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Kodiak Oil & Gas Corp. (NYSE:KOG)

Q1 2014 Results Earnings Conference Call

May 2, 2014 11:00 AM ET

Executives

Aaron Gaydosik - Vice President, Finance

Lynn Peterson - Chairman and CEO

Jimmy Henderson - Chief Financial Officer

Russ Cunningham - Executive Vice President, Exploration

Russ Branting - Executive Vice President, Operations

Bruce Taton - Vice President, Marketing

Analysts

Brian Corales - Howard Weil

Michael Hall - Heikkinen Energy Advisors

Mike Scialla - Stifel

Jeffrey Campbell - Tuohy Brothers Investment

David Tameron - Wells Fargo

Paul Grigel - Macquarie

Jason Wangler - Wunderlich Securities

Jason Smith - Bank of America Merrill Lynch

Operator

Good morning. And welcome to Kodiak Oil & Gas Corp. First Quarter 2014 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 Aaron Gaydosik, Vice President of Finance. Please go ahead.

Aaron Gaydosik

Thanks, Emily, and thanks everyone for joining us today. Please be advised that our remarks today, including answers to your questions, includes statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include among others matters that we have described in our financial and operating results, news release issued yesterday and in our filings with the Securities and Exchange Commission.

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

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

Lynn Peterson

Thanks, Aaron. Good morning, everyone. And welcome to our first quarter earnings call. I’m joined for this morning’s call by Jimmy Henderson, our Chief Financial Officer; Russ Cunningham, Executive Vice President of Exploration; Russ Branting, Executive Vice President of Operations; and Bruce Taton, our Vice President of Marketing.

Please reference the news release and our filing on Form 10-Q, both which were made available last evening for further details and full disclosure of the topics we are discussing today.

As we received a lot of positive comments from our fourth quarter call, we will try to stay away from restating all the information that we released last evening.

We have just completed challenging quarter that was heavily impacted by severe weather conditions with abnormally low temperatures that continued through most of the quarter. We like all Bakken operators were slowed by weather -- by these weather conditions and as we only operate in one basin our results highlight the challenges incurred during the quarter.

When we look at our non-operated production, we saw nearly an identical reduction volume reflecting a basin-wide situation. As we have always stated, this is a marathon and not a sprint, and we believe we are well-positioned to deliver quality results throughout the balance of the year.

Our first quarter production was clearly below our expectations. We ended the New Year with the intent to drill some of our short-term leases in our Wildrose area in Northern Williams County in order to hold all of our acreage by production.

We felt that we could drill and complete a total of five wells early in the year and then move into our core areas and start to ramp up our production. Unfortunately, with the weather conditions we didn’t get to our core areas until March and the result in production gains fell principally into the second quarter.

The production from the few Wildrose wells was further delayed as this is an area of thinner source rock with less reservoir pressure that requires us to put these wells on artificial lift almost immediately. With the weather conditions we were unable to get in our workover rigs onto locations quickly and set the pumping units.

Our production was not only impacted by a slowdown activity but also higher than anticipated downtime as workover activities slowed dramatically as this work is totally exposed to the weather elements.

However, on a positive note, as we look back at March and now April, we can see significant improvement in not only our completions but also we have been able to bring our down production back online.

During April, we are estimating that sales volumes will average between 36,000 and 37,000 BOE per day based upon March non-operated sales volumes. During the month we saw sales volumes range from a low of 34,000 to 35,000 BOE per day to as high as 39,000 to 40,000 BOE per day.

We are currently utilizing two completion crews. We expect to see stepped up growth in the second quarter and then linear growth as we move through the remaining periods. Looking back at the first quarter, we completed 15 net operated wells, of those 15, four net were completed in the Wildrose area and nine were completed in March, so you can see the weather affect on activity level in February.

As we look at the next three quarters, we should complete approximately 22 to 25 net operated wells per quarter over each of the remaining three quarters. We have already brought online nearly 10 net wells in April.

Regrettably when we look at average for the year, it’s very similar to GPA for batting averages. If you enjoyed the college life and left the books till the end of the night, you probably struggled getting the GPA built back up during the last three years of college or likewise, if the major leaguers get off to a slow start in April and May, it is a real challenge to lift that batting average come August or September. The one difference is we can’t until mother nature, we must deal with the hand we are dealt and some winter hands are better than others.

With that in mind, we have chosen to reduce our guidance for the year to reflect the slow start. With the first quarter in the books, we have reassessed our expectations for the rest of the year.

Looking not only at our operated drilling and completion plans, but also an updated completion schedule on our largest non-operated interest where activity has been pushed back to the latter part of the year.

Based upon this analysis, we have revised our average 2014 full year guidance to a range of 39,000 to 42,000 BOE per day, down from 42,000 to 44,000 BOE per day that was provided in late 2013.

I would now like to turn the call over to Russ Cunningham, our Executive Vice President of Exploration to discuss our continuing work on the wellbore optimization. Russ?

