Good day, everyone, and welcome to the Northern Oil and Gas Fourth Quarter and Full Year 2012 Earnings Release Conference. Today's call is being recorded. At this time, I would like to turn the conference over to Mr. MichaelReger. Please go ahead, sir.

Thank you, Kim. Good morning, ladies and gentlemen. This is Mike. We're happy to welcome you to the 2012 year-end earnings call for Northern Oil and Gas. Also with me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from 2012; and Brandon Elliott, our Executive Vice President of Corporate Development and Strategy, who will discuss the opportunities we are seeing in 2013. Before we begin this morning's call, you should be aware that certain statements made during the call may contain forward-looking statements that are based upon management's expectations, estimates, projections and assumptions that involve certain risks and uncertainties. We encourage you to review the various risk factors relating to our business, which are available on our annual report on Form 10-K for the fiscal year ended December 31, 2012, and other reports we have filed with the SEC. 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 the non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we put out last night. As I mentioned in the earnings release last night, 2012 was a transformational year for the Williston Basin. Drilling cost abated throughout the year, as oilfield services became more plentiful. Wellhead oil price differentials ended the year at some of the best levels we have seen since the play began, and multi-well pad drilling is becoming the norm as opposed to the exception. During this transition, Northern was also able to grow the company's production in 2012 by 95% over 2011 and grow adjusted EBITDA in 2012 by 101% over 2011, while also improving capital efficiency throughout the year. Also, drilling pace at the end of 2012 was robust, with North Dakota well spuds at an all-time high in December. The combination of this high activity and the operational efficiencies I just highlighted should position Northern for a very exciting 2013. With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some financial highlights and then he will turn the call over to Brandon Elliott to discuss value and the 2013 opportunities.

Thanks, Mike. Northern's 2012 production increased 95% compared to 2011. We produced approximately 3.8 million barrels of oil equivalent or BOE for the year. The sequential quarter-over-quarter production on a BOE basis declined 4% with fourth quarter production averaging approximately 10,900 barrels per day. As we discussed in our operations release on February 11, fourth quarter production was affected by a confluence of events, including weather, lower average working interest in completed wells during the fourth quarter and a dip in North Dakota's Bakken production during November. Having said that, 2012 was obviously a record year for Northern in terms of production, net well additions and proved reserves. During the year, we added 563 gross (48.3 net) wells to production, bringing our total producing wells to 1,227 gross or (106.2 net) wells. We reported GAAP net income of $72.3 million or $1.15 per diluted share for 2012. Excluding the net of tax impact of the noncash gain on derivatives and certain severance expenses, we reported adjusted net income of $66.2 million, $1.05 per diluted share. Our earnings release includes a reconciliation of these non-GAAP numbers to net income, net income per share. We continue to see strong cash flow growth in 2012. We reported adjusted EBITDA of $225.3 million for 2012, 101% increase compared to 2011. Adjusted EBITDA growth for the year was fueled by strong production growth and higher realized prices. Production expenses were $32.4 million in 2012 as compared to $13 million in 2011. The aggregate increase in production expenses was primarily due to well additions and the maintenance of production on existing properties. On a per-unit basis, the average production expenses or BOE increased from $6.77 per barrel sold in 2011, $8.61 in 2012. The year-over-year increase on a per-unit basis is primarily due to increased cost…

Thanks, Tom. As Mike mentioned in his opening remarks, the Williston Basin was in transition in 2012. And with that transition, we experienced some challenges. The push to hold acreage by production and the constrained availability of oilfield services in the second half of 2011 and the first half of 2012 caused some bumps in the road. But as we look to 2013, some of these challenges represent opportunities. Held by production percentages are approaching levels, where the worry over acreage exploration is declining for many operators. With that, the basin is beginning the transition back to the core and a more developmental drilling approach. As Mike mentioned, multi-well pad drilling has become the norm as we enter 2013. This, combined with much greater availability of oilfield services and substantially improved infrastructure, should help drive costs down. We have already begun to see this as the AFE cost overruns we experienced in the first half of 2012 have abated. As we indicated in our press release, we expect drilling and completion cost to average between $8.4 million and $8.8 million per well for the year, with the cost likely approaching $8 million per well by year end. But the sales times have also been in decline and are now at approximately 90 days for the basin. As a result, we expect our capital budgeting predictability to improve. Assuming we spud approximately 44 net wells during the year and the cost and capital budgets we have laid out to you today, we initiated 2013 production guidance in the range between 4.7 million and 5 million barrels BOE, which would reflect growth of approximately 25% to 33%. As of December 31, 2012, Northern was participating in 157 gross or (12.4 net) wells that were either drilling or in the completion process. The…

[Operator Instructions] Our first question today is from Ryan Oatman from SunTrust.

