Northern Oil and Gas Inc (NOG) 2012 Q2 法說會逐字稿

Good day, and welcome to the Northern Oil and Gas Incorporated second-quarter 2012 earnings release conference call. Today's conference is being recorded. I would like to turn the conference over now to Mr. Michael Reger. Please go ahead, sir.

Thank you, good morning. My name is Mike Reger. I am the Chairman and CEO of Northern Oil and Gas. Also with me today is Ryan Gilbertson, our President, and Tom Stoelk, our Chief Financial Officer. We are excited to welcome you to the 2012 second-quarter earnings call for Northern.

Before we begin this morning's call, you should be aware that certain statements made during this call may contain forward-looking statements, and are based upon management's expectations, estimates, projections and assumptions, and that involves certain risk and uncertainty. We encourage you to review the various risk factors relating to our business, which we most recently updated in our Form 10-Q for the first quarter of 2012 that we filed with the SEC on May 7, 2012. These forward-looking statements relate to our future plans, objectives, expectations and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

During this conference call, we will also make references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in our earnings release on Form 10-Q filed with the SEC this morning.

The second quarter of 2012 was another record quarter for us, in terms of production, oil and gas sales, and adjusted EBITDA. We also had another great quarter of acreage acquisitions, adding over 7,000 net acres to our portfolio of prospective Bakken and Three Forks acreage, and bringing our total to approximately 180,000 net acres in the play. We also have now reached about 109,000 net acres that are either developed, held by production, held by operations or permitted. During the second quarter, we added 162 gross, 15.8 net wells to our production base. That is approaching two gross wells added to production per day, including weekends and holidays. Total wells added to the production base during the first half of 2012 was 291 drilled, and 29.7 net wells.

Today, we are one of the largest non-operators in the Williston Basin, and remain a clearing house for non-operated strategic working interest. We continue to grow our production, reserves, and acreage positions, as we expect very limited acreage expirations throughout 2012 and beyond.

I would now like to turn the call over to Northern's President, Ryan Gilbertson, to highlight our second-quarter operating results.

Thanks, Mike. Northern Oil had another excellent quarter, with production increasing 136% for the second quarter of 2012, as compared to the same period last year. Our total production for the quarter was 947,000 Boe. Our sequential quarter-over-quarter production on a Boe basis increased 22%, and reached approximately 10,400 average barrels of oil equivalent per day in the quarter. Our average daily production during June increased to approximately 11,000 barrels a day.

As of June 30, 2012, we controlled approximately 180,000 net acres in the Williston Basin, Bakken and Three Forks play. During the second quarter of 2012, we acquired leasehold interests, covering an aggregate of approximately 7,060 net mineral acres in our key prospect areas for an average cost of $2,184 per net acre. During the second quarter of 2012, we had leases expire, covering approximately 1,400 net acres. We currently have approximately 865 undeveloped net acres that may possibly expire, that are prospective for the [Bakken] and Three Forks plays in the remainder of 2012. This represents less than 0.5% of our overall Williston Basin position.

In the first half of 2012, we spud 22.5 net wells, and continue to expect to spud approximately 44 net wells for the year, in line with our initial guidance. Based on current drilling and completion costs for AFEs received from operating partners, we estimate that our average completed well cost will be $8.8 million this year, up from a previously estimated $8.2 million. As a result, we expect capital expenditures related to 2012 spud wells to be approximately $387 million, an increase of $27 million from our previous estimate.

In the first half of 2012, we spent $25 million on acreage acquisitions, and we currently expect to spend a total of approximately $50 million on acreage acquisitions during 2012. This represents a reduction in our previous guidance of $60 million to $80 million in acreage acquisitions. As indicated in this morning's press release, we announced our mid-year proved reserve quantities of 57 million barrels of oil equivalent, which is a 22% increase from our year-end 2011 quantities. Our reserve base continues to be heavily oil-weighted, with a 90% crude oil reserve mix. Continued growth from our growing portfolio of Bakken and Three Forks producers drove the reserve increase.

At this point, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some of the financial highlights.

