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Kodiak Oil & Gas (NYSE:KOG)

Q2 2012 Earnings Call

August 03, 2012 11:00 am ET

Executives

Lynn Alan Peterson - Chairman, Chief Executive Officer and President

Russell A. Branting - Executive Vice President of Operations

James P. Henderson - Chief Financial Officer, Principal Accounting Officer, Executive Vice President of Finance, Treasurer and Secretary

Russ D. Cunningham - Executive Vice President of Exploration

James Ernest Catlin - Executive Vice President of Business Development and Director

Wally O'Connell

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

William B. D. Butler - Stephens Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Mark Lear - Crédit Suisse AG, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Paul Grigel - Macquarie Research

Operator

Good morning, my name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Kodiak Oil & Gas Corp Second Quarter 2012 Financial and Operating Results Conference Call. [Operator Instructions] Please be advised that our remarks today, including answers to your questions, include 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 turn the call over to Lynn Peterson, Kodiak's Chairman and CEO for today's prepared remarks.

Lynn Alan Peterson

Thank you, Christie, and good morning to everyone. As always, we will take your questions at the end of this call. Before we begin, let me introduce some members of our management team that are on the call today. James Catlin, Jimmy Henderson, Russ Branting and Russ Cunningham. We have also asked Wally O'Connell, our Reservoir Engineer to join us this morning.

We appreciate your time this morning as we discuss our second quarter results. Given the positive response in the format of our call from our last quarter, we again will attempt to keep our scripted comments to a minimum to leave plenty of time for Q&A.

As always, please reference the news release, and our filing on Form 10-Q, both of which were made available last evening, for further details and full disclosure of the topics we are discussing today. We're not going to recite all the financial numbers that we issued, since we know all of you can read them directly off our news release and 10-Q.

Last evening, we reported earnings per share of $0.10, which is in line with the consensus expectations of second quarter 2012. We also reported adjusted EBITDA numbers of $68 million, driven by oil and gas sales of $86 million. These are solid results that we expect to improve during the second half of 2012.

Also, a couple of weeks ago, we reported our second quarter average daily sales volumes of 12,700 barrels of oil equivalent per day, which represents a 20% growth from the first quarter of 2012 volumes of 10,600 barrels of oil equivalent per day.

We've provided an update on our completion activity in yesterday's earnings release, where we announced initial rates on 3 wells with 2 additional wells just beginning flow back. All of our wells down through the core area of the play continue to perform very consistently.

I would note that we completed one Three Forks well in our block of acreage in northern Williams County that had initial rate of 225 barrels of oil per day equivalent. This was the well that had been drilled by the prior owner of the acreage that was acquired in January 2012. The well was stimulated utilizing white sand tailed in with resin-coated sand, which brought our completion cost down by nearly $2.5 million. Looking at overall economics per well drilled in this area, we believe we can achieve an internal rate of return of approximately 20%, assuming a completed well cost of $7 million to $7.5 million, with ultimate estimated of recovery of approximately 300,000 barrels of oil at an 82% net revenue interest.

While these wells did not meet the returns we're achieving on our other blocks of acreage, the wells are certainly economic. However, with that said, at this time, we do not anticipate further activity in these area in 2012 beyond the possible completion of one more well that, again, was drilled by the previous owner that awaits stimulation.

From our operations standpoint, we are seeing improvement in both drilling and completion operations. We have evolved from 3 rigs, a year ago, to our current 7-rig count. A large part of the drilling gains can be attributed to increased drilling crew stability and the crew's growing interaction with our corporate staff that has developed by working together for 6 months, to a year, in some cases.

We are gaining efficiencies by consistently running rigs in certain geographic areas where we have improved geologic knowledge, as well as further refining our drilling procedures. We believe that this reduced drilling time will allow us to maintain our current rig count, yet drill the number of wells we set out in our original CapEx budget.

On the completion side, we are pleased with the use of cemented liners and have not encountered any completion issue since our use was initiated. We've had great success utilizing zipper fracs that are allowing us to complete 2 well pads in approximately 8 to 10 days. At this rate, we believe we should be able to complete 5 to 6 wells per month with our dedicated crew.

Our completed well costs are approximately $11 million, as we continue to use 100% ceramics on wells located in the deeper part of the basin in southern Williams, McKinsey and Dunn counties. As previously noted, we have reduced the number of drilling days per well by 3 to 5 days. We continue to place great efforts into reducing water costs during drilling and completion operations.

We are starting to see some relief on the cost side, and if this trend continues, we anticipate that we should be able to reduce our well cost by 5% to 10% over the second half of the year and early 2013.

The company's current net production has been steady through July at an approximate rate of 17,000 barrels of oil equivalent per day. We are constantly questioned about our production guidance, and this morning we are going to try to explain our program.

We project that we can complete 5 to 6 gross wells each month, through the remaining 5 months of the year, with our fully dedicated completion crew. If we are successful with this program, that would total 25 to 30 gross wells from August 1 through December 31.

Assuming an approximate 75% working interest, which would equate to 18 to 22 net wells, we would be on target to complete 4 net wells per month. We have assumed a new well decline rate of 55% during the first 5-month period. We have also declined our starting 17,000 barrels of oil equivalent per day by an approximate 3% per month for the remaining 5 months of the year.

We have maintained our non-operated production flat from its current level due to the uncertainties of the timing of any incremental production. If we can add roughly 1,600 net barrels of oil equivalent production per day for each of the next 5 months, we would be in line with our previously stated 4-year average production rate guidance of 17,000 to 21,000 barrels of oil equivalent per day and, certainly, in line with our 27,000 barrel oil equivalent per day exit rate.

