraged by the initial results in both projects, we would like to see at least six months of production data before making more definitive conclusions. Through these two downspacing tests, we've also tried to evaluate how to optimize our development program and drill-out program.

From our early results, it appears that we can gain well cost efficiencies and stimulation effectiveness, by drilling out entire DSUs at the same time. Our evaluation of the increased well density in the middle Bakken and the Three Forks will continue through the next several quarters.

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

Lynn Peterson

Thank you, Russ. Third quarter of 2013 was a very exciting quarter for the [Bearden]. We delivered impressive production growth and continued to be one of the industry leaders in proving out downspacing in the basin, which should lead to increased drilling inventory. Third quarter production of 35,400 BOE per day was a new record for Kodiak.

We closed on our recent acquisition during the third quarter, which added a high quality drilling inventory and production to our core Williston position. However, I think it is important to stress that production for the quarter, excluding the production from the acquired properties, was 30,700 BOE per day, which implies organic quarter-over-quarter growth of 7,500 BOE per day. I'm very proud of our team for achieving this feat, all while integrating the new assets.

As Russ alluded to earlier, we believe these pilot programs will help determine an ultimate development plan of our nearly 200,000 net acres in this play. Because you only get one shot at development, we felt these tests are critical to the future of the company and must be done in the near term. Once we feel comfortable with the optimal development spacing, we can then start to project the impact it will have on the company's drilling inventory, which we ought to be able to communicate in the coming months.

We have been working diligently since our acquisition transaction was closed in July, to try and high grade properties and increase our working interest. To date, we have completed transactions to sell down our interest in certain lands, swapped non-op interest for interest in our operated units and acquired additional interest in some of our operated units. We feel that this process has been very successful so far and continue to work on a number of potential transactions that will allow us to core up and consolidate our position.

To give you a little more detail, today we have closed on six transactions, which have led to a net divestiture of approximately 3,700 net acres and broadened net proceeds of approximately 14 million. We have agreements on a couple of other deals and hope to finalize those in the near future. Following these deals we will have a more consolidated, higher working interest, which will lead more efficient development and better operational and capital visibility.

Next, I would like to give you some thoughts on our production and the capital expenditures for the remainder of the year. Last week we announced a tightened production target for 2013 of approximately 30,000 barrels of oil equivalent per day. We also announced that we expect a full year exit rate of something close to 42,000 BOE per day. Based upon our current production rate, coupled with the return of our second completion crew in mid-October, we believe we are on track to meet these production targets.

Turning to our capital expenditures, we reported a total spend of approximately $800 million for the nine months ended September 30, 2013. We expect to spend somewhere in the ballpark of $1 billion for the entire year. Our fourth quarter expenditures should be lower than the third quarter expenditures, due to a lower pace of our non-operated completions resulting from a lower rig count on the non-operated properties, continuing decline in well costs on a quarter-over-quarter basis, and lastly, our overall working interest for wells completed in the fourth quarter is less than those completed in the third quarter. We’ve continued to add significant manpower to the Kodiak team and are very pleased to be adding the level of technical skill and expertise from our recent hiring.

I know many of you are interested in our plans for 2014, but what I can say at this point is that we are working through our formal budgeting process as we speak and I hope to have an update for you all later this year.

Finally, in closing, I would like to state that lot of operators are doing great work in the basin and well results continued to show improvement. We hear constant chat about different style completion well results. Kodiak continues to valuate different technology and currently we are applying several types of completions throughout our acreage blocks.

I would also like to state that the quality of the production will always nearly be directly influenced by the location of the lands. If you look at any research play, there are core lands and then there are other lands. It is important to remember that we are not creating our output rather we are extracting existing oil from the rocks.

So at the end of the day, the results are going to be totally in line with qualitative rocks. Your highest greater returns will be in the core areas and as you drill and complete wells to the edge of the play your wells will still be commercial, but there will be degradation every time as simply there is less oil in place. We have put a lot of effort into acquiring acreage, which we felt we are in the core areas and I believe our results are confirming our beliefs.