With the shares trading near that PV-10 value, can you talk about the assumptions you used to create that estimate, whether they'd be well cost, EURs, number of wells per year, et cetera?

This is Brandon. I mean, a couple of numbers that are in there, I think 1,214 PDPs as of the end of the year with kind of 488,000 average EURs and basically, the average well numbers that we gave you, 44 net wells for the year.

Okay, very good. That's helpful. And then, we also recently saw the announcement of the first-ever acquisition of a public sea core by an upstream LLC or MLP. In the past, you guys have kicked around the idea of converting into an MLP structure. Can you refresh us on the prior rationale there, your for and against conversion, the pros and the cons there. And then a follow-up question. With the shares where they are, is that idea now back on the table?

With respect to the valuation currently, and Ryan, this is Mike, and the question about MLPs. As we announced last August, we've shelved any possibility of an MLP for now until our production profile matures and becomes more appropriate for that structure. As we continue to analyze all options to increase shareholder value, though.

Okay, I appreciate it. And then moving onto 2013 guidance here, what sort of average Bakken well assumptions are you looking at? Are you looking at your specific locations versus last year, I guess with activity looking like it's trending towards some of these higher productivity areas, whether they be in south of Elm Coulee or the Peninsula or Tarpon? Is -- does guidance reflect that potential for productivity to improve? Or does it more look at kind of how the 2012 well results trended?

One thing that is going to be different about 2013 that was different than 2012 is that the rigs are now present again in Southern Mountrail County, which is where Northern has generated a lot of its production growth over the last few years. That acreage over the course of 2011 became, for the most part, held by production. And just in late 2012, we started to see the Slawson and EOG rigs return to Southern Mountrail. Specifically, Slawson has 3 rigs drilling on the Peninsula right now, where Northern has a fairly significant working interest. So I would say, generally speaking, the mix of wells that are going to be developed in 2013 will be better on the whole than the wells developed in 2012, as the rigs start moving back into the core for more development in infill drilling.

Moving on, we'll hear from Scott Hanold from RBC Capital.

Just a follow-up on that question on 2013 guidance. Obviously, it does look pretty good coming in close to 30%. Outside of, I guess, Slawson, in the Peninsula, what is your confidence level? What are you seeing from some of your other operating partners as they move to development? How do you get sort of a confidence as a non-operator over the next couple of years and what they're going to do and how that kind of translates into growth for Northern?

Scott, this is Mike. The way that we look at it is from a development standpoint, based on the rig count, based on the activity we saw at the end of 2012 and in the beginning of 2013, we've always had a fair degree of confidence over development, when the wells would be spud. Where it's been a challenge for us in the past is when the wells would be completed. We didn't necessarily know when that production would come on, and we didn't know when the completion cost would flow through our joint interest build cycles. But because the spud to sales cycle has compressed to approximately 90 days, generally speaking, we now know that once the development program begins, we generally know when the production is going to be coming on and when the joint interest builds will flow through our cycle. So the way we look at it, we expect 44 to be a conservative number from a net well spud this year, and we expect that to be generally straight line. We do expect some additional benefits from pad drilling to maybe weight heavier towards the back half of 2013 from a production standpoint. But from a general development standpoint, we're confident with the 44 net wells and we're confident with the development plan and the areas where they're being developed. As I mentioned in the previous question -- in a previous question, the rigs are currently present at Southern Mountrail. That's going to be a win in back this year. A lot of the drilling in the core of the play is now pad drilling as opposed to sort of on the edges or the periphery or hold by production type drilling. We also have seen some activity in McKenzie County that's very exciting for us. We happen to have 17.4% working interest in Whiting's Tarpon wells that they have brought on here recently that are in the 5,000 BOE range for an IP. So that's been exciting for us. We also happen to have about 7 -- a little over 7% working interest in the Conoco Corral Creek unit, which is the 30,000-acre spacing unit in Dunn County, which is some of our highest EURs overall in the entire play, and Conoco currently has 3 rigs drilling in that area. So that's going to be active for us. And then in addition to the other activity that's standard for Northern throughout the core, as I'm just basically highlighting only a handful of the rigs that we're exposed to, just I think the play as a whole is actively developing the core. And then we're also very actively developing the Big Sky/AMI in Richland County with Slawson targeting the upper shale.