Russ Cunningham

Thanks, Boss. Let me begin by saying our first quarter is not indicative of quarters to come as we have brought on some great wells in March and April. I’m excited about our upcoming results as we move through the year.

Regarding our downspacing work, we want to continue to caution everyone on jumping to conclusions with only a few months of production. We posted 210-day production numbers for the wells at our Polar Pilot 1.0 where we drilled six wells in the Middle Bakken and six wells in the Three Forks formation.

While the numbers are encouraging and represent nearly 100,000 BOE per well produced to date, this timeframe represents less than 2% of the expected lifetime of the wells. We have taken the downspacing one step further with our Polar Pilot 2.0 drilling spacing unit, where we will ultimately drill eight wells in the Middle Bakken and eight wells in the Three Forks staggered throughout the first three intervals.

The first four well pad with this tighter spacing was completed during the first quarter of 2014. We posted the numbers last evening as well for the first 60 days of production. We have received numerous questions about these wells as people are trying to compare it to our first pilot program and draw immediate conclusions.

Please keep in mind that these wells were completed during some intense cold weather, while the first pilot wells were completed in August and as a result, different procedures were used to clean up the wells.

Probably most importantly, this is an extremely small sample and we need to get the remaining wells drilled and allow these wells to produce for several months. When we evaluate production along with pressure work being completed in the field, we feel good about the early numbers but again caution against extrapolating to quickly.

We currently have two rigs that are drilling wells on two additional four well pads with the third rig scheduled for the remaining pad in the coming weeks. Completion efforts will be in the second half of the year and we should have some preliminary production figures by year end.

We continue to see more variability in the quality of the Three Forks wells, compared to the Middle Bakken. The quality of each of these formations varies throughout the basin but we seem to have larger range Three Forks quality variability within specific geologic areas.

We have previously stated and continue to feel good that we are not seeing significant communication between these wellbores at the time we stimulate the wells or during the early production period. However, that’s about the only thing we know definitively at this point. As a geoscientist, I blame all of our first quarter production issues on our operational team and accept no responsibility for their performance.

With that, I would now like to turn the call over to Dr. Russ Branting, our Executive Vice President of Operations to defend himself and his team.

Russ Branting

Thanks, Russ. Good morning to all our listeners. This morning I’d like to focus my discussion on the key operational issues that received significant publicity, gas capturing and the reduction of gas flaring.

During 2013, we captured approximately 55% of our total gas produced. This number is skewed lower to some degree due to the early flowback gas on some of our downspacing work where we concluded several wells within a small area creating significant volumes early on.

Kodiak is participating with industry and governmental task force in an effort to improve the gas capture to nearly 75% by year end 2014. This number will then continue to increase over the next couple of years. Kodiak has already been working with our midstream providers to meet this challenge.

For instance in Dunn County with the exception of our Charging Eagle block, our midstream providers have increased capacity and compression, whereby we are currently capturing over 80% of our produced gas. This is an area where we have historically sold less than 50% of our gas production.

In certain areas where pipelines are not in place, we have put in place NGL recovery units to reduce flared volumes. We have started placing small refrigeration plants on site and are stripping liquids out of the gas before it is flared, thereby reducing the volume of gas flared by up to 40%., by removing most of the liquids, we significantly lower emissions from that flared gas.

The income stream generated from the captured liquids helps offset the cost of the plants. We will continue to evaluate additional properties that will be suitable for this recovery method.

Our Polar area in Southern Williams County continues to be the area where we are flowing the most gas -- flaring the most gas. We have been collaborating with our midstream provider over the past several quarters to bring in larger pipe and compression into the area. To the midstream provider credit, much of this work has already begun and we expect additional takeaway capacity to come online in Q3.

In several of our areas, we are focused aggressively on replacing diesel fired generators with natural gas driven generators. This not only helps us utilize the natural gas, but it should also help us drive down our LOE as fuel for generators is the second largest component of LOE.

Let me now turn over the call to Jimmy Henderson to discuss the financials.

Jimmy Henderson

Thanks, Russ, and good morning, everyone. Thanks for joining us. Kodiak continues to be an oil story as crude oil accounted for approximately 90% of our revenues recorded in the period.

Last evening we reported fully diluted GAAP EPS of $0.11 for the quarter ended March 31, 2014 and reported adjusted EBITDA of $180 million for the quarter driven by oil and gas sales of $257 million, which is a 56% growth over a year ago period of $124 million.

Even more important, when we compare our Q1 EBITDA of $180 million against our capital expenditures of $208 million for the quarter resulting in total outspend of about $28 million. This compares to outspend of $132 million in first quarter of 2013. This closing of the gap is an important step forward for us, as we look to fund most of our capital expenditures within internally generating cash flows.

We made additional efforts to improve our balance sheet through receipt of about $70 million of proceeds from selling non-core properties. As far as our overall liquidity picture, we ended the quarter with about $700 million drawn on the revolver, which leaves us with over $650 million undrawn. We continue to believe this provides us with sufficient liquidity to meet our commitments.