Thanks, Ryan. We reported net income of $43.6 million for the second quarter. Net income included $49.8 million pretax unrealized gain on mark-to-market derivative instruments. Excluding the unrealized mark-to-market gain on derivatives net of tax, we reported net income of $13.6 million, or $0.22 per diluted share. As Mike mentioned, our earnings release includes a reconciliation of these non-GAAP numbers to net income and net income per share.

Strong cash flow growth was a key second-quarter highlight. We reported adjusted EBITDA for the second quarter of 2012 of $53.1 million. That's a 134% increase over adjusted EBITDA for the second quarter of 2011, and a 19% increase when compared to the first quarter of 2012. Adjusted EBITDA growth in the second quarter of 2012 was fueled by 22% sequential quarter-over-quarter production growth.

During the second quarter of 2012, oil and gas sales, including derivative settlements reached $69.3 million, which was 132% increase over the comparable amount in the second quarter of 2011, and $9.5 million or 16% on a sequential quarter-over-quarter basis. Comparing the second quarter of 2012 versus the second quarter of 2011, oil and gas sales growth was driven by a136% increase in production, which was partially offset by a 2% decline in average realized price per Boe, which includes the effect of settled derivatives.

Lower average realized prices per Boe during the second quarter of 2012 included higher oil differentials in the second quarter of 2012, when compared to the same period last year. Oil differentials for second quarter of 2012 averaged $13.72 per barrel, as compared to $7.42 per barrel in the second quarter of 2011.

Total production expenses per barrel of oil equivalent were $7.70 in the second quarter of 2012, as compared to $6.52 in the second quarter of 2011. We believe production expenses on a Boe basis were higher in the second quarter of 2012, as compared to second quarter of 2011, primarily due to higher water disposal costs experienced in the second quarter of 2012. However, I would note that our production expenses of $7.70 per Boe in the second quarter was down from first quarter amount of $8.40, primarily due to a lower level of workover activity.

Total production taxes per Boe were $7.03 in the second quarter of 2012, compared to $8.26 in the second quarter of 2011. As a percentage of oil sales, production taxes were 9.5% during the second quarter of 2012, and that compares to 9.3% in the same quarter last year. The second quarter of 2012 average production tax is slightly higher than last year, really due to a greater level of production that didn't qualify for reduced rates or tax exemptions during 2012. Some of these reductions are temporary in nature until a certain period of time expires, or a volume metric threshold is achieved, at which point they return to -- in North Dakota, it's a 11.5% rate.

General and administrative expenses were $4.4 million for the second quarter of 2012, which was up from $2.7 million for the comparable period last year, but down from $4.7 million from the first quarter of 2012. The majority of the year-over-year increase is related to salary and compensation expenses, as we have increased our staffing throughout the Company to support our growth. Our personnel continue to increase, as we invest in our technical teams and other staffing to support our growth.

Depletion expense per Boe increased during the second quarter of 2012, and reached $26.90 on a per unit basis, as compared to $20.83 in the second quarter of 2011. The increase in depletion expense per Boe is due to an increase in our estimated future development and operating cost estimate, as well as an increase in the depletable base, as additional unimproved properties are proved up and become subject to depletion.

Interest expense net of capitalized interest was $2.7 million for the second quarter of 2012, compared to 123% from the comparable period last year. The increase in interest expense is due to the higher level of borrowings in 2012. In mid-May, as many of you may recall, we completed an offering of $300 million of senior notes at an interest rate of 8%. The notes are due in 2020, and the proceeds were used to fund development and our acquisition program, repay outstanding amounts under our revolving credit facility, and for general corporate purposes.

At June 30, 2012 we had no borrowings outstanding under our credit facility. We had $300 million of availability under that facility, and had approximately $25 million in cash, which provides the necessary liquidity to fund our planned capital expenditure program. Our effective tax rate in the second quarter of 2012 was unchanged from the second quarter of 2011, and remains at 39.8%.

We continue to layer in hedges opportunistically as the market warrants, so we can maintain our growth momentum and our capital expenditure program. For the second half of 2012, we currently have hedged 840,000 barrels under swap agreements with a weighted average price of $94.25. And approximately 700,000 barrels, using costless collars, with an average 2012 floor price of $91.42 per barrel, and an average 2012 ceiling price of $107.23 per barrel.