A couple of questions as a follow-up to your comment there. The first is in the project area, with Whiting, that's the Tarpon area, where you've had some pretty prolific wells, how many -- what is the inventory there for you like? Is there a handful of wells left that's going to be drilled this year? Because certainly, that's potentially pretty significant for you guys.

Scott, we have about 23,000 net acres in McKenzie County, fairly close to the river. If you look at the map that shows our acreage, whether you look on our website or in press releases or investor presentations, you can kind of see that most of our acreage is tucked nicely in the Northern McKenzie and Southern Williams, fairly close to the river, as opposed to Northern Williams or Southern McKenzie. So if you just look at our acreage in McKenzie County, it's tucked nicely up into the river and that Tarpon prospect is generally in the Central, East Central, or Northeast Central portion of McKenzie County. So we've got a lot of inventory in the area, not just with Whiting but Conoco, Continental and others. So it's a very exciting area for us and we've got a lot of inventory, especially from an infill standpoint going forward.

Okay, very good. And one last follow-up here. You mentioned Big Sky. I know in the past you've talked about this prospect opportunity. A number of wells, it looks like, have been drilled there over the last sort of year or so. At this point in time, do you have any kind of color or sense in terms of what that opportunity looks like at this time? And is there going to be increased development there with you and your partner?

Scott, let me just lay out Big Sky here simply without getting into too much detail. Slawson and Northern have drilled approximately 20 wells in the Big Sky area, in our Big Sky area of mutual interest in Richland County. It's on that Southwestern edge of the Elm Coulee field in Richland over in Montana. Northern has a 24% working interest in the areas of mutual interest, with Slawson having the balance. We control -- Northern controls approximately 20,000 net acres in that particular area. The program is slightly different than our typical Bakken and Three Forks development drilling. We're targeting the upper shale on that southwest edge of the Elm Coulee field, where the middle member is no longer present. We are drilling short laterals in 640-acre spacing units. And as I mentioned earlier, we've drilled about 20 of these wells. So on the short laterals, 5,000-foot laterals, we're using 20 stages sliding sleeves with white sand. We're currently drilling these wells for under 5 million a piece. And the EURs on most of the recent wells are in the 350,000 to 400,000 range. So that puts Big Sky as probably our -- one of our highest EUR -- or excuse me, highest IRR areas. Slawson intends to drill about 4 wells per unit until the project is complete. This is not a huge deal for us, but it will be among many of the drivers of production and value in 2013, similar to the movement of the rigs into the core over North Dakota. So it's an exciting play for us with Slawson.

And I apologize, I'm a little bit slow here. But what was the well cost in that EUR range that you provided?

We're currently drilling these wells for under 5 million apiece. And the EUR range of the wells that we've been drilling with the most recent recipe for drilling and completion are in the 350,000 to 400,000 range. And one thing to note, not to get into too much additional detail, but Slawson has also recently drilled 2 dual lateral wells, where from a single vertical, it had 2 laterals running along the lease line that are north and south and then east and west or vice versa. Where he's completing one -- he'll complete one -- Slawson will complete one lateral, flow it back, shut it in and isolate it, complete the other lateral, flow it back and then co-mingle the production. Slawson just completed the first well under this program, and the well costs are approximately $8 million, so roughly $4 million per lateral. So Slawson continues to innovate, not just from a drilling and completion standpoint but they're also innovating from a cost efficiency standpoint. So it's an exciting play for us, albeit not gigantic for us. It's just another value driver for 2013.

And we'll hear next from Peter Kissel from Howard Weil.