Regarding the revolver facility, we just completed the spring redetermination and left the borrowing base and aggregate commitment to $1.35 billion. As a reminder, we had just recently set that borrowing basin in November, so we didn’t expect a change this time around.

Going forward, as we continue to complete wells and increase production reserves, we expect to see that facility continue to grow which will further improve our liquidity situation. As always, we appreciate all of the banks participation in the syndicate and look forward to continuing our relationships in the future.

To further protect our liquidity, we have about 65%, 70% of our forecasted oil production hedged at approximately $93 per barrel for the rest of 2014. While we have a much smaller percentage hedge for 2015 due to the degredation of the forward curve, we will continue to layer on transactions as we move through the remainder of 2014. And hope to be around 50% hedged as we enter 2015.

With that, let me turn this back over to Lynn. Thanks.

Lynn Peterson

Thanks Jimmy. I’d like to thank Russ Cunningham for being such a team player and throwing the operations team under the bus. Before we move onto Q&A, I’d like to reiterate our feelings on the downspacing projects. I think it’s extremely important that people realize that one plan will not fit all acreage in the basin.

Development programs and completion techniques will vary greatly from area to area. The Three Forks qualities seem to change significantly as we move from east to west in the basin, with Bakken and Three Forks wells nearly equivalent in our Dunn County acreage, whereas we see the Three Forks being nearly 15% less quality in our southern Williams County acreage block.

We understand that investors are not giving us value for 12 wells per spacing unit and we certainly understand that nobody has gone to a 16 well NAV calculation. However, with the continued production from our downspacing work, we believe that we can move the NAV of the basin forward.

We continue to stress to all of our investors, the importance of payout and capital efficiency. While our early production numbers look good from these downspacing projects, we hope to see our recovery rates improve. But we have to expect some type of degredation of reserves on a per well basis at some point.

However, if you can get the reserves out quicker and drive your NPV ahead, then what happens in 10 to 20 years from now has less of an impact. I know we sound like a broken record at times, but we need to have some additional time to get our downspacing wells all drilled and then we need to let these wells produce and we’ll post the numbers accordingly.

With that, we want to thank our listeners for joining us this morning. We’ll now turn it over to the operator and be happy to take your questions at this time.

Question-and-Answer Session

Operator

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

Brian Corales - Howard Weil

Good morning, guys.

Lynn Peterson

Hi, Brian. How you doing?

Brian Corales - Howard Weil

I’m doing all right, I guess. The timing of completions in the first quarter, I know you said they’re more -- you’re going to have more in the next three quarters. Were most of the completion or wells brought on, is that mostly March or can you maybe quantify that a little bit?

Lynn Peterson

Yeah. Like I said, we brought on the 15 net wells we completed in the first quarter. Nine of them were brought on in March and as we stated, most of that production really falls into April and the second quarter. January and February were extremely slow.

Brian Corales - Howard Weil

Okay.

Lynn Peterson

To show you the step up again, we’ve noted that in April, we’ve already -- we completed 10 net wells approximately. And we are kind of on that pace going forward here.

Brian Corales - Howard Weil

And do you have a decent backlog right now of wells to be completed, bigger than normal I would say?

Lynn Peterson

Yes. I mean, inventory grew -- the drilling activities never slowed down during the winter period for the most part. We had our rigs positioned where we wanted them, that moved ahead and we’ve made some great strides in getting these wells done quicker. So, yes, we did have a buildup of inventory at quarter end. We’ll work that off here in April and May and get back to more of a routine as we go through the third and fourth quarters.

Brian Corales - Howard Weil

And just one question on the downspacing. I mean, the rates were -- I know it is early life stage here, but a little bit lower than we saw the pilot, the 1.0 downspace pilot. I mean, is this where it is and is this the reservoir, was it just weather impacted those flow rates a little bit? Is it too early to tell or could this be just two wells not -- could the next four be much better? What is your -- I know it’s very early, but what is your thinking of, maybe some of the reasons or is it really just you’re going to have some degradation and this is kind of how the wells are going to look on a 16 wells per drilling unit?

And just one question on the downspacing, the rates were -- I know it’s early life stage year. But a little bit lower than we saw the pilot -- that 1.0 downspace pilot -- is this where it is -- is this, the reservoir or was it just whether impacted those flow rates a little bit? Is it too early to tell? Could this be just two wells not -- could the next four be much better? What is your -- I know it’s very early but what is your thinking of maybe some of the reasons or is it really just to have some degradation and this is kind of how the wells are going to look on a 16 wells per drilling unit?

Lynn Peterson

I’ll take a shot and then the other guys can jump in here. But I think -- one thing, we’ve just got to be careful about. This is an extremely small sample. We’ve only drilled two wells in the Middle Bakken, two wells in the Three Forks. And I can’t stress enough that we brought these wells on in the dead of winter here. And we certainly had some operational challenges. There’s no doubt, moving oil and everything here.