With that, I would like to thank everyone for listening this morning. I will now turn the call back to the operator and we will be happy to take their questions at this point.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And our first question is from Brian Corales of Howard Weil.

Brian Corales - Howard Weil

Good morning, guys. Question on the downspacing, the 12 wells I guess, the results are pretty good. Is this going to become standard or is that not standard yet?

Lynn Peterson

Brian, again, I think as we’ve stated over and over I think more time will make us feel more comfortable. We also think it’s going to vary as we move throughout the basin where we probably have better rocks and more natural fracturing, maybe get back to few less wells. These will determine as we move through this. Again, we’ve often stated I think we’ve pretty much proven that seven or eight wells is not the answer anymore and is 12 the magic number, is 16 the magic number is something greater. Only time will get there. Do you guys you want to add anything there?

Jimmy Henderson

No.

Lynn Peterson

So that kind of answers, Brian. It’s not a --

Brian Corales - Howard Weil

That was helpful. Hey, that was helpful but basically your previous drilling of eight wells per drilling unit is probably -- you mean more wells per unit and they may vary area-by-area but you don’t know the magic number but it’s more.

Lynn Peterson

Yeah. And I didn’t tell you that all of our programs that we are looking forward, 2014 is little tighter than the seven, eights were. So, I mean we are moving in the direction from 12 up to a little bit tighter and almost we will add them.

Brian Corales - Howard Weil

And then just on the same kind of thought, I think you all said you are testing, this means a one drilling unit of 16 wells. When do you think you can talk about that or when do you think that will be completed? Is that kind of mid-next year or late next year?

Lynn Peterson

Yeah. Let me guess, it’s in that range. Again, we’ve got a rig running on it right now. We are drilling our first pad. We are still looking for some to get additional permits grouped and we’ve moved rigs in there fairly quickly. So we’ve got to laid out and will be -- somewhere next year we will get this information.

Again, I agree, emphasize what we said on past calls, we’ve tested wells down to 600 with spacing in various parts of the basin. There have only been two wells. Again, we don’t think that’s the test we are looking for and that’s why we would like to do over a broader area. So, I mean, it’s not like we haven’t done and no other operators have done it. We did like to like, all added together and stimulate more at once and see what kind of numbers we get again there.

I think the other part of, what we are doing here is we are looking at the deeper part of three parts. As you recall this to us, it was really isolated to what we refer to as the upper and middle member. We're looking at wellbore placements within those two intervals to see if there is a certain area we like to place them. We're also going to reach down into the lower middle member or upper lower member and try to evaluate and see what type of numbers we can get out of the well down there. So continued evolution of the play I think -- we're excited about where we are going with it.

Operator

And the next question will come from Hsulin Peng of Robert Baird.

Hsulin Peng - Robert W. Baird

So, I just wondering if you could talk about the well costs. I know you mentioned 9.2 million, 9.5 million currently. And I was just wondering what you think -- what you’re thinking for 2014, where could you get to and also the drivers for potential cost savings, how is the service cost environment looking currently?

Jimmy Henderson

Well, again I guess if we start back beginning of the year I think we saw well cost in the first quarter to be somewhere in that 9.5 range or 10.5 to 10.7 range. During second quarter we saw like kind of coming into a lower 10 to 10.2 range as I recall, third quarter we beat that number down to about 9.7. Today I think our well cost for well again drilled into deeper part of the [basin complete] full ceramics is running this in this 9.2 million to 9.5 million range. We are drilling on a couple of wells on each of the play, we think these are going to be in the 7.5 million plus or minus range.

So, again one doesn't fit everything here. When we talk, we talk majority of our acreage is the best part of the basin, our well costs are today running in that 9.2 million to 9.5 million range. As we go more into development mode, we get -- we build a lot of roads for our whole acreage block, that cost has sunk into the cost already, as we drill more and more wells along those roads. We're not going to be incurring those same numbers. Where we can drive this, I think we're comfortable thinking we can push this to 9 million, can we get it down a little bit lower with time? It's going to take some time. And as we continue to evolve on the development side, keeping the rigs in one area has a lot of merit. We should see some cost efficiency, just like we saw maybe when we did our pilot program earlier this year. So I think those are fair numbers and I think they are numbers that we can see in our current agreements that we have with third party services.