For 2013, we currently have hedged 840,000 barrels under swap agreements, at an average price of $91.49 per barrel, and approximately 2 million additional barrels under costless collar arrangements with an average floor price of $90 per barrel, and an average ceiling price of $104.54 per barrel. For 2014, we've hedged approximately 1.6 million barrels under swap arrangements, at an average price of $91.80 per barrel. We will continue to look for opportunities to increase these hedging levels, but we feel we have established some very attractive levels.

At this point, I will turn it back to the operator to begin the question-and-answer session.

Thank you.

(Operator Instructions).

We will take the first question from Peter Kissel of Howard Weil.

Yes, good morning. Thanks for taking my questions. First of all, thank you for the additional color in the press release, and Ryan, in your prepared remarks on the leasehold expirations in the remainder of 2012. I was wondering if you could maybe give us some idea as to what you have expiring in 2013, and really, what your expectations are there, please?

I think -- this is Ryan. We have a total of approximately 14,000 acres that have 2013 expiries, that are at this time undeveloped. And we expect to hold a vast majority of that, by production or operations through the remainder of 2012 or end of early 2013. So I think a realistic number for us to potentially have at risk to expire in 2013 is probably somewhere between 4,000 and 6,000 acres. We are pretty comfortable with the pace of drilling, and the plans we see for the acres that expire in 2013. So no material expirations,13,000, 14,000 total with probably realistically 4,000 to 6,000 that have any kind of real risk to them.

Got you. Thank you, Ryan. And maybe just one quick question on the decision to shelf the MLP process for now. You mentioned that the production profile doesn't really fit with a MLP structure right now. Is that more, because the wedge of already flattened out production isn't large enough to the point where you think it's appropriate to drop into that structure? Or when, and if so, when do you think that timing will be right? And maybe additionally, on the MLPs, how much did the tax implications play into your decision to shelf it for now? And that's all I have. Thank you.

Thanks, Pete. The tax implications don't have much of an issue. It wouldn't be a large cash transaction for us, in any scenario. The main issue is the maturation of the production, and the amount of production, that were to achieve optimal valuation within an MLP structure. We believe that reevaluating in a year from now will give us a larger production base of appropriate production to choose from for the MLP. There's a certain amount of fixed costs that we have determined are associated with the MLP. So the greater efficiencies we can create by a larger vehicle, end up creating more accretion. So in the meantime, it's going to be business as usual, we continue to convert more acres to production. And as this production matures, we will (inaudible) this in a year.

Okay, great. Thank you.

We turn next to Marshall Carver, Capital One Southcoast.

Yes, couple of questions. So your budget is $8.8 million a well now for 2012. Is that flat through the year, or are you assuming lower well costs in the second half? Or how has that changed from first half to second?

Hi, Marshall. This is Ryan. The way that we arrived at that number is $8.8 million is the average AFE cost of the wells currently on our drilling and completing list. The average AFE for the first half of the year was somewhere around $8.2 million. As a non-operator, we don't always know exactly what the completed well cost is in real-time. So we're operating under the assumption that the AFEs going forward are going to be a good representation of costs. We think that is appropriate, given the fact we definitely have seen costs plateau and start to back off in the field. I think it's a fair assessment to say that the first half of the year generally ran over AFE costs, and we expect the second half of the year to probably track in line with AFE costs.

So that's the reason for the bump-up. There is a methodology behind it. We are not trying to predict the future, we are simply taking the average of the AFEs. The roughly 150 AFEs we have in front of us, for the roughly 10.8 wells that are drilling or completing, and the average cost of those is $8.8 million. So in the absence of any additional information, we are going were the most reliable piece of data we have, which is what the operators are telling us what the wells are going to cost.

Okay. That helps. Thank you. And on reserves, I see the midyear reserve update, on the -- it looks like you had pretty good reserve bookings per well on the proved developed reserves. Do you have the exact number of reserve bookings per well, or were there any positive revisions factored into that on the proved developed reserve numbers?