These numbers that we just laid out were based upon utilization of our existing contract for our full-time completion crew. As we have stated before, we intend to utilize a second crew, from time-to-time, as additional wells are ready for stimulation procedures.

I would now like to turn your attention to a couple of positive events that were disclosed in last evening's earnings release.

First, we're pleased to announce our mid-year estimated proved reserve quantities of 70 million barrels, which is 36% increase from our year-end 2011 pro forma quantities. Continued production history combined with strong well performance from our growing portfolio of Bakken and Three Forks producers drove the reserve increase. We remain oil-weighted, with an 86% crude oil reserve mix. For the record, our PV-10 value of the reserves are now at $1.4 billion, which is a nice increase from the $850 million PV-10 value we posted at year-end 2011, which were, again, adjusted for our January 2012 acquisition.

Another important announcement last evening, regards our expanded borrowing base, which was a result of a special redetermination. We expanded our syndicate by adding 7 additional banks. We would like to thank all of 12 banks that are now involved with us for their time and effort in providing us this credit facility. We now have $375 million borrowing base access, which is a 67% uplift from the $225 million previously available to us for borrowing. Revolver is an important source of the balance sheet flexibility and liquidity for Kodiak, as we continue on our growth trajectory.

We'll now move to our CapEx. For the first half of 2012, we invested nearly $300 million, including leasehold costs and infrastructure. This includes our operated activities, as well as our participation in our wells that are non-operated within our Dunn County area of mutual interest.

We are projecting to invest nearly $300 million in the second half of 2012, which would put our full-year capital spend in line with our initial $580 million CapEx budget.

In addition, we invested additional $38.8 million during the first half of 2012 on non-operated properties outside of the Dunn County area of mutual interest. The CapEx on non-operated properties is difficult to project since the timing is out of our control. However, given the high-quality of our leasehold, opting to go non-consent on wells and suffering the penalty is detrimental to the underlying value of Kodiak's leasehold portfolio.

Most of the non-operated activity in the first half of 2012 was associated with properties acquired in January 2012, much of which was incurred in the latter part of the second quarter. A significant portion of the non-operated acreage in this area is now held by production, and we expect that the net expenditures on these non-operated activities will be lower in the second half of 2012, as compared to the cost incurred today.

With the CapEx incurred on these non-operated properties and projecting a range of expenditure for the second half of 2012, we could see our total CapEx for the year being 5% to 10% over our initial projections.

Our 2012 drilling program is designed to provide flexibility in drilling high working interest well locations and in the timing inside of capital investment. We anticipate funding the remaining $300 million of the 2012 capital program with our cash flow, our existing working capital and the previously mentioned revolver.

Finally, I want to turn to the deferred tax -- income tax expense, a new reporting item that we posted during the second quarter and the first half of 2012. As you are probably aware, we have not previously accrued income tax on our income statement because of our historic tax and book losses. And we had recorded a valuation allowance against the deferred tax assets on our balance sheet resulting in a net neutral impact.

In the second quarter, we finally reached the point when under accounting rules it is appropriate to reverse allowance and begin accruing income tax. In the second quarter, you see the effect of this change with the year-to-date accrual for income taxes offset by the end effect of the valuation allowance reversal.

Keep in mind, the accrued taxes are deferred and there is no cash effect. For the benefit of our analysts on the call this morning, you can assume a continued accrual of taxes at roughly 24% rate for the remainder of 2012, which will increase to around 38% in 2013 when the affected devaluation allowance reversal rolls off.

With that, we want to thank our listeners for joining us on the call this morning. We want to thank all of our shareholders for your continued support. Now I'll turn this back to the moderator, and we'll be happy to take your questions. Thank you.

Question-and-Answer Session

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

You mentioned -- you just are going to assume that non-operated production is flat. Can you talk about how many wells your partners are drilling? And that more -- this is just for Dunn County, is your partner drilling -- I mean, rigs are drilling, with today, and kind of what is the production done from the beginning of the year to, say, through second quarter, what kind of increase did we see?

Lynn Alan Peterson

Well, Brian, we're going to treat all non-op together, I don't want to call out any [indiscernible] here. As far as our MI 2 rigs continue to run, they have been off and on through the first half of the year, and some are smaller working interest wells, again, some of these production's just delayed, and we're not able to account for it as quickly as we do our operated stuff. So we decided just to hold this flat. We think there's a lot of upside and to several of our numbers here but since we can't really tell you when that incremental production is going to come online and -- the numbers, it's just a tough call for us. But certainly, we think, it will be improving. I mean, certainly in Dunn County, we're making some good wells, and they're making some good wells. So there's no reason to believe this is not going to increase.

Brian M. Corales - Howard Weil Incorporated, Research Division

Right. And a lot of your peers in the Bakken that we've seen these big well cost increases, and yours have been relatively stable, is there something you're doing, or is it pad drilling that is -- or that you're driving cost maybe lower, you're gaining efficiencies? I know you mentioned water handling. But is there anything else that's driving that?

Lynn Alan Peterson

Well, I think, the first quarter, our well costs were really coming out of the fourth quarter 2011 and into the first quarter of 2012. Our well cost were in the $11.5 million to $12 million range. I think we have driven them -- the costs out, but I think Russ Branting and his team has spent a great deal of effort, and some of the bigger ticket items are the water. We use a lot of water while we're drilling and competing these things, and we've knocked that number down. Our days off of these drilling times is pretty significant. Our burn rate on a rig can be plus or minus $100,000 per day. So you start shaving of 3 to 5 days off of 7 rigs running and you start seeing some pretty significant numbers here. So it's a combination of everything. I think availability of services have certainly improved. And I think we're starting to see some of these costs come down a little bit. I might ask Russ Branting, if you want to add your thoughts on this Russ?

