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'm 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're 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 involve certain risks and uncertainties. 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 2 gross wells added to production per day in collar [ph] days. Total wells added to the production total base during the first half of 2012 was 291 gross, 29.7 net wells. Today, we are one of the largest non-operators in the Williston Basin and remain a clearinghouse for non-operated strategic working interests. We continue to grow our production, reserve 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 costs will be $8.8 million this year, up from our 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 estimates. 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 acquisition. As indicated in this morning's press release, we announced our midyear proved reserved quantity 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 financials.

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 2011 and a 19% increase when compared to the first quarter of 2012. Adjusted EBITDA growth in the second quarter 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 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 136% 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 the 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…

[Operator Instructions] And we'll take our first question from Peter Kissel of Howard Weil.

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?

This is Ryan. We have a total of approximately 14,000 acres that are on 2013 expiries, that are, at this time, undeveloped and we expect to hold a vast majority of that by production or operation due to remainder of 2012 or into early 2013. So I think a realistic number for us to potentially have that risk to expire in 2013 is probably somewhere between 4,000 and 6,000 acres. We're pretty comfortable with the pace of drilling and the plans we see for the acres expiring 2013. So no material expiration, 13,000, 14,000 total [Audio Gap] would probably, realistically, 4,000 to 6,000 that have any kind of real risk to them.

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 an MLP structure right now. Is that more because the wedge have 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 then maybe additionally, on the MLPs, how much did the tax implications play into your decision to shelf it for now?

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 would achieve optimal value addition [ph] within an MLP structure. We believe that re-evaluating in a year from now would give us a larger production base of appropriate production which, for the MLP, is a certain amount of fixed cost that we've determined are associated with an 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'll revisit it in a year.

And we turn next to Marshall Carver, Capital One Southcoast.

Yes, couple of questions, so your budget's $8.8 million a well now for 2012, is that applied through the year, or are you assuming lower well cost in the second half, or how has that changed from first half to second?

This is Ryan. The way that we have arrived to 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 realtime. So we're operating under the assumption that the AFEs going forward are going to be a good representation of cost. We think that's appropriate given the fact that we've definitely 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're not trying to predict the future, we're simply taking the average of the AFEs, the roughly 150 AFEs we have in front of us, with a 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'll go in with the most reliable piece of data we have, which is what the operators are telling us the wells are going to cost.

And on reserves, glad to see the mid-year 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 and it sort of tracked as expected from a volumes basis. The major change was driven by the imputing of higher future development cost and higher lease operating expense, both of which we expect to moderate. So what we essentially have to do with the reserve report is take the realtime numbers of lease operating expense and development cost and apply those today, regardless of where we think those LOEs may go. You've probably seen across the play, LOEs are starting to come down. We expect that trend to continue and we do expect drilling costs to drop as many of our operating partners have indicated this quarter on their call. So the main effect of the dollar value of PV-10 not increasing proportionately to the barrels amount of PV-10 is the change in future development cost [ph] and the assumptions implied in lease operating expense.

So the 400,000 BOEs per well net to you also, is that net of the royalty, so that would be more like 500,000 gross of royalty?

Right, 400,000 gross EUR. I think you'll find, Marshall, that our reserve booking's based on that number. And again, being that we're proxy, really, for the entire play, we're 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 developed reserve base?

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

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

The main driver there 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. Again, which we think are -- again which we think will trend lower. So in general, the amount of barrels will drop with higher well cost as we inflect along from 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'll actually see the volumes go up as well.

And we'll take our next question from Neal Dingmann of SunTrust.

Quick question, one, just on that guidance. I noticed on the acreage acquisitions around that, it look 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 these privates still maybe can't afford to stay in some of these plays and might be looking for -- continuing to come to you, as they always been. Just wanting your thoughts on why you would reduce that or if there's really less opportunities?

This is Mike. I think from a land standpoint, we're continuing to evaluate all of the opportunities we're seeing throughout the field. At this point, we still haven't seen a lot of the acreage cost come down where we think they should be relative to the current play, so we're just continuing to be more selective with what we're buying, as we begin to move toward, 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 that given our activity in the first half of the year, we expect second half of the year, which will be approximately $50 million for the whole year, so another $25 million in the second half.

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

Yes.

Okay, and then just wondering, now when you're looking at things, still, I guess, has the plan really changed from day 1 as far as where you're considering, I know parts of the plays and some of the operators you team with. Right in some of the core counties are obviously moving a bit further west, 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 it there with the success of a new area. We continue to see 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 interest. Our AMI's with Slawson in Richmond County and we'll discuss that further as the year progresses. But that's where we're 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 as new areas emerge, as high-quality, our model will automatically take us there as really the clearinghouse for non-operated strategic interests that will arise when new rigs hit new areas.

And Mike, if you and Ryan can have your druthers in, when you're looking at some of these plays, would you consider stepping up larger working interest than you've had kind of on average in the past or do you see that changing going forward?

I think the working interest is really a result of the opportunities. Our appetite for a larger working interest has obviously increased as we've 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 has -- our ability to take larger interests have increased but from a standpoint of what we deploy, it really comes down to acre-by-acre and well-by-well.

Up next, Scott Hanold of RBC Capital Markets.

Ryan, you'd mentioned a couple of times, obviously, LOE cost came in a little bit better this quarter, like some of that was related to lower work-over and you expect from your partners to get sort of better water handling going forward. What's your best guidance in terms of what we can expect here for the next, say, 6 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 could turn down, Scott. I think we're 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 wastewater disposal standpoint. We're really moving into the efficiency part of the play, so I absolutely think that we've 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. I think that's consistent with what we've been hearing from the operators both off and online this last quarter.