The other thing I think if you look back on our initial program, we had some wells that went on the low range or fell into these same numbers. We also had some wells that were better and I think as you hit a larger sample, we’re going to get a better read on this. Russ Cunningham, do you mind to share your thoughts out here and then Russ Branting can pitch in?

Russ Cunningham

Yes. Brian, we see variability, especially in the Three Forks. If you look at our initial pilot program, we have one well specifically that’s a really dandy well and we have one adjacent to it that isn’t nearly as good. So it’s a natural variability within the Three Forks. The first two wells that we drilled in the second pilot program were drilled in kind of, what we call a marker bed between the upper and the middle Three Forks. So it’s hit a favorable location and we expect to see as Lynn pointed out, when we get a better sampling and more wells drilled, we’ll see kind of more of an even distribution expected reserves.

Lynn Peterson

Russ, do you have any other?

Russ Branting

I think it’s fairly early to try to get a true determination on these wells and we also need to remember that operationally we clean these wells out with stick pipe versus coiled tubing. In the middle of the winter, it took me longer to get them cleaned out. We were evaluating whether that had an impact or not, and we should have something definite or more definite here as we go along.

Lynn Peterson

Yeah. I think, Brian, I mean we just need a little bit of time here. And I think the whole industry does and we need more wells drilled so.

Brian Corales - Howard Weil

Okay. All right, guys. Thank you.

Lynn Peterson

Appreciate you taking time off from the Jazz Fest, Brian, to join us.

Brian Corales - Howard Weil

I appreciate. And just for the record I never crammed in college. I always studied well ahead of time.

Lynn Peterson

I’m sure, that’s true.

Brian Corales - Howard Weil

All right, guys.

Operator

Our next question is from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Michael Hall - Heikkinen Energy Advisors

Thanks. I enjoyed freshman year fully. So, I guess a couple of things. On all downspacing and just variability that should be expected across the basin, when -- do you have any plans or thoughts on when you might look at doing the downspacing test out in Alsip in that western area? And any early thoughts on how we ought to think about how that might vary relative to what we’re seeing in Polar and Koala, or sorry, Polar and Smokey?

Lynn Peterson

Right now, what we’re focused on right there is getting all of our infrastructure build out so we can move the oil and gas by pipe and that’s where it’s been a little bit of, it’s still moving in that direction. I think that as we go through the second half of the year, we start picking up activity and then into next year. But we just got to look, give it a little more pipe in the ground so we can move our product.

And again, I think this goes back to completion techniques and there’s a lot of things going on in the basin. A lot of good work has been done by a lot of companies and we’re all moving and changing our style here and because the rocks change. And we’ve got to continue on that effort and I think our team is trying to stay up with the changes and trying new things as we complete every well here. So stay tuned as part of our program. We don’t think it’s vastly different than what we’re doing right now but we’re a few months or a few quarters away from getting that job done.

Michael Hall - Heikkinen Energy Advisors

Okay. Fair enough. And then on Smokey, we were just looking at the data and fully appreciate this is early days still and a small sample. But it does look like those wells are maybe turning over a bit more quickly relative to what you’re seeing in Polar. And then at the same time also that perhaps the Three Forks productivity relative to the Bakken, if you look at that versus what you are seeing in Polar, is also a little sub par, let’s say or inferior relative to Polar. Can you just remind me, kind of the dynamics that played on in Smokey and how we got to think about that and if there’s anything to be extrapolated other areas of the basin?

Lynn Peterson

I think we’ve left it pretty transparent, as far as the west side of the (indiscernible), we kind of look at our polar area as being our top property. And I think as we move to Smokey, we looked at reserves been slightly less. I think we’re actually very pleased with the Middle Bakken. I think as we get into the Three Forks, we see some changes geologic and maybe that’s where Russ could expand on that a little bit. But certainly as we go southwest of our area, we definitely see some changes as we move to the Northeast. We think we’re right back into this really pretty superb package of rocks. Russ?

Russ Cunningham

There are two conditions that exist down there in Smokey and they are kind of transitional. One is that the lower shale which is one of the principal source rocks, things rapidly from northeast to southwest across the block. Additionally, there is another stratigraphic unit that presents some challenges to the migration of hydrocarbons. So we see these variabilities -- we are just starting, hopefully to understand what the implications are and probably more affect the Three Forks than the Bakken.

Michael Hall - Heikkinen Energy Advisors

Okay. That’s helpful, I appreciate the context. And on, kind of, the timing around the first quarter -- is it all fixed kind of field level downtime that you all saw on existing production in January and February and is there any way to quantify that?

Lynn Peterson

Yes. I don’t know if we can really quantified it. I mean, Russ maybe you can just kind of address some of the challenges we saw without getting into specifics.