Russell A. Branting

It's a moving target, Brian, as you know. It's a moving target, but our costs on the drilling side have come down. We're seeing kind of across-the-board, we're breaking over where the costs are coming off, maybe 5% to 10% of revenue in the second quarter. And I think we'll continue to drive them cost down. As Lynn allowed our efficiencies in shaving off days continues to improve, and that's a huge factor for us on the drilling side. And produce water and just frac water, we sourced better water sources and we're doing a doing a good job on that.

Lynn Alan Peterson

And I think your comment about pad drilling. We're probably fortunate in that regard. I think our land team has done a great job blocking this stuff up. We're able to park these rigs on these blocks of acreage. And I know from -- as we go to different areas, geologically, it's challenging to keep wells and zone. And I think as we drill more and more wells in each of these areas the team has done on a great job of staying in the zone, eliminating, backing up and redrilling. So I think it's combination of a lot of things. And I tip my hat to the entire group at Kodiak, as I think everybody has done very well with these costs and trying push them down.

Brian M. Corales - Howard Weil Incorporated, Research Division

Lynn, one follow-up question. There's -- I'm assuming it's the just gas that's been flared but the difference between the production and sales -- should we start to -- is the kind of 1,000 -- a little over 1,000 barrels equivalent a day, is that something that should decline over the next several quarters? Or is that kind of the rough number as -- something that maintains as you get gathering lines put in?

Lynn Alan Peterson

Well, we hope to see that improve. One thing that hurt us in the second quarter, we brought 2 wells on in May. They were over in the southern Williams County, they're great wells. They were making a lot of gas. The pipeline was 2 to 3 weeks delayed getting in there. So we lost some of that plush production, which impacted our numbers and made them a little worse than what they should have been. But I think those numbers are going to improve. I think we've kind of all looked at our operated stuff, I think, we're probably selling close to 65% of the gas we're producing. As we work through the second half the year, we hope that number climbs closer to 80%, maybe 85%, as we go through the rest -- balance of the year, here.

Operator

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

William B. D. Butler - Stephens Inc., Research Division

Maybe on the pipeline hookups. Some of the curtailment there is related to gas processing plants further down the line. Is that something -- is there any update on that?

Lynn Alan Peterson

I think everything is improving quickly here, William. There's a lot of work being done. And we got one area we need to get a pipeline laid for about a mile. Once that gets done, we're going to have a much better percentage of our gas being produced. Yes, I think we continue to work through the Dunn County stuff. There's some systematic problems that are trying to be corrected at this point. I think we'll make some improvement over there. Some of that may not be reflected until later this year and into next year. But again, a lot of work is being done throughout the basin. Jimmy, do you...

James P. Henderson

No, I think, that's -- I think, as the processing capacity has come on, there's a little bit of replumbing that needs to happen on the existing systems, and that's what Lynn is alluding to. With a bit of pipeline that needs to be laid to tie some areas that -- or have too much pressure in areas that where compression's being installed. So that's in the works right now. And that should free up soon some capacity on the gas processing and transportation.

Lynn Alan Peterson

Maybe just to add a little bit more. Even getting away from the gas to look at our oil. We just have entered into an agreement with a third-party to lay pipe through our entire Polar area. We hope that this work is completed sometime at end of the year, or very first part of '13, which would really bring almost -- nearly of all of our oil production into oil pipelines. So we're pleased with that. Again, shouldn't change just numbers much, but it certainly will help us as we go to the winter, assuming we get a winter we did a couple of years ago, it would be very material to us. So we are pleased with that development. And again, a lot of changes have taken place here.

William B. D. Butler - Stephens Inc., Research Division

And then you had several strong wells, particularly southern Williams County in Three Forks. Have you all got any updated thoughts on downspacing and has your thought process evolved any since last quarter or is still the same?

Lynn Alan Peterson

We've continued to tighten these up a little bit. We have completed some wells that are closer to the 1,000-foot separation. At this point, it's way too early to really make any definitive conclusions. I think, as we look at other operators, I think the Basin, in general, people are starting to talk, maybe a little tighter spacing here. So there's work we're going to continue to be involved with and test. But I think everybody's just got to have a little patience here and let us get through some numbers and see what ultimately we see. Russ, anything -- would you like to add some to that?

Russ D. Cunningham

Well we had just started making some of these wells a little bit closer together. They're being completed, and we just need to see if we see any interference in the first several months. It's just too early to tell what the ultimate spacing will be right now.

William B. D. Butler - Stephens Inc., Research Division

Is that something you all would think you need 2 more quarters before you could discuss more, it sounds like, maybe not by next quarter even?

Lynn Alan Peterson

Unfortunately, nothing is ever quick enough for you guys. But, yes, just give some time and let the reservoirs engineers walk through, Wally's shaking his head over here, so he wants a little bit of time.

William B. D. Butler - Stephens Inc., Research Division

Got you. Okay. And then last one, on LOE, looked great on the quarter. Some you -- you think you should stay sub 6 for the second half of the year, is that fair numbers?

James P. Henderson

Yes, actually, this water disposal, we put some money into it, we drilled some wells. And Jim, Kevin, I might ask if you'd give your thoughts on this, see where we're headed?