Yes, Marshall, this is Ryan again. I believe our average booking per well is around 400,000 Boe net to us. We haven't had any substantial negative revisions. In general, the reserve report is sort of tracked, as expected from a volume basis. The major change is driven by the impeting of higher future development costs and higher lease operating expense, both of which we expect to moderate. So essentially what we have to do with the reserve report is take the real-time numbers of lease operating expense and development costs, and apply those today, regardless of what we think those LOEs may go. You have probably seen across the play, LOEs are starting to come down, we expect that trend to continue. We expect drilling costs to drop, as many of our operating partners have indicated this quarter on their calls. So the main effect of the dollar value of PV10, not increasing proportionately to the barrel's amount of PV10 as the change in future development costs and the assumptions implied in lease operating expense.

Okay. So the 400,000 Boe's per well net to you all, is that net of the royalty? So that would that be more like 500,000 gross of royalty growth?

Right, 400,000 gross EUR.

Okay.

I think you'll find, Marshall, that our reserve bookings based on that number. And again, being that we are a proxy really for the entire play, we are in many of the similar wells that you'll see others book at different numbers. We think that 400,000 is a very conservative number to book for gross EURs across the play.

And that was for -- were you talking about the entire, just the wells added in the first half of the year were 400,000? Or were you talking about the entire proved development reserve base?

Marshall, that's the average across all wells, not just the wells added in the first quarter.

Okay.

Or first half of the year, and it's slightly higher than our year-end number. So it does imply on the whole, net positive revisions for the EURs.

Okay. Just one final question on the reserves. It looks like your pipe percentage, or your pipes went down a little bit. Why -- did you decide -- is that just a more conservative stance on PUD booking, or what caused you to treat PUDs that way?

The main driver is essentially the cutting off of the tail on wells, as a function of higher LOE costs. So what it implies is that in the future, the wells will become uneconomic sooner, given today's assumptions about LOEs. Which we think are, again, which we think will trend lower. So in general the amount of barrels will drop with higher well costs as we inflect along that economic line. And so, if you were to see lower LOE in the future, not only will you see the value of the reserves go up, but you will actually see the volumes go up as well.

Right. Okay. Thank you very much.

We will take our next question from Neal Dingmann, SunTrust.

Hi, quick question. One, just on that guidance I noticed on the acreage acquisitions, Ryan, it looks like you decreased that a bit on expectations, which is a bit surprising. I would assume, that, given that well costs are staying up there that a lot of the privates still maybe can't afford to stay in some of these plays, and might be looking for -- continue to come to you as they have always been. Just wanted your thoughts on why you would reduce that, or if there is really less opportunities?

Thanks, Neal. This is Mike. I think from a land standpoint, we are continuing to evaluate all the of the opportunities we are seeing throughout the field. At this point, we still haven't seen a lot of the acreage costs come down where we think they should be, relative to the current play. We are just continuing to be more selective with what we are buying as we move towards, basically the cash flow chapter of our business, rather than the acreage acquisition chapter of our business. But we continue to evaluate opportunities. We just believe given our activity in the first half of the year, we expect that to be similar to the second half of the year, which would be approximately $50 million for the whole year, so another $25 million second half.

Okay. So more just your choice, kind of like what you are picking and choosing and how you are playing this. Do you see that turning around maybe later in the year, early next? I guess it's tough to say, but would you assume that if, if the prices do come down then, you would become more active again?

Yes.

Okay. And then just wondering, now when you look at things still, I guess -- has the plan really changed from day one, as far as where you consider -- I know part of the plays, and some of the operators you team with, right in some of the core counties are obviously moving a little bit further west, a little more into Montana, what's your thoughts about that, Mike?

I think that the core delineation of the play has been defined for now. If there are new areas that open up, our model will take us there with the success of a new area. We continue to see a lot of, a lot of activity and better completion and better efficiencies in North Dakota and Montana. We continue to be more and more pleased every day with our activity in our areas of mutual interests, our AMIs with Slawson, in Richland County. And we will discuss that further as the year progresses. But that's where we are really pleased with the new developments in our southwest Big Sky area of mutual interest with Slawson. But generally speaking, the play is getting better, if new areas emerge as high quality, our model will automatically take us there, as really the clearing house for non-operated strategic interests that will arise when new rigs hit new areas.