Hsulin Peng - Robert W. Baird

So is the service cost -- third party service costs sort of holding flattish currently?

Jimmy Henderson

Yes, I think there is just efficiency gains to achieve primarily. I am not going to sit here and say all of our costs are coming down. We have seen some costs come down, whereas some have gone up to this range. So, we are making progress. We have got a good relationship with our third party services. We are continuing to look at our completion work. I mean, our team doing a lot of different things. We are doing single-entry completion job. We are doing multiple-entry completion jobs. We're doing -- as Jim mentioned we're doing some sand completions, we're doing ceramic. We are making progress and this is a big play and there is a huge oil discovery here.

So these things are going to evolve over time and again I’d just really try to emphasize -- I think there is a lot of operators doing a lot of good jobs. I think Kodiak is hanging in there, and we are performing well.

Hsulin Peng - Robert W. Baird

And then my next question is regarding -- just wanted to understand how reserves booking works from the downspacing in terms of pud booking from -- I guess from mid-year versus what you think, just the impact of downspaced pilots, your pud booking tactics going forward?

Lynn Peterson

I don't think we know the answer to your question at this time, Hsulin. We are working with our third party reservoir engineers. We are going through that process as we speak really. So, Jimmy, you want to add something to that?

Jimmy Henderson

No, I would say that probably the limitation on puds is going to be more from the timeline to development and number of wells per DSU. And that's something, like Lynn said, something we've got to work through with the engineers. But I'm certain with the success that we've seen so far in the downspacing, it does bring in a cushion of how you book offsetting locations and DSUs. But, I think, ultimately there will be limitation that if SEC prescribes on time to development?

Lynn Peterson

I don’t think there is any shortage of PUDs, again, we don’t really see the necessity to book a lot of bunch either. So we are going to try to pretty consistent where we have been.

Hsulin Peng - Robert W. Baird

Okay. And then my last question and I don’t know if you would be willing to answer is, in terms of, I guess, the next downspace pilot wells that you plan to drill, if I look at your map, can you kind of give us some ideas to where you could go to?

Lynn Peterson

I am not sure again, as Russ stated, our new task is going to be just immediately east of our last Polar test, I am not sure, I am not understanding your question?

Hsulin Peng - Robert W. Baird

Just kind of going forward in 2014 other than the 16 -- potential 16 well PUD east of Polar, what’s to come, what areas do you think you will test next?

Lynn Peterson

Oh! We are going to continue, well, we are working in Dunn County right now. We have got expansion changes to the infrastructure over there that we view as positive at this point and if we can get more build out where we know we can move our products, we want to do some work over there. We have just moved the rig into one of our core areas over there and we’ll be starting drilling programs.

So we are going to continue to evaluate all of our lands. I mean, this I think is the challenge to our team is to look at everything and that includes our acreage block ups to the north in [Northrop] where we have a rig runner right now. We are doing some testing at there. We are going to continue to work through the whole 200,000 acreage more or less.

Hsulin Peng - Robert W. Baird

Okay. No. That sounds good. Thank you, guys.

Lynn Peterson

Thank you.

Operator

Next we have a question from David Tameron of Wells Fargo.

David Tameron - Wells Fargo

Morning. Lynn, I apologize, if this has already been asked, I mean jumping back and forth between conference calls? But can you talk about ’14 and how we should think about capital allocation, I know you have some line of site to free cash flow down the road, I am just wondering how we should think about the desire to ramp or accelerate the slowdown or what’s your plan there for the next four quarters?

Lynn Peterson

Yeah. I think what we talked about this morning there was kind of keeping our rig count somewhat constant here in these seven rigs plus or minus range. Again, we are seeing some efficiencies and so, we are drilling more wells with the same number of rigs. So you see a little bit of acceleration even without adding additional rigs. I think as we go more to the development stage, we will see some more of those efficiencies come into play here and we will get more and more work done in short amount of time.