James Ernest Catlin

Well, yes, obviously, we've done much better. And I think we're headed significantly lower. A good part of all this has to do with the disposal wells that we've drilled. The other thing, though, I think that's a big factor here is that we've added some really good people in the field to handle our water operations, both procurement as well as disposal. They've done an excellent job, and I think that we have to give the staff some credit, too, for just pushing on this real hard, and we think it'll significantly get better.

Lynn Alan Peterson

Well, you know, and that being said, we have made some big changes here. And so I think probably 5 to 6 is probably a reasonable number as we look at the next couple of quarters. So I don't know if we're going to see a dramatic change moving forward. But if we can get real consistency moving forward, I think that's most important.

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

Just turning to the balance sheet here, I'm looking at the leverage ratio, debt-to-EBITDA, could you express your comfort level on that ratio, what that might look like, say, with the balance of this year and in 2013 at least arranged based on your own internal models?

Lynn Alan Peterson

I'll let Jimmy run on that one.

James P. Henderson

Yes, Dan, I think we're still pretty consistent with our thinking -- the growth numbers that we've laid out ahead us, I think, we should be on a sort of annualized 2x ratio debt-to-EBITDA fourth quarter, first quarter 2013. So our goal is to push it down to 1.5x to 2x, barring any kind of acquisition that changes these numbers. But just on a continuing operating basis, we see it kind of getting into that range as we get into '13 as we annualize each quarter as we go.

Dan McSpirit - BMO Capital Markets U.S.

Okay. Great. And the price that the banks supplied in these last redetermination, out of curiosity?

James P. Henderson

I believe it was -- I think they're still around the 65 to 70 range. I don't have that right in front of me. But they -- it hasn't been reduced. They didn't take it up whenever oil was $105, so there wasn't a big reduction as it's come back into the high 80s. So pretty similar to what we've seen for the last 1 year, 1.5 years.

Dan McSpirit - BMO Capital Markets U.S.

Okay. And just turning to the Dunn County and the leasehold on the reservation. A peer of yours had, earlier this week, expressed experience in delays in permitting wells on the reservation. Any observations, any thoughts on that experience?

Lynn Alan Peterson

Well, again, a big tip a hat goes to Russ Cunningham and the whole permitting group. From day one out here, beginning in 2007 and '08, when we're getting our first permits, we were the initial team that really had to fight through a lot of the delays. I think, we developed some really good relationships. I think with our pad drilling that we initiated back in November of '08, the first rig we moved over here, we have got a big head start on all of our permitting work and Russ Cunningham gets a big part of this credit and -- Russ, I'll let you give your thoughts on where we're at and how you look at 2013, probably more importantly than where we're at today because we sure have plenty in the pocket today.

Russ D. Cunningham

Thanks, Lynn. I think that by the first quarter of 2013, all of our lands in Dunn County will be HBP. And we have already begun permitting development-type drilling locations. And we do have a number of permits, as well as locations built that we would be able -- ready to move a rig on in a short period of time. We continue to look ahead to get more permits and to build locations in the good time of the year, so that we're not out there scratching around in some frozen tundra.

Dan McSpirit - BMO Capital Markets U.S.

Got it, okay. And then one last one for me. On the subject of flaring the gas from the wells at the well site today, what do you see in terms of rules and regs changing over the next 6 to 12 months that may or may not present a risk to flaring that gas and producing the hydrocarbon from the wells? Any changes on that front?

Lynn Alan Peterson

I don't know if we've seen any real game changes. I think our effort is always get these wells hooked up. And again, when we look at all of wells out here in the Williston Basin, by the end of the year, I think, we're comfortable saying that we're going to have only a handful of wells that will still be not hooked up to a pipeline. Now again, due to plant capacity and build-out and some things that are still being done here, we're going to have times when we can't sell 100% of the gas that we're producing. This is a situation that the team deals with on every hearing we go to with the North Dakota Industrial Commission, and it's a very important item that -- we've tried to put a great deal of effort into this, really with the belief that we can be in that 80%, 85%, 90% in the pipeline by year-end. So our attitude is to take care of the problem before it becomes a problem, Dan.

Operator

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

David R. Tameron - Wells Fargo Securities, LLC, Research Division

You talked about well cost. Can you give us specifics as far as what's driving those? And does that continue in the next year, or is it just -- is it drilling days or is it more than that?

Lynn Alan Peterson

Again, I think it's a combination of all of it. It is our efficiencies, which is certainly a big part of it. But you know we are seeing some relief on the well costs. And again, I think it's more that the service company availability's kind of come closer to the rig count, and we haven't seen a big increase in rig count out here either. I mean, it's kind of held in, I think it's 210 to 220 right now. So there is such a huge push over the last, call it, 2 years. I mean, and everybody was trying to catch up and everybody was trying to get an acreage HBP'd, which is still continuing in some cases. But a lot of companies are starting to move in to more of a development mode. And so we've seen a little bit more stabilized rig count, which I think is really helping across-the-board and, again, Russ Branting, I mean if you want to -- you deal with this every day with more of the vendors and we're not going call out any particular vendors or any particular area, Dave, that has decreased but, I just think, generally, we're seeing an overall decline a little bit.

Russell A. Branting

Absolutely. Efficiencies on the drilling side come from the pad drilling. We don't have to move the rig, every well. We can walk it forward and be spudded and drilling within 24 hours on a normal basis. We also, like Lynn has alluded to a couple of times, we're seeing price decreases across-the-board from our service providers. And we're also in a situation in the Williston Basin where we can, basic, kind of shop around and get some better providers, so that's helping us too.