And Mike, if you and Ryan could have your druthers, I mean when you are looking at some of these plays, would you consider stepping up larger working interests than you have had, kind of averaged in the past, or you do see that changing going forward?

I think the, I think the working interest is really a result of the opportunities. Our appetite for larger working interests has obviously increased as we have gotten bigger. But really, it just comes down to an acre by acre, and well by well analysis, whether it's 5%, or 35%, our appetite, our ability to take larger interests has increased. But from the standpoint of what we deploy, it really just comes down to acre by acre, and well by well.

Great plan. Thanks.

Thanks.

Up next, Scott Hanold of the RBC Capital Markets.

Good morning.

Good morning.

Ryan, you had mentioned a couple times, obviously LOEs costs came in a little bit better this quarter, and it sounded like some of that was related to lower work-over and you expect from your partners to get better water handling going forward. What is your best guidance, in terms of what we can expect here for the next, say, six to 12 months? Is it going to be kind of flattish as work-over ebbs and flows, and offset by better water efficiency, or do you think that could actually trend down a little bit?

I think it is could to trend down, Scott. I think that we are very pleased with the investments that the operators have been making in systems that will make these wells more efficient, both from a production standpoint and a waste water disposal standpoint. We are really moving into the efficiency part of the play, so I actually think we have got future efficiencies that will be driven by the investments and the innovation of the operators in the play. So I do think there is some downside to that number. I think the trend will remain in place, and I think that's consistent with what we have been hearing from the operators, both off and online this last quarter.

Okay. Fair enough. Is there any reason to believe, I guess, in the next couple quarters that work-overs would increase or decrease? Or how much visibility do you generally have on that?

We really don't have very much visibility on the timing or the planning for work-overs. I think it's logical to assume that work-overs, completion enhancements will probably continue to be a bigger part of this play as the technology advances, and the operators figure out more and more ways to efficiently recover more and more barrels of oil. So we hope that becomes a big part of the play. The operators are savvy enough to determine if a completion enhancement is going to create an enhanced rate of return, and we trust their judgment on that. So we think that as we see more technology evolve in the play, better efficiencies, I hope we do see more of that kind of activity.

Yes, okay. And I was probably trying to give you a little bit -- if you could give us a little bit of guidance here over the next couple of quarters. So at 770, I mean should I think about flattish from those levels, going into the next couple quarters?

I think, Tom, the question is, (inaudible) flat or lower LOEs in these levels?

I would have it flat.

Okay, okay. Fair enough. (Multiple Speakers). And Tom, on the DD&A side, you think that $27 in the second quarter is a pretty decent run rate?

Yes, it's going to be the run rate clearly for the third quarter, and when we do our year-end engineering, we will adjust that rate again, and we will see where we're at.

Okay. Understood. And on the lease expiration side, and you did provide a little bit of color on what you think would be at risk next year at expiration. In your view, is that 4000 to 6000-acre number more of, it's stuff on the fringe that ultimately, it's not really a core asset, you are not going to it drilled? Or is it more of, you just haven't seen the operators permit the acreage, or is that something you might expect could happen?

In our mind, Scott, this is Mike, we see that more as a function of -- we don't as you know from our maps, we don't have much fringe acreage, for lack of a better term. But what we will see is acreage in areas where the rig count isn't as active, or rigs aren't as active. So on a conservative basis, we assume that 4000 to 6000 acres could expire due to lack of activity in an area. But generally speaking, we are-- with the rig count still over 200, and efficiencies increasing every day, from a spud to total depth, and then spud to sales standpoint, we think we are going to turn on a lot of that acreage, most certainly the vast majority of it.

Okay. In general, did you have kickers on some of these -- on your leases, where even if like in fact get drilled, you would actually step up and maybe release that for another term?

We do have kickers on a portion of our acreage, yes.

Okay.