So, we are working through those numbers, right now. I think what I had told everybody that we are pretty consistent with other guys speaking that we expect to see a CapEx somewhat similar to what we have seen this year.

We will see where oil prices go, we have a lot of flexibility to change if we need to or want to. But I think we can deliver some pretty impressive growth keeping our numbers right where they are at today and we do think we will get into a more or less neutral position sometime midyear, next year and hopefully end of year, certainly neutral or positives.

So, again, much of that is still subject to oil prices as you are aware and those type of things. But that is one goal the company has, I think it’s important. So we can continue develop this huge block of potential in a meaningful manner. So, does that help you?

David Tameron - Wells Fargo

Yeah. It does. And then just on the hedging front, any change of philosophy for ’14 or should we expect to see something similar done in the last couple of years?

Lynn Peterson

Go ahead, Jimmy!

Jimmy Henderson

Yeah. I think it would be fairly similar, I think right now we are somewhere around 40% to 50% hedged and that’s pretty similar to where we were 2013 coming into year and as we -- I think we still have some dry powder to add on additional hedges as we move closer to the year and to the year take advantage of spikes in WTI to takeoff a little bit more whenever it makes sense. So, I think, philosophically I think it’s pretty similar to what we did through the 2013.

Lynn Peterson

Yeah. I think if you look at the curve as you know, it drops off pretty quickly, so it’s become a challenge for 2014, certainly more challenge come 2015. So again I think we've been pretty adamant about just protecting our CapEx here and trying to be opportunistic. And I am glad we've just got a pretty firm base here to work with now 2014 and I think we can ride it out and put them on when the opportunity presents itself.

David Tameron - Wells Fargo

And then last question, [acquisition] you don't have a appetite to do anything soon. But can you just talk about more industry-wide or basin specific anyway, kind of what's left in the Bakken, how many private packages -- can you just talk generally about what you are seeing out there as far as M&A and what's out there and what's not?

Lynn Peterson

David, the [Bearden] always has an appetite (inaudible). We are always looking for opportunities and again quality of acreage is most important to us. I think as we all understand this basin has gone through a lot of M&A to date and a lot of properties have changed and I think you look at the basin as a whole, the majority of it is certainly in public company’s hands right now. Are there opportunities? Absolutely. Are there big opportunities? I think it gets a little tougher.

So I probably skirted that question pretty well but if and when an opportunity rises, we like the play. We think it's providing us some great return on investment and we'll try to be as aggressive as possible.

Operator

And the next question comes from Michael Hall of Heikkinen Energy Advisors.

Michael Hall - Heikkinen Energy Advisors

This might have been answered, just one question I had was around just the evolution of completion design and I appreciate the run through on your end. That was helpful. And I think Liberty is completing oil somewhat differently than you all have. Just curious if you can provide any thoughts about maybe piloting some offset wells with the Kodiak's style completion relative to a Liberty style and if you have any plan to do that?

Lynn Peterson

You know Mike, I think we've got to be pretty careful as we discuss these things. There is a lot of factors going to all these completions and I think there is also a lot of factors as you look at production numbers and how they're gathering and all that stuff. Again, I think our team is very much on top of this. I always caution all of our investors to certainly understand comments that are made about different types of completions. It's evolving without a doubt. I think our program does pretty well.

We compare all these numbers against everybody and all these different types of completion. We normalize numbers and we feel pretty good what where we're at. So, again, we watch everything and there is a lot of people trying to do a lot of different things and that's great, and we certainly encourage all that. And our team -- we treat things different parts of the basin. I mean as Jim stated earlier, there is not one recipe that works for everything out here. So these are things that will continue to be going on. I think this is the beauty of the play, there is a lot of oil in place here. And we can work on a recovery rates. And probably what we are doing today and what we are going to be doing two years from now is going to be totally two different things. So, anybody else want to add something to that --

James Catlin

This is Jim. I am not sure about trying to get into all the gory details. There are different ways to do this. They all seem to work. In some areas, some are going to work maybe slightly better than others and I think one of the key things that Lynn has mentioned this and emphasized is that different operators do all kinds of things differently, not only how do you frac the wells, how you clean the wells out, how you report IPs? And so while you can get some general indications of well qualities initially, you really need to look at 30, 60, 90, 180 day production numbers to really compare wells and we do that in different areas. We are doing, try some different things and that's really about I think all that we really can't or won’t say about.