Lynn Alan Peterson

And that's probably, really, a good point, too. I think, even the quality of our crews and -- some of us don't -- we take for granted but -- we were at 3 rigs a year ago, so we brought in 4 new rigs. We've integrated new people. Our team here in Denver that calls the shots, working with these guys every day for -- anywhere from, like I said, 6 months to a year, it has a big impact and as they get more comfortable with us, we get more comfortable with them, we work together closely everyday. We're just seeing better and better work out of everybody and the water costs -- we use water in drilling, and we were paying a lot of money for this early on and we've got a team here that, as Jim mentioned, has done a great job procuring water here and all of these things add up. And it takes time, some of these numbers don't flow through the financials as quickly as you want them, but we certainly see it here in the house things are getting-- are improving.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, that does add some color. And then secondly, as far as transportation cost and, I know there's been a lot of projects that have been added and some still to add. Can you talk about if we think out the next 12 to 18 months, where would you expect transportation costs and I guess, by default, kind of differentials, what's your outlook there?

Lynn Alan Peterson

Jimmy wants to take a shot at that one. He always laughs at me when I turn to him.

James P. Henderson

Yes, differentials are a tough one to predict, as everybody knows. We're certainly seeing transportation pathways improve and certainly the biggest thing, as we've talked a lot is the oil loading facilities that have come up on the Burlington, where the railroad over the last just few months. And that's obviously moved some supply into a different direction off of Enbridge. We've seen Clearbrook come in quite a bit, and right now, I think it's about $5 under WTI, which is a big improvement from what we saw in the spring prior to these oil -- the rail facilities coming online. I think that's part of it. But the pipe going in the ground locally has been a big help, as Lynn mentioned. We were just contracted to pick up the Polar area and the pipe, and our plan has to move that oil up to the rail loading facility that also has an outlet into Enbridge. So I'm not saying that's going to improve our netbacks necessarily, but it will improve efficiency and ability to move in who we sell to. So hopefully, that will translate into better netbacks. I'm not going to guide that way at this point. But I think all of these things, just like everything that we've talked about service cost, et cetera, have gotten better in the Basin, as the industry as a whole has pushed to develop this play and a lot of it is coming back to roost now.

Operator

Your next question comes from the line of Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So it looks like you guys like the performance front[ph] of the cemented liners versus, I guess, some of the issues you had with the plug and perf. I mean, are you guys pretty much looking to stick with cement liners? Or because you've got -- the efficiency is down, or is there any reason to want to look at plug and perf? And remind me, are you doing any hybrids in as well?

Lynn Alan Peterson

Well, first of all, all these cement liners are all plug and perf. So...

Scott Hanold - RBC Capital Markets, LLC, Research Division

I'm sorry, yes, I'm sorry, I misspoke there. But I think you get my point.

Lynn Alan Peterson

I know exactly what you're talking about -- and Russ, again, jump in here. I think at this point, we're very pleased with the success we've had with the cemented liners. I think being able to draw the wells on pads where we've able to get 2 or better wells on every pad. Being able to utilize wireline services to do these zipper fracs, we really got our days -- completion days down to a very reasonable timeframe. We just completed 2 wells just this week. I think we were on the wells for 8 days as I recall. I think the others have been closer to 10 days. But if we can get 2 wells done every 10 days, I think we'd be pretty delighted. And probably more importantly is we really do not have to worry about the external packers anymore, or the sleeves or any of that. We look at the risks that we encountered with those items versus any additional time we might be incurring on the completion, we think it's a no-brainer. So we like the well performance. And guys, Russ and Jim, you want to add something?

Russell A. Branting

I have no intention of going back [indiscernible] .

Lynn Alan Peterson

We kind of got tired of that question, so we're pretty happy where we're at.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. [indiscernible] And as far as like even [ph] these well pads -- ultimately it sounds like you're doing 2 wells per pad right now. And where is that going to go and does that get 2, 4 and 6? Where are we going with that?

Wally O'Connell

Actually as I look at our 7 rigs, I might be off here, but I think we got 4 of them on 4 well pads and 3 of them on 2 well pads. And so that's kind of our go forward. We are going to try some larger pads. We're even toying with the idea trying to put a couple of rigs on a pad to drill them quicker so we can get to completion quicker.

Russell A. Branting

Yes, again, I give a lot of credit to our operation guys. I think we're trying to think outside the box. We're trying to figure out how we get from spud date to date of first sales on a quicker basis. And we really like our pad drilling. We think it has helped us drive down our cost. We think it's certainly going to improve as we go forward. But what we'd like to see now is to expedite the timing to get these wells on production. And that's really our focus as we go out of '12 and look at our 2013 drilling program. So you'll see us drill more wells as opposed to fewer wells per pad, I think, is a fair statement. And I believe as we look forward I'm not sure we have, but maybe 1 or 2 wells that are going to be single wells even going almost into '13. So we're definitely pad drilling.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Is some of that -- just basically your leaf position that will dictate whether or not you can put multiple wells on a pad area or is that not necessarily the case?

Lynn Alan Peterson

Well not necessarily. I think some of it had to do with the acreage we acquired. The orientation of the wells that have already been drilled, we're trying to work through that right now. And so we've had one situation we've got to drill one well, but again, from that point forward, we are multiple wells, 2 to 6 I think is a probably a fair number.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And on your full year production guidance and -- what do you assume in there, in terms of like how much of the gas that's being flared comes online? Is there an assumption that it improves? At the end of year, you said 85%, 90% was your hope. But -- what number have you baked into guidance?