Russ Branting

We had a -- Q1, we were little short on pulling unit service rigs to address the down production from just normal maintenance type work. We’ve gone back up to nine pulling units and from Q1 to just April, our down production has decreased by at least a third. So like I said, everything takes a little longer. Everybody wants to freeze to death instead of take clothes off and things don’t get done as quickly as you like.

Michael Hall - Heikkinen Energy Advisors

Fair enough.

Lynn Peterson

I think that were just a lot of pipes that got frozen. We just had some issues. I mean, permafrost was pretty deep this year compared to what’s normal, caused some issues. Yes, I think the one positive to keep in mind here is that we didn’t have a lot of snow during the year.

We had some really, really cold weather but limited snow and as a result, the springtime, the meltdown has not been significant to us. And there have been some isolated flooding along the rivers but nothing that’s impacted us. We’ve had some weather this week because it’s thought out quickly, the grounds gotten soft. We’ve had a lot of rain and snow here. Last few days, we’ve had some roads shutdown but overall I think we’ve had limited downtime this springtime because of the, maybe, the spring thaw.

Russ Cunningham

That is correct, Lynn.

Michael Hall - Heikkinen Energy Advisors

Okay, encouraging. And then I got a last one on my end, you’ve talked about and you’ve, kind of, alluded to it a little bit in the comments there from Jimmy. But, kind of, the free cash flow balance or the funding balance as you move forward you’ve talked about in the past, I think towards the end of the year, early ‘15 maybe getting into balance. On the new guidance, when do you see that occurring? How do you think about that going forward?

Lynn Peterson

I don’t think it’s changed a whole lot, obviously with the lower volumes forecast. It’s not quite equilibrium. I think we had a little bit buffer built-in because we used lower pricing for our internal forecasting. So I think it’s still going to be pretty close for 2014 as far as EBITDA to CapEx and kind of exit the year pretty much in equilibrium certainly early 2015. So we’re definitely continuing to turn the corner on that and get closer.

Michael Hall - Heikkinen Energy Advisors

Okay. Great. That’s encouraging as well. And then what are your thoughts on any acceleration in ‘15 as you get to that level? Is that something you’re contemplating as we start to move towards second half of this year? Should we be thinking about that or any commentary there and then I’ll hand…

Lynn Peterson

I think Mike this is something we think about all the time. I think it’s depended upon certain oil prices. We want to get a little more production from our downspacing work here. So we can make sure we have a better understanding at least of our -- how close we want to put these wellbores.

So I think even with the same rig count, we’re kind of accelerating our activity level. We are bringing a couple of new rigs in here second and third quarters. We hope that, that will kind of speed up some mob and demob time which allows to drill a few more wells. So we’re slowly doing it. We are not changing our rig count necessarily. But I think that’s an option that we have certainly as we look into more of a cash neutral or free cash flow position.

Michael Hall - Heikkinen Energy Advisors

Very good. Thanks guys. Appreciate the time.

Lynn Peterson

Thanks Mike.

Operator

Our next question is from Mike Scialla of Stifel. Please go ahead.

Mike Scialla - Stifel

Good morning guys.

Lynn Peterson

Good morning Mike.

Mike Scialla - Stifel

Along the lines of Michael’s question while you’re thinking about 2015. If your confidence really grows over the year that 16 wells or even if 12 wells per DSU is the right number. How do you think about 2015? Do you want to really drill up the Polar area or would you think about moving over to Dunn County and testing the limits of downspacing over there?

Lynn Peterson

Well, let me say, some of our drilling activity is going to be a function of where we can get our infrastructure build out. We mentioned the gas capturing. I mean, we are very sincere about that. We know there’s an area we can improve on. As a result, we are working with our midstream providers that we mentioned.

So if we get pipe built into an area, get compression established and be able to capture higher volumes of our product. Those are the areas we are probably going to focus our drilling activity. I think when we look at Dunn County, we certainly see some very good wells over there. Russ mentioned that we’ve seen some really improvements on the infrastructure side.

We’ve actually continue to do some downspacing work over there. We just haven’t drilled the entire DSUs up all at once. So we don’t talk about it in quite the same regard. But the walls that we are working on over there are going to tighter spacing. So I think really our activity is going to be driven as much by results but also very much aligned to where we can sell our gas and capture all of our product here.

Mike Scialla - Stifel

So if I’m reading you right, Lynn, it sounds like you like what you see over there but that area is still a little bit behind on the infrastructure side before you’d really do something similar to what you’re doing at Polar?

Lynn Peterson

Again, they’ve made a lot of progress. We want to make sure that we can throw more wells added, we and other operators. So yes, I think we’re getting better and better shape all the time over there. So we appreciate the work that’s been done by our third parties.

Mike Scialla - Stifel

Got you. Okay. And then you’d mentioned in your prepared remarks, Lynn, about you probably pushed this to a point where you do see some degradation as long as the returns are still there. What -- do you have a sense of what kind of degradation you’d be comfortable with or maybe a different way of asking it is what kind of hurdle rate are you looking for before you’d say okay, we’ve hit the limit here, we’re going to stop with whether it’s 12, 16 wells or whatever the number is?