So that gives us optionality [clearly].

Yes. And what are you seeing in general in activity in the Basin? It's interesting you are seeing the rig count in the basin drop. I think a common theme is everybody's doing things, such more efficiently, and how does that play in your non-operated strategy? Does that really not make a difference for the most part?

Scott, this is Ryan. The interesting thing that we are seeing is -- with the rig count dropping, I think we still see the amount, or actually more wells drilled exactly because of what you referenced, which is the increase in efficiency. So we have seen spud to sales time compressed significantly, and seeing the significant loosening in the availability of frac crews, completion assets. So I think that equilibrium between wells and frac assets has really tightened, and potentially even inverted the other way. I think we're able to accomplish just as much activity with fewer wells, I'm sorry, fewer rigs in the future. So I think it is a net positive for us. As we move into the down spacing mode of this play, it's going to be economic decisions that will really drive the pace of drilling as opposed to racing to hold acres by production. So we are looking forward to significantly increased efficiencies in the next leg of the play, and I think that's accomplished with a lower rig count.

All right, thanks for that color, for the next quarter.

Thanks, Scott.

We will take our next question from Chad Mabry, KLR Group.

Hi, good morning. Appreciate the color on the MLP on the call, just to follow that up. You had discussed other avenues, I guess, for specifically royalty trust. Can you, I guess, provide any commentary on where that ranks, on kind of avenues that you might pursue here over the next 12 months or so?

Thanks, Chad, this is Ryan. Royalty trusts are still on the table for us, a royalty trust being sort of a one take transaction is really just more of a essentially a sale of production. And if you look at where the Company trades on a multiple of EBITDA, in other words where our cash flows are valued, and you compare that to a multiple of EBITDA that asset would trade for into royalty trust, there certainly is some significant accretion that we could create there.

We are still evaluating the royalty trust scenario, so that is absolutely one option for us that, that could potentially make sense. From a leverage standpoint, and from a liquidity standpoint, we have got a very strong balance sheet. We are very well-positioned, with a completely undrawn credit facility as of the end of the quarter, to be able to use that low-cost capital. So we are really not forced to do anything from a divestiture or a restructuring standpoint into another vehicle. So for liquidity reasons, we would consider something like that if we were able to create a significant accretion, relative to where the cash flow currently trades. So that's still on the table.

Okay. Just to follow that up, looking at other sort of non-op M&A activity in the basin, would you -- specifically look at the EOG package and the value that that received. I mean, would that be an option to potentially market a package, a similar package of your properties as well?

Chad, I mean, we -- at this point, as far as least the public record goes, the EOG package is still a subject of really just conjecture, although we are fairly certain the level of that package traded is significantly higher than the implied valuation of Northern. So right now we are focused really on growing the business, first and foremost, and executing our business plan. If opportunities present themselves in the A&D markets, we will look at anything that can create or enhance shareholder value.

I appreciate it. Thanks.

Our next question comes from Phil McPherson, Global Hunter Securities.

Good morning, nice job on the quarter.

Thanks, Phil.

Most of the questions are answered, but I had one. I was kind of doing some housekeeping here, going back and forth between first quarter, and second quarter press release. Maybe you can help me. In the first quarter press release, it indicated that you completed and put on production 13.4 net wells, and in this press release, it was 15.8, which would bring your total to 29.2. So I'm trying to figure out, is that the right number for the first half as far as on production? And then how does that look relative to the 44 number? I mean, it would suggest that third and fourth quarter activity would actually have to come down, or maybe we are looking at a bump up in the amount of wells that could be put on this year?

Phil, this is Ryan. Yes, the increase in the pace of first quarter and second quarter completions is related to the clearing of the 2011 backlog. So we ended the year with (inaudible) I think it consisted of approximately 18 net wells, that's down to D&C list right now of just about 10 wells. So it's actually realistic we will complete more wells in 2012 than we will spud, just because of the compression of spud to sales time and the backlog we had at the end of the year. So don't necessarily draw a complete correlation between well spuds and well completion, given that we had a substantial backlog at the end of 2011.