And is there any reason to believe, I guess, in the next couple of quarters that work-overs would increase or decrease? How much visibility do you generally have on that?

We don't have very much visibility on the timing or the planning for work-overs. I think that 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, 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.

Okay. And that was probably trying to give you a little bit -- give us a little bit of guidance here over the next couple of quarters, and so it's at 70, should I think about flattish from those levels, going to the next couple of quarters?

I think -- the question is flat or lower LOEs from these levels?

I would have it flat.

And Tom, on the DD&A side, do 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 then when we do our year-end engineering, we'll adjust that rate again. And we'll see where we're at.

On the lease expiration side, you did provide a little bit of color on what you all think could be a risk next year to expiration. In your view, is that 4,000 to 6,000-acre number more of -- it's stuff on the fringe that ultimately it's not really a core asset, you're not going to see it drilled? Or is it more of, you just haven't seen the operators permit the acreage, but that's 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'll see is acreage in areas where the rig count isn't as active, or the rigs aren't as active. So on a conservative basis, we assume that 4,000 to 6,000 acres could expire due to lack of activity in an area. But generally speaking, we're -- with the rig count still over 200 and the efficiencies increasing every day from a spud to total depth and then spud to sales standpoint, we think we're going to turn on a lot of that acreage, well certainly a vast majority of it.

And in general, do you have tickers on some of these, on your leases, where, even if you like it and it's not getting drilled, you can actually step up and maybe re-lease that for another term?

We do have tickers on a portion of our acreage, yes, So that gives us optionality, clearly.

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

Scott, this is Ryan. The interesting thing we're seeing is, with the rig count dropping, I think we still see the same amount, or actually even more wells drilled, exactly because of what you referenced, which is the increasing efficiencies. So we've seen spud to sales time compress significantly, we've seen a significant loosening in the availability of frac crews, completion assets. But I think that, that equilibrium between wells and frac, frac assets, has really tightened and potentially even inverted the other way. So 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's a net positive for us. And 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're looking forward to significantly increase efficiencies in the next leg of the play and I think that's accomplished with the lower rig count.

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

I appreciate the color on the MLP on the call. Just to follow that up, you guys 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?

Chad, this is Ryan. Royalty trust is still on the table for us. A royalty trust being a 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 assets would trade for into a royalty trust, there certainly is some significant accretion that we could create there. We're still evaluating the royalty trust scenario, so that is absolutely one option for us that could potentially make sense. From a leverage standpoint or from a liquidity standpoint, we've got a very strong balance sheet, we're 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're really not forced to do anything from a divestiture or a restructuring standpoint into another vehicle. For liquidity reasons, we would consider something like that if we're able to create significant income [ph] relative to where the cash flows currently trade. So that's still on the table.

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

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

And our next question comes from Phil McPherson, Global Hunter Securities.

Most of the questions were answered, but I just had one. I was kind of doing some housekeeping here and going back and forth between first quarter and second quarter press release. Maybe you could help me. In the first quarter press release, it indicated that you completed and put on production 13.4 net wells. And then 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're looking at a bump-up in the amount of wells that could be put on this year.

Phil, this is Ryan. 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 a D&C list that consisted of approximately 18 net wells, that's down to a D&C list right now of just about 10 wells. So it's actually realistic that we'll complete more wells in 2012, than we'll 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 wells spud and well completion, given that we had such a substantial backlog at the end of 2011.

So you're thinking then, from a CapEx standpoint, that it doesn't really impact you because of just the lag in time on that?

Right, so there's a lag in 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 completions that tip over the other side of the year. So we think the most efficient way to measure that is a realtime marker like well costs, that we're able to infer from our AFEs, and which is always broken out well 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? Is that a constant number?

I think it's -- yes, I mean, it's probably going to be pretty consistent. I mean, if we're 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 pretty consistent number going forward as it relates to spuds and completions. 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, then it implies that 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 all to be able to track what the spud to sales time is doing specifically.

We'll take our next question from Phillip Jungwirth, BMO Capital Markets.

I was going to ask about what you're seeing from the Big Sky prospect where Slawson has been pretty active this year, but sounds like you're not going to address that until later this year, is that fair?

We continue to lease in that particular area so we are yet to release a batch of wells and completions and results. We have drilled approximately 15 or 16 wells in our Southwest Big Sky AMI with Slawson. We plan to get specific 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'll update the market with the 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 an MLP, you're probably going to achieve the best valuation somewhere around the 12% decline rate. And although we do have a certain amount of production declining at 12%, it's a matter of really gathering enough production that declines in that rate. And as we get about 12 months down the line, we think we inflect in that point where we've got an efficiently large amount enough of production, or efficiently large enough amount of production that makes the fixed costs with an MLP make sense. And so really, it is related to the amount of flat declining production that we can put into that kind of vehicle.

I was just wondering if you could talk generally around where the mix of your 2012 wells are being drilled kind of between the 5 different areas of the Bakken, Big Sky, Lewis and Clark, Northwest 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 Mountrail, McKenzie 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 drilling assets in the field. So the counties that have a higher percentage of the rig count, Northern will have a higher percentage of its net well adds. So we really truly are a proxy for the play. So where the activity in the play goes, so goes Northern. And there's no one outlier, as far as adds. And as the rig count increases or moves around from county to county, so goes Northern.

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

Well, speaking along with that roughly 90-day spud to sales, probably about half of those should be turned to sales, and then we'll also sort of clear out the D&C list that we're 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.

This concludes today's question-and-answer session. I'd like to turn the conference back over to Mr. 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.