Lynn Alan Peterson

We're at 60%, 65%. I think it's around 60% actually. But we actually are trying -- we've tried be as conservative with all these areas that we can and really go with what exists today. So we'd not try to build any improvements in that regard.

Operator

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

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Sorry, if you've hit on it earlier, but what caused the GOR jump in Polar? And is that something that we should expect going forward?

Lynn Alan Peterson

Yes, Russ, can you hear? Why don't you jump on this? And you can talk from a geology standpoint.

Russ D. Cunningham

Well, the GOR is controlled by, not only the depth but also the paleo-temperatures. And so we've had some more gas in some of these areas where we have higher geothermal history. And so as you get to the basin margins, you probably have lower gas because you are not, number one, as deep; and number two, you don't have the same thermal history. So these areas it’s not unexpected that we see these things, and we're just happy that we're getting such good wells in this area.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Yes, that's fair enough. And then one last one. Can we get an update on the Grizzly wells, are these holding in pretty flat, as expected?

Lynn Alan Peterson

Yes, actually we are pleased with what we're seeing over there. Again, I think, we've got a couple of wells we didn't get up to the completion that we hoped for, but where the wells are, they're doing fine. That hyperbolic decline rate that you see in other areas, and Wally, do you want to add? You probably look at them closer than I do every day.

Wally O'Connell

Yes, I just looked at them today, and they have much shallower decline than we typically see in other areas. It's a little different area, a little different property than most of the other areas, it's lower pressure, lower temperature. But it's doing fine.

Lynn Alan Peterson

And again, Russ Cunningham, maybe you just comment quickly. I mean, we get these blocks of acreage, and we call them one name, and the rocks can change within the boundaries of that prospect area.

Russ D. Cunningham

If you look of the western portion of Grizzly, we're much shallower coming out of the basin and the stratigraphy is beginning to change more rapidly on the west side. As you move to the east side and the north part of Grizzly, you have different stratigraphy, different targets and different expected outcomes on the reserves, as well as getting a little bit deeper and therefore probably seeing a little higher pressures. And so there is a lot of variability when you say the Grizzly area that's kind of a large area in southern McKenzie County. But there's a lot of area variability in the geology.

Operator

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

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

This is Hsulin. So my first question is a clarification question. So current production, I think you said 17,000. If that's 17,000, what is base decline rate because you said 3 months -- or 3% every month? And out of that, what is the non-op production?

Lynn Alan Peterson

Well, okay, this is Kodiak Oil & Gas Corp. We're going to deal with the company on a broad base. We're not going to go into the non-op and call out any of our industry partners here. We're going to treat this as a company, as a whole. Again, we used a 3% decline rate for our -- kind of our base production that's been on anywhere from 3 years to 4 years, I guess now to a few months. And I think that's a very fair number. When we look at quarter-over-quarter declines, it's much lower than that number but again, just to try to give you guys an idea of how we go about trying to predict our production, we used the 3%. And I'm not really going to break that down to non-op and operated.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And second question is actually a follow-up with Jimmy, in terms of the leverage ratio. So you said the -- I mean you've got your focus on the 2x for debt to annualized EBITDA's. And if I look at your near-term EBITDA, number it looks like you are higher than that right now. So is this more something -- I guess do you look more forward in terms of when you get that number? And also, do you have any -- what are your covenants currently? I'm sure it's higher. But I just wanted to kind of get an idea.

James P. Henderson

Yes, I believe, the current -- the covenants it's just on the revolver, I believe, it's 475 and it kind of ratches down over a period of time. That's actually in the 10-Q we just filed, so I may be off a little bit. I can double check. And, yes, whenever I talked about the leverage ratio, I was talking -- I was projecting forward. I think the previous analyst is asking about where we expect to see it as we get into the 2013 and I was -- when I talked up about annualizing, it's not a trailing 12 months as it's typically calculated, but taking, say, the fourth quarter '12 or the first quarter '13 and annualizing that number to get a leverage ratio based on our where we expected it to be at that time.

Operator

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

Mark Lear - Crédit Suisse AG, Research Division

In terms of the rig count, delaying the delivery of the 8th rig, when can we expect that to see -- to show up? And I guess, ultimately, as Kodiak stands today, where do you think you optimally should be in terms of how many rigs you can run and when you kind of see that peak out in the program?

Lynn Alan Peterson

Well again, Mark, as we've tried to state here, we're not even sure we're going to go to 8 rigs. And if we shaved 3 or 5 days off of every well we've drilled and you if look that over a 10-well program, you'd save nearly 30 to 40 days, which allows you to drill one extra well, which -- if you've got 7 rigs running, you're going to make up for that 8th rig. So right now, we're really comfortable with our 7 rig count. We think our efficiencies are getting better. We think we're going to drill the same number of wells that we had budgeted with the 8th rig. So I don't think it changes anything. I think we can just keep doing what we're doing here with the staff on the rigs and the rig count that we have.

Mark Lear - Crédit Suisse AG, Research Division

Even looking out to '13, '14, beyond, I guess, was kind of thinking even longer-term. I mean, given that it's an accelerating NAV sort of story.

Lynn Alan Peterson

If you can tell me what oil price is going to be, I'll tell you what our rig count's going to be. I mean, we're going to look at this on an on-going basis. I mean, a month ago, we're being asked how quickly we can lay our rigs down because oil was at $80 and they thought the world was coming to an end. This is an evolving deal. It changes quickly. It changes everyday. And our team -- we've got our rigs set-up on various termination schedules for right now. We can escalate activity if we want. We've got plenty of permits in hand. We've got great acreage to drill. We can also decelerate, if we need to, if oil prices go the other way. So I guess, we're not going to lay out our 2013 budget today so I will tell you, currently, we're going to stay at 7 rigs. And we're going to try to get better and better at what we're doing here, and I think we're going to get more wells drilled with each of those rigs.