Michael Hall - Heikkinen Energy Advisors

So content with what you are doing and you'll continue to think as you always have for the major overhauls on the horizon. Does that makes sense?

Lynn Peterson

Yes. I mean no Badger -- what means, what that means exactly, we’re continuing to do lot of different things. And again when we do try it on one well, may not try it on all. So, yes, it’s a great PUD, you guys know. And again I stress there is lot of operators who could work out here and we all share here and there and it’s improving so.

Michael Hall - Heikkinen Energy Advisors

Fair enough. I guess, on the downspacing test on Polar in particular. Do you have any [company that] you could talk to on the wells that you had on first on that Badder?

Lynn Peterson

Yes, I think when we look at this whole thing, we’ve ran our 60 day numbers. We don’t have 90 day numbers on all the wells at this point. But when we took, I think there was a total of eight wells in immediate area that were completed by Kodiak. Potentially same number of stages, same type of volumes, we compare those numbers and they track very closely.

We put a lot of these numbers out in the past. I think you can refer back to some of our Polar wells and feel pretty good. Again there is a little bit of variety as we’ve seen. I think generally speaking, we still believe that the Three Forks is a little bit inferior to the Bakken. That being said the best well in the 12-well program is a Three Forks well.

So its kind of challenge to make all those broad statements but generally speaking, it appears that the Three Forks is a little bit under performing in the Middle Bakken wells but the rest of them are very much in line with the Middle Bakken wells when we compare it to the old wells, they almost mirror them exactly.

So we also thank the state. I mean, from a production standpoint, we just are not seeing any degradation of the numbers at this point. So we feel pretty good.

Michael Hall - Heikkinen Energy Advisors

Great. That’s helpful. Appreciate.

Lynn Peterson

Thank you, [Brian].

Operator

And the next question comes from David Deckelbaum of KeyBanc.

David Deckelbaum - KeyBanc

Thanks for taking my question, Lynn. I was curious actually. So you have a small asset disposition in the quarter. I don’t know if you guys had touched on this already on the call I missed it. But did that include any production and can you give any color around, any expected turning that we should see over the next six months or so?

Lynn Peterson

Well I think we stated. I think we did close six transactions. And we’ve been eyeing some of our working interest -- non-operating working interest partners out of our operated units. We’ve sold a little bit of our operated lands and we thought we’re in an area where we weren’t going to get too immediately.

I think we ran through the numbers. We’ve lost -- we’ve sold some production without a doubt overtime. And that’s why we try to adjust our guidance a little bit, tighten it up at least the range. Maybe I want to give you any details, we could talk a little bit offline and see if I can answer specific questions for you. But it’s been a combination. That’s why we try to put that numbers out there. I think we state we had about 3,700 acres on the net basis that we’ve sold or swapped or traded out off and we brought in about $40 million to our balance sheet.

Again we’ve got several transactions out there right now, some of which will include additional acreage and production. But we’ve also got few offers out there right now. So, it’s an ongoing process but I think then they would [buy in up around] 85,000 net acres. I’m going to guess in basin and that’s going to be pretty high quality acreage.

David Deckelbaum - KeyBanc

That’s great. I guess I was trying to get a sense for the impacts to tighter guidance range from asset sale there?

Lynn Peterson

It’s a little moving target.

David Deckelbaum - KeyBanc

Okay. All right. Well, that’s all I have Lynn. Thank you.

Lynn Peterson

Hey thanks, Dave.

Operator

And our next question is from Eli Kantor of IBERIA Capital.

Eli Kantor - IBERIA Capital

Good morning guys.

Lynn Peterson

Good morning Eli.