Lynn Peterson

Let me be clear. I don’t believe that any of our team feels like we’re seeing a degradation of results at this point. We had some variability within our production numbers but again there’s so many factors that go into that. We’ve had these wells on such a limited time. I don’t believe any of us are to the point of making that leap at this point.

However, when we look at this from a realistic standpoint, we believe the more wells you drill into a DSU, it’s hard to envision a scenario where you wouldn’t see some type of degradation. And so we’ve tried to look at that scenario and say okay, what if? I mean, you put that in our presentation as a hypothetical example. If you see a change in EURs which you are drilling more wells and you’re bringing that oil out of the ground quicker, you’re seeing an improvement in your NPV value for DSU.

And I think these are all the things. We’ve just got to continue to keep in mind. And I still go back to this payout basis that is so important that we get our money back on these wells. And as I think Russ Cunningham mentioned these wells on our 12-well program at nearly 100,000 BOE at this point.

Well, I mean, depending on what you look at for a payout, everybody has their own numbers but you can see we are well down the road to that. And are these wells, some of them are going to pay off probably in a year, some are going to pay out in two years but maybe the average 18 months, 15 months somewhat in that range. That is the important factor here.

Again I think so much emphasis is put on EURs and yet these wells have a life of 30 years. So I mean, as we get out to that 20 to 30 years, I mean, we really don’t know what the changes are going to be. Russ Branting, you want to jump in here with me?

Russ Branting

Yes.

Lynn Peterson

Any comments in that regard or did I misstate anything?

Russ Branting

No. I think you stated it correctly Lynn. And these wells have a life of over 30 years and payout and economics is the number one thing we are driving for here.

Lynn Peterson

We think we’ve probably reached that limit, Mike. I mean, we’re not looking to drill more than what we’ve done right now at least in the near term. And we’re not even sure in the Three Forks. I mean it’s possible that we are going to have seven or eight wells in the Bakken. They will have, call it, six or seven in the Three Forks. I mean, we’ve still got some work to do there. As everybody has brought up here, there’s different numbers in the Three Forks. And so we’re trying to evaluate all the stuff as quickly as possible.

Russ Branting

And don’t forget that these are a pilot program. There meant to try to determine the spacing.

Lynn Peterson

That’s exactly.

Mike Scialla - Stifel

Right. No, I appreciate that, thanks. Just one last one for me, was interested Whiting made some comments yesterday about coil tubing completion design that you looked at recently. I just wondered if you guys have looked at that at all if that has any interest to you?

Lynn Peterson

No. We try not to comment on other operators. We looked at this we’ve actually done some work early on. We haven’t done anything recently. But these are all things we’re looking at. And I think our team is actually trying to be pretty much in step with everybody out here. And we need to see what the results are going forward. We’re a long way from the finish line up here.

Mike Scialla - Stifel

Okay. Great. Thanks. Appreciate it guys.

Lynn Peterson

Thank you.

Operator

Our next question is from Jeffrey Campbell of Tuohy Brothers Investment. Please go ahead.

Jeffrey Campbell - Tuohy Brothers Investment

Good morning.

Lynn Peterson

Good morning Jeff.

Jeffrey Campbell - Tuohy Brothers Investment

First thing I want to ask you about was in the press release, it sort of sounded like you were calling out Wildrose as an additional contributor to production downward revision and I wanted to know if I’m misinterpreting that. And if so, why did you call out Wildrose?

Lynn Peterson

Well, Jeff, I don’t think we’ve -- we’ve always been very clear about this. We looked at that area as a tier 2 type property. We wanted to get up there and HBP it. So we could come back at a later date, work on completions. We tried several different things up there. We want to see what the results end up.

We felt like we could get out there and get out of there quickly. Unfortunately when the weather hit, it slowed all of our activity and it took us much longer to get that work done. And then as we mentioned, it was even further delayed because you’ve got to get these wells on pump immediately and that didn’t happen until almost end of the quarter.

So it was part of our program going in. We didn’t ever expect that it would take most of the quarter to make that happen which consequently pushed back all of our completion work that we wanted to get done down to the core of the play.

Jeffrey Campbell - Tuohy Brothers Investment

Okay.

Lynn Peterson

That’s our one block of acreage that we think is different right now. We think the balance of our acreage is all up obviously pretty high-quality and pretty similar.

Jeffrey Campbell - Tuohy Brothers Investment

Yes. I think you’ve been real clear about that it and it basically sounds like you’re saying it was a timing event which is what I expected. The other -- another thing I want to ask you about you mentioned about as part of your natural gas initiative trying to get some rigs on natural gas. So I was wondering if you had a number in mind as to how many rigs might be running on nat gas by the end of ‘14? And also would you try to run any frac spreads on natural gas as well?