Operator

Your next question comes from the line of Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Say, Lynn, just a couple of follow-ups. A lot of the peers are going after all these benches and such, just want to hear your thoughts, when you look at some of your plays, especially, I guess, more on Dunn and some of these others, but doing that down the line?

Lynn Alan Peterson

That's the beauty of this play, there's so much upside left to be had here and, I mean, this is what brings us to work everyday and gets us excited with what we're doing. And I don't think anybody knows how much oil is really out here, still. So again, I'll probably ask Russ or Jim Catlin to pipe in here as we look at these various areas. We've got one guy spending a tremendous amount of time looking at all these different benches. So either one of you guys want to throw your thoughts?

James Ernest Catlin

Obviously, it's something we've talked about everyday. Fortunately, we have some other operators in the basin that are doing a more aggressive job of looking at these, particularly, the second, third bench of the Three Forks. We're watching these. Without question, the success in the second bench has expanded the total reservoir significantly. And at this time, we're not drilling any, but we think it is going to add to the play, and we're back at very closely watching developments in the third bench to see what the results are, and subject to those, we'll pursue them. But obviously, the -- it is a great thing here that we continue to find more and more, and we expect that there'll be additional things developed in the years to come here.

Russell A. Branting

And I think what we've talked about in the past is, I think, Kodiak's been more focused on maybe looking how tight we can get these wells and what kind of impact that has on drainage. And so that's been our effort and it's going to continue to be our effort here, as we move through the year. And we'll let the rest of the -- as Jim said, the rest of the industry continue to work on some other ideas. So I think, in general, the industry has made great strides out here, I think a lot of people are doing a lot of good work. Yes, I know costs get high, and people get nervous about them. But I think, again, if you sit back a little bit and think what's going on out here, this is a first-class play and has a tremendous upside that probably nobody can even quantify at this point.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Lynn, what about when you look at kind of, as you keep tweaking the completions a little bit, when you look at now like ceramic versus all the different types of sand, are you pretty content of where you are now? Or is that something you're always looking at?

Lynn Alan Peterson

Again, when we look at the deeper part of the basin where 80%, 85% of our acreage exist, we're going to stay with ceramics. And we hear it all, we continue to look at our production, we have evaluated wells that have been drilled with sand, I mean, and again guys, this is -- everybody has their own idea here. We think we're making some pretty decent wells. And we think the incremental cost that we're incurring upfront is going to pay off. We think it pays off early on. But really, ultimately, what is going to be the terminal decline rate of these wells, and I know that's what we continue to think about. Again, we use a probably pretty -- towards the higher end of the terminal decline rate range but, I think, ultimately, it could be lower than that, which changes our reserves dramatically. So to answer your question, in a nutshell, we are believers in ceramics. We're going to continue to use that in the deeper part of the play. As I mentioned, when we did this well up north, we did change. And you know we're fine. It's not the same geologic picture that we see where we're at, your shallower, lower pressures, all the things we talk about all the time. So again, it's debated everyday.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And lastly, Lynn, obviously the differences are -- seems to -- number one, I guess, just difference is not silly question as far as where you think they’re going to be, but just, again, volatility, are you still seeing the same type of volatility in differentials, and then, I guess, what are they currently?

Lynn Alan Peterson

Certainly volatility is there.

James P. Henderson

This is Jimmy. I think we'll continue to see volatility in it. And there's so many things that go into that equation, how much oil is coming down from Canada versus how much they're able to refine locally up there. Where the rail facilities are coming on and the availability of rail cars, all these things go in an equation, as everybody knows here. But right now, Clearbrook is $5 off WTI, which is kind of the Bakken's lookalike, or it's one of the key ingredients to the Bakken netbacks. So it's certainly come in quite a bit from what we saw just in February and March. But it's tough to give you guidance on where we expect that to be as we talked earlier. It's just too many ingredients in that cake. So but it certainly looks better today than it has earlier in the year.

Operator

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

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just a quick question. I guess the follow-up to the last question, you're pretty comfortable with the completion recipe right now, so we shouldn't expect anything in terms of perhaps dropping frac stages in order to cut costs here because you still sort of feel like you need to pay upfront for the -- to come out with the most optimal decline rate.

Lynn Alan Peterson

Again, I think our completion guys have really -- they done a lot of modeling here. We did try some wells going up into the low-30 stages. We don't believe that we're getting the incremental production that warrants additional cost. Again, I tip my hat to them because I think our technique we're utilizing today is really reaching this fracture system, we're making good wells. I think we've sort of settled in here around 28 stages, which is going to be some 325, 335 feet per stage, roughly. And I think we're pretty comfortable with that. Are we're going to continue to look at things? Absolutely. The guys look at things everyday. And could we do something different? Certainly. Don't hold us to that we're going to be, every well 28 stages. Again, that's part of what we're doing here. This is part of the evolution of this play. And there's so much oil to be had out here, we got to continue to work at it. We'd be the first to tell you we don't know all the answers. We're continuing to work at it. And I think, again, our well performance speaks for itself.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Certainly. I guess getting back to Wild Rose quickly. I know that you all had sort of set expectations low here. And then the wells ahead -- the 2 that have been completed were drilled by the previous operator. And this acreage is held by production, so there's no real incentive to drill here. But considering it is a 24,000-acre block, do you sort of feel like most of the acreage is condemned at this point? Or it just doesn't stack up relative to what's in the rest of the portfolio?