Okay. So you are thinking then, from a CapEx standpoint, that it doesn't really impact you, because it's just a lag of time on that?

Right. There's a lag of time of CapEx that's paid in 2012 related to the completion of 2011 wells, and likewise, there will be a lag of 2012 CapEx paid in 2013 relative to completion, that will tip over to the other side of the year. So we think the most efficient way to measure that is a real-time marker like well costs that we are able to infer from our AFEs, and which is why we feel (inaudible) specifically to average well costs and number of wells.

Do you think that with more crews and stuff that's going on in the basin, that your wells waiting on completion, that inventory starts to decrease going forward?

I think -- I mean it's probably going to be pretty consistent. I mean, if we are spudding 10 to 12 wells per quarter, we should probably be carrying in general 10 to 12 wells on the D&C list. So we should see a consistent number going forward, as it relates to spuds and completion. If we are carrying more than a quarter's worth of spuds on the D&C list, it implies that spud to sales is greater than 90 days. If we're carrying less than we spud in a quarter, than it implies the time from spud to sales on average is less than 90 days. But we generally expect to carry in any given quarter approximately the same amount of wells that we spud. And that's a good way, I guess, for you to be able track what the spud to sales time is doing specifically.

Okay. Great, appreciate it. Thanks so much.

Okay, thank you, Phil.

We will take the next question from Phillip Jungwirth, BMO Capital Markets

Good morning. I was going to ask about what you are seeing from the Big Sky prospect where Slawson has been pretty active this year, but it sounds like that you are not going to address that until later this year? Is that fair?

We continue to lease in that particular area, so we have yet to release a batch of wells and completions and results. We have, we have drilled approximately 15 or 16 wells in our southwest Big Sky AMI with Slawson. We plan to get specifics later this year on our success there, and our plans for full development. So as we continue to build our lease position, and continue to develop the field, we will update the market with specifics down the road.

Okay. And then on the MLP or royalty trust, what do you think the average base decline would need to be for the PDP, in order to drop production down into one of those structures?

Sure. This is Ryan, I think that in targeting a MLP, you are probably going to see the best valuation, somewhere around 12% decline rate. And although we have a certain rate of production that is declining at 12%, it's a matter of really gathering enough production with declines in that rate. And as we get about 12 months down the line, we think we inflect, and at that point where we have got an efficiently large amount enough of production -- or efficiently large amount of production, that makes the fixed costs with an MLP make sense. So really, it is related to the amount of flat declining production we can put into that kind of vehicle.

Okay, makes sense. And then, I was just wondering if you could talk generally around where the mix of your 2012 wells are being drilled, kind of between the five different areas of the Bakken, Big Sky, Lewis & Clark, North, West and East Nesson?

This is Mike. I think it's generally scattered throughout the core of our acreage position, which is -- within the core of the play. We continue to see development in Montreal, Mackenzie and Williams. In one of our presentations, we have a slide that tracks our net well adds in the first half, related to percentage of rigs in each county. And really, Northern correlates very well with the, with the drilling assets in the field. So the counties that have a higher percentage of the rig count on Northern will have a higher percentage of it's net well adds. So we really, truly are a proxy for the play, so where the activity in the play goes, so does Northern. And there is no one outlier, as far as adds. And as the rig count increases or moves around from county to county, so goes Northern.

Okay, great, that's helpful. And last, how many of the 22 net wells that you're going to spud in the second half of the year, do you think you'll be able to complete and turn to sales?

Sticking along with that roughly 90 day spud to sales, probably about half of those should be turned to sales. And then we will also sort of clear out the D&C list that we are currently carrying. So you should really expect sort of a straight-line conversion of spuds to sales. So if we're spudding roughly 10 to 12 wells per quarter, we should be adding 10 to 12 net wells per quarter from this point on out, given our current D&C list.

Okay, great, that's all I had. Thanks.

Thank you.

This concludes today's question and answer session. I would like to turn the conference back over to Mr. Michael Reger for additional or closing remarks.

Thank you so much for joining our conference call. Look forward to another quarter ahead. Thank you.

This concludes today's presentation. Thank you for your participation.