Russ Cunningham

Frac spreads, no. No, it’s just not feasible at this point in time. The rigs we’re looking at going to overhead electric power. It’s a lot easier in trying to get them all on natural gas but we will be running the natural gas in all the boilers next year. We’re already well down the road on this one.

Jeffrey Campbell - Tuohy Brothers Investment

Okay, great. And my last question, I just would, sort of, like to change the conversation on the Polar 2 a little bit. I mean, we’ve kind of beat the flow rates to death. What I would appreciate is if you and I think maybe some investors would appreciate it as well? Can you just give some specifics to the structural advantages that you gain from downspacing relative to geology or whatever? Meaning, how do you capture more resource faster by virtue of downspacing and why might lower well NAVs still potentially become higher pad NAVs?

Lynn Peterson

Again, I think if you look at payout again, Jeff, if we are able to drill more wells within DSU and get our payout at the same rate, again, you compare that to looking at reserves that you’re going to get out years 20 through 30, I think there’s a big difference there. And if we can crack more of this rock as a group, I mean I think that’s one of the things we came away from our first pilot program when we were able to complete all of these wells at one time and stimulate all of the rock pretty consecutively, we feel like we got a little better production out of the wells. I think that is the one thing we’re trying to drive [tools] (ph) is seeing how is the proper way to drill these and complete them as DSUs as opposed to individual wells?

Jeffrey Campbell - Tuohy Brothers Investment

Okay, great. I appreciate that. Thank you.

Lynn Peterson

Thank you.

Operator

Our next question is from David Tameron of Wells Fargo.

David Tameron - Wells Fargo

Good morning, Lynn.

Lynn Peterson

Good morning.

David Tameron - Wells Fargo

I apologize I’ve been jumping on conference calls back and forth, so I apologize if you talked about this. But, can you just take us out of here and if we think about free cash flow or potential free cash flow, what are your thoughts about accelerating versus maintaining the current rig count?

Lynn Peterson

We are not the number one company that you’re listening to. So we did talk about it briefly and I think these are the things we’re looking at. We’re trying to figure out our downspacing here. And I think as we move into the latter part of this year, we get a better hand on that. We are going to feel more comfortable I think. We are seeing some acceleration through. Drilling times are coming down. Our team has done an exceptional job I think of bringing those down to kind of mid-teens type of number. We’re going to change out some rigs here through the second half of the year.

We hope that will actually speed up some of our at least more than demobilization time and allow us to drill up more wells. I think we certainly -- we do believe that being cash flow neutral positive is a good thing. And as we get to that point, we will have the optionality to increase our rig count going forward so. But I think some of this is going to play into all of this pipeline. We talked about infrastructure being able to capture gas and this is serious matter and somehow we’ve got to make sure as we move forward that we have pipe and compression and access to plants. So we can do a good job of capturing all of the revenues here.

David Tameron - Wells Fargo

Okay. And just one more for me. I know you guys are using actually ceramic and maybe stand in isolated cases. But just from an industry perspective, can you talk about -- I know you don’t like to talk about other operators. But just big picture, as we go to these completion techniques, or higher sand or whatever everybody is talking about, do you think that’s an issue that will be a bottleneck for the industry over the next when you look out 12 months? Do you think that’s going to be an issue?

Lynn Peterson

Certainly we’ve got a lot of publicity lately about the lack of this white sand and just from a simple standpoint, I think it’s -- when you think all the wells being completed in the U.S. right now and a lot of sand being used, I think we continue to use ceramics not because of that reason but because we think that it’s holding the fracture system open and the depth that we are drilling these wells at and the pressures that we see, we believe it will crash the sand. And when we look at a non-op of our areas, people are at least using some portion of ceramics. I’m not aware of too many wells that are just packed full of 100% sand in the deeper part of the basin. So I think it’s real. And I think from our standpoint the use of ceramics we’re going to continue, it works both ways in our regard.

David Tameron - Wells Fargo

Okay. My other questions have been asked. So, thanks. Appreciate it.

Lynn Peterson

All right. Thanks, Dave.

Operator

Our next question is from Paul Grigel of Macquarie. Please go ahead.

Paul Grigel - Macquarie

Hi. Good morning.

Lynn Peterson

Hi, Paul.

Paul Grigel - Macquarie

Just wanted to confirm you guys mentioned 22 to 25 wells being completed for second through fourth quarter, so that would kind of with the 15 in the first quarter. That would imply roughly 90 wells for the year, is that right? I just wanted to make sure I heard the correctly.

Lynn Peterson

Yes. Paul, I mean, that’s just operated. So then on an non-operated, it’s still close to that 100 net that we originally forecasted.

Paul Grigel - Macquarie

Okay. Perfect. I just wanted to reconcile that. And then on the crew, the second crew that you guys have going full time right now. Can you just kind of give a high level discussion on where you’re thinking for second quarter, third quarter, fourth quarter, does that go throughout the year, or is there a plan to kind of drop and come back and forth on that one?