Lynn Alan Peterson

I'm not sure why you'd say condemned. You make a 20% rate of return as we tried to explain earlier, it may not be what we're making on these other wells, but that's not a bad return. In a lot of plays, it's pretty good. Are we putting our capital to the other parts where we're getting a better rate of return? Absolutely. But there's nothing wrong with that play. We've got to work and bring our well cost down. I mean, we throw these numbers out, we haven't drilled a well, so we don't know what we could drive them to. Let's not get too excited about initial rates here. These wells have set for probably 6 or 7 months here until we got them completed. This area has a low GOR and has more water. We need to get the wells on pump and see what they're doing. So I think everybody's trying to make conclusions based upon pretty tough information at this point. And again, we look at a broader base, Wally has looked at a lot of wells up here. Again, they're not 40%, 50% rate of returns that we see in other areas, but these wells are fine. And I don't really understand why the condemnation comment has come up in a few cases.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Yes. Perhaps the verbiage is a little extreme. But I appreciate the color. And then I guess, you guys will have really the entire program held, by mid-next year, I guess, with 7 rigs. So is there -- when you talked about the 7 rigs, based on the strip now is it -- do you think about it just in terms of holding acreage or is there sort of a percentage without spending cash flow now beyond 2012 that you feel comfortable with when you set your budget?

Lynn Alan Peterson

Well again, we're going to work through 2013, I think, as we've made very clear at the Street, we felt like we were going to get into kind of cash-neutral position as we go out of 2012 and into the early part of '13. With -- really 2013 being our turnaround year where we become cash positive, absolutely. We're going to look at cash flow and resources available, what type of wells we're making, all of these things are going to come into play. But I don't think anything has changed internally. How we feel about where Kodiak's at, at this point, and Jimmy, do you want to add anything to that?

James P. Henderson

No, I think that pretty much summed up -- as we work through the process here, this late summer and fall, as we look into 2013, it all goes into our -- through our thinking. And I think anything's changed as far as our modeling things up to the next couple of years.

Operator

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

Paul Grigel - Macquarie Research

Regarding the go-forward assumptions and reaching year-end guidance. On the working interest, earlier in the year, you guys had definitely higher working interest wells. Recently, the last couple updates have been lower. What assumptions are driving the 75% going forward, in terms of wells being planned out that are-- that are relatively higher versus lower working interest?

Lynn Alan Peterson

We actually have our wells laid out for the rest of the year. We do know what our working interest is in these wells. And we know what our averages are so it's actual facts.

Paul Grigel - Macquarie Research

Great. Just wanted to make sure. And just following up on that real fast, you guys look like you'll be completing just short of 11 net wells for the quarter. Is there another well that can sneak in there, to kind of meet the 4 per month? Is it just kind of a timing issue with the pad drilling? Just trying to get a little color on that.

Russell A. Branting

I wish our world was so clean that we could put it all in a spreadsheet and everything would work so perfectly.

Lynn Alan Peterson

We're trying to give you guys guidance and it's not going to be exactly what happens. Again, these things -- it's a moving target. And as we said, there's a lot of upside to our numbers. We got a second crew that we've been using from time-to-time, we intend to do that again. So I mean, believe me, don't hold it against us if we get more wells completed. We're trying to give you numbers that we can meet our guidance with and make you feel comfortable but certainly, at the same time, we think there's a bunch of upside here that we can deal with.

Paul Grigel - Macquarie Research

Lynn, we appreciate the details, it is helpful. You had mentioned land swaps [ph] kind of as you consolidate positions and build working interests as well, just -- you've mentioned in the past that acquisitions continue to be small, is that a way that you kind of view the ability to grow going forward?

Lynn Alan Peterson

This basin continues to mature, there are few things certainly still around. Obviously everything is continuing to ratchet up, I think, in costs, as the results continue to improve here. So these are all things that we're going to keep evaluating and, if we find the right opportunity, we will chase it. Are we're going to be successful? I certainly can't guarantee that. But it's an area that we really believe in and we are going to continue to work it. So I don't know if I can tell you where we're headed because I don't of exactly was going to become available over time.

Paul Grigel - Macquarie Research

Okay, lastly, on CapEx -- not to get into people that's not my intent here, but more so from the intention of -- you guys had mentioned that you would continue to participate in AFEs -- does there come a point in time if AFEs reach a certain point or certain areas that they would go non-consent on? On wells, on a discretionary basis?

Lynn Alan Peterson

Sure, we evaluate everything. And again, there's been some costs that have been incurred. Everybody's going to be coming down here. This play is getting better and better with time, that's the fun part about it.

Operator

I guess [ph] we've reached our allotted time for questions today. It's my pleasure to hand to program back over to Mr. Peterson for closing remarks.

Lynn Alan Peterson

I apologize, we can't get to everybody, I know there's some people still in the queue, but we'll be glad to address those individually. We just had to call this to a close. I do want to thank our staff, both here in Denver and in the field in North Dakota, as well as our service companies. And everybody's come together and helped us execute our program. We do feel strongly that we're on course to deliver our stated goals. The well performance that we continue to experience makes us a world-class resource play and Kodiak's become a very meaningful operator in the play. I know we can't please everybody on the timing of such things and the cost of everything. Everything will take a little bit longer than we always expect. I will say that I'm extremely proud of our team's accomplishments. At this time, we're going to close the call. I hope everyone has a great day, and we will look forward to talking to you again in 90 days. So thank you very much.

Operator

This does conclude today's conference call. You may now disconnect.

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