Eli Kantor - IBERIA Capital

Hopefully this question isn’t too granular but in the past, you guys have talked about a seeing different drainage footprint in Dunn County. Just curious, if you have any plans towards downspacing in that area next year?

Lynn Peterson

Well, as again, as I stated previously, we are doing some workover there. We just moved a rig in, infrastructure has changed hands, we think we're going to see improvements in that. So we'll be able to work in Dunn County more as we go through 2014 and into '15. So that's really that all we can say at this point.

Eli Kantor - IBERIA Capital

And in terms of activity levels, it sounds like you plan on maintaining a seven rig program but you are going to see additional increase in the completion count just through improving efficiencies. I'm curious as to when do you think you might reach cash flow neutrality and what kind of oil prices are you assuming to get there?

Lynn Peterson

Again, I think we ought to just wait a month or so here, let us get our budget out. Typically we have gone out before year end and all those type of numbers. And I think to speak to that at this point would probably be a little presumptuous until we get our numbers firmed up.

Operator

And our next question comes from Jeffrey Campbell of Touhy Brothers Investment Research.

Jeffrey Campbell - Touhy Brothers Investment Research

Yes. I wanted to ask you about the Lower Three Forks. I think that you’re going to do (inaudible) maybe in contrast to 16 well pads. First of all, when you call a Lower Three Forks, is that analogous to what others call the third and fourth bench? And then my second part is kind of what are your expectations for the Lower Three Forks going in and if it turns out to meet those expectations what kind of prospect does this have for you throughout your acreage?

Lynn Peterson

To answer the first one, yes, I think [World Congress] jumping here but I think when we talk or we assess it's kind of the lower second to higher third somewhere in that interval. Again I think as we've talked about numerous times, we don't necessarily believe that these are all separate intervals from a production standpoint. We believe that when we stimulate these wells, we see communication between these intervals. So I think what we are focused on is trying to think about wellbore placement, where is the optimum place to drill these, where can we initiate our stimulation work, those type of things.

As far as expectations, I think again clearly, we see the resource potential deteriorate as you go further in -- deeper into the Three Forks. We think the upper two intervals are the most prospective without a doubt. Clearly, Continental has done a lot of good work. We commend them for their work. And we are trying to do some of this ourselves and see what kind of the numbers we get out of it. So I think our expectations are within reason and we will probably keep those to ourselves at this point. Russ, do you want to throw something out…

Russ Cunningham

We think, as Lynn pointed out -- we think it's a fairly large reservoir in thickness. We don't see necessarily separation between the upper and the middle benches. We don't expect to see separation with the lower one. It is equivalent of what Continental calls the third bench. We did core the well in the polar pilot project and we did see oil saturations that give us encouragement that things will probably get some decent production. That's why we want to test it in this area.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Lynn Peterson for any closing remarks.

Lynn Peterson

Okay. Thank you. At this time, I wanted to extend a big thank you to all of our employees. Everyone continues to show some great dedication and loyalty to our company. Everybody is working hard try to drive shareholder value. And I can tell you and our entire staff about what we have accomplished this year but more importantly I think when we look at our trajectory going into next year and where this company can go, I think that's what everybody is excited about. I can't thank everybody enough for their efforts and appreciate it all. I think the Williston Basin -- it’s a great place to call home. We are experiencing some very solid oil prices. We’ve seen a massive investment into the infrastructure build out. Our costs are turning downward. Technology and industry efforts are allowing us for more optimal development of the massive resource.

And I think we’re gaining efficiencies to move along. I think you are going to continue to see this at our all companies and this is one of the premier oil plays in North America without a doubt. I guess at this point, we will be back with everybody here as we go through the end of our year closed out. We’ve got a pretty active conference scheduled as we noted on our release earlier this week.

We’re available. We will continue to communicate with everybody. I want to thank everybody for your support. We’ve had a good year. We are just beginning and things are moving very smoothly right now. And I’d like to thank all of you for that support and wish you all a great weekend and we will be in touch over the coming weeks. Thank you very much.

Operator

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

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