Lynn Peterson

Again, Paul, I think we will do just what we’ve done in the past. We will use them as we need them. And we’ve got good arrangement with all of our completion work. So I think we’re in pretty good shape, everybody is out here and we have big times and we’ve gotten a one crew and big times. We will be pushing with two cruise. So we’re ongoing in that regard.

Paul Grigel - Macquarie

Thanks. That’s it for me.

Lynn Peterson

Thank you.

Operator

Our next question is from [Adam Francis] (indiscernible) Capital. Please go ahead.

Unidentified Analyst

Yes. Good morning. Thank you for squeezing me in here, Lynn. Could you speak to what you’ve seen in terms of monthly oil differentials, including your best guess of April?

Lynn Peterson

Well, I might ask Russ Cunningham if he wants to jump in here too, head of marketing, he and Jimmy, do you guys want to speak to that?

Russ Cunningham

Well, I think we’re still pretty comfortable using $10 differential on average. We’re going to see it very bit from there. I think April where it’s just a little bit wider than $10 if I remember correctly Bruce. And look at first quarter, I think we are just a little bit under $10 differential and that was, we get water in in January, then it’s closed up here in February and March and April. So we’re continuing to use $10 for internal budgeting purposes, knowing there’s a lot of complexity that goes into that number. So as we kind of see the waterborne prices with Brent and where they’re at now and transportation costs not changing too much, we’re pretty comfortable with that number still.

Unidentified Analyst

Very good. Thank you, guys.

Operator

Our next question is from Jason Wangler of Wunderlich Securities. Please go ahead.

Jason Wangler - Wunderlich Securities

Good morning guys. Just curious -- you mentioned Lynn real quickly there on the rigs as you switch some out, how many are you switching and when do you get that done? Could you maybe just speak to the seven rigs that you have as far as that high spec nature of them?

Lynn Peterson

Yes. Russ, I will let you jump in here too. We’ve got one new rig coming, (indiscernible) rigs. I believe we are hoping to see that kind of the end of the second quarter here. We’ve got a second one scheduled for kind of late third quarter I believe -- and they’ll be replacing two of our existing rigs. So we’ll maintain our 7, but we just think there will be a little bit more efficient.

Russ Cunningham

They will be more efficient, Lynn. We’re going to replace two of our oldest rigs with the new rigs, less loads, say we get 2200 horsepower, 7500 psi circulating system so we can hang out these laterals and we expect them to perform well.

Lynn Peterson

Russ, you mentioned loads, I mean trying to give them magnitude about what we’re seeing in the changer. Some of the current rigs we’re looking at 85 to 100 loads to get the rig moved. The new series 400 gross rig from unit, we’re expecting that number to be down in the 55 to 65 range, so quicker moves, gets down days. We took two days off a rigs move. I can drill an extra well every year per rig.

Jason Wangler - Wunderlich Securities

That’s helpful. I appreciate it.

Lynn Peterson

You’re welcome.

Operator

Our next question is from Jason Smith, Bank of America Merrill Lynch. Please go ahead.

Jason Smith - Bank of America Merrill Lynch

Good morning guys. Most of my questions have been answered at this point, but just a really quick one on Wildrose again. Just curious have you guys held everything that you need to hold at this point or are there any requirements anytime in the future to head back up there?

Lynn Peterson

We’re in pretty good shape. That was really the reason to get this done. I’m sure we’ve got some outlying interest, but all of acres are in great shape. That was really -- just to get it done, put it behind us and we’ll move down the road.

Jason Smith - Bank of America Merrill Lynch

Okay. Thanks guys.

Lynn Peterson

Thank you.

Operator

And this concludes our question-and-answer session. I’d like to turn the conference back over to Lynn Peterson for any closing remarks.

Lynn Peterson

Thank you. At this time I’d like to say thanks to all of our employees for your continuing efforts and dedication to the long-term success of Kodiak. We’ve been through several winters in the Williston Basin, but we continue to learn from each one. The lessons gained over the last few months will be put to work and help us better prepare for the next one, but just as the winter happens every year so does the spring, summer, and fall.

The Williston Basin continues to be a top-tier basin. As highlighted in the press recently, IHS estimates the Bakken has produced 1 billion barrels of light sweet crude oil. We think that there is much more to come over many years ahead, so our goal is to maximize recovery of those resources on our acreage and the corresponding value for all of our shareholders. We remain excited about the opportunity and I look forward to updating our investors on our pilot programs in the future as we work to define a plan to best develop asset base.

Before we leave you today, I want to play a weather forecast that we received late last year. As I usually don’t have a lot of faith in these weather productions, I guess we did not take seriously enough. So with that, I will share the following with you and ask Aaron to play the recording.

[Video]

So with that, I want everyone to know we are alive and well and very happy to be reporting that it is now May 2. We want to thank all of you for your time this morning and your continuing support. We will be back on the conference circuit the next week and on the road to see many of our investors. Get your Derby pics in, have a great weekend, and we look forward to speaking to all of you soon. Thank you very much.

Operator

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

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