Maybe just one initially on differentials. Clearly, they've been favorable. I'm just trying to get a sense for where you think they're going to go going forward? And if you could give any sort of color in terms of what your breakout is from rail to pipe to track out, just for our modeling purposes, that'll be helpful.

Pete, this is Mike. I would say the first quarter we're probably seeing some of the similar levels we saw in the fourth quarter of 2012. I think just from a conservative standpoint, I would use the 5 -- 5 to 7 range throughout 2013, which is consistent with what our operators are telling us. But generally speaking, with the addition of significant rail assets in the Williston, that's going to be one of the big drivers of tight differentials in 2013.

Okay. And then maybe one follow-up, a little bit more broad-based, following on one of the prior analyst's questions regarding the MLP. Just looking at our model, we have Northern generating free cash flow mid 2014-ish. I'm just curious to see how you think about that in context of the structure of Northern. You mentioned MLPs and that you're always looking at alternatives to maximize value. But what about dividends, repurchases or even at that point once it's a free cash flow entity that's still growing pretty fast? Is that a time to be looking at an exit strategy? And does the buyer become a little bit different and more interested at that point, do you think?

And as you know, we take our duty to maximize shareholder value very seriously, and we're continually evaluating all options to increase shareholder value. As to any specific strategy, whether it's an MLP or an outright sale, like most public companies, we basically have a no-comment policy. With respect to MLP, again, we announced in August last year that we've shelved the MLP for now until the production profile matures. The production profile may be appropriate for an MLP towards the end of 2013 into '14. But at this time, that's still on the shelf.

Okay. And maybe just one last question for Tom here. When you're looking at 2013 costs, how should we think about your different operating cost lines? In particular, LOE was a bit higher in the fourth quarter of '12 due to some workover and water disposal expenses. But looking through the year, now that you have pretty good line of sight, how should we be looking at that versus fourth quarter '12?

I think -- kind of echoing on Mike's comments, I think the first quarter differentials are fairly similar to what we're seeing in 4Q. Differentials, I think 5 to 7. I think our LOEs are going to range kind of in the $8 to $9 range. As I mentioned in the script, you typically have higher LOEs during the first year of a well's operation. We've added a significant number of new wells during 2012; that will continue. I think our expectation is you'll see LOEs trend down as our production base matures. But I'd probably peg it in the $8 to $9 level. Production taxes, we were about 9.6% at the end of the fourth quarter, 9.6% to 9.8% would probably not be a bad range. An income tax rate slightly lower -- slightly higher, rather, than our year-end rate, will be an augment taxpayer next year, so probably 38 to 39 kind of on a rate, probably 0.5% of that being kind of current while the rest of it's still being deferred.

And our next question today is from Jason Wangler from Wunderlich Securities.

Just a couple of quick ones. One on the CapEx budget. Do you see the rig count kind of moving higher throughout the year and maybe that CapEx budget ramping as that happens? Or do you it see more just being kind of consistent throughout the year?

This is Mike. We really are modeling a stable rig count here. I think the rig count as of last night was about 185. We think that the rig count has essentially been high-graded over the last year, given 2 pretty important data points. One clear data point is that the rig count is actually down about 15% from its all-time high of about 215. However, in December, the gross well spuds were at all-time record. So we believe that the rigs that are in the basin now, roughly the 185 rigs that are in the basin now are pad drilling rigs that can walk or slide from well to well on a pad. So that's -- I think that's what our model is assuming, which is just a stable rig count and development profile. And I think the CapEx budgets and the drilling plans in 2013 have been set with our partners. So we've always had a very -- fairly decent view towards spuds. And we think that our 44 net well spud is going to be accurate. We believe that 8.4 to 8.8 is a reasonable range to assume at this time, although given the efficiency of the pad drilling and other costs, given the further availability of services, we think that we could exit 2013 closer to 8.

That's helpful. And then just -- the only other question I had was as far as the credit facility. When is the next redetermination coming up?

April 1.

We'll hear next from Chad Mabry from KLR Group.

A quick question on non-consents. You previously mentioned that you went non-consent on about 30 wells in Q3, Q4. Just curious if you could specify which areas or maybe operators that you went non-consent? And then, also if you could comment on the terms of your leases there? I mean, will you have the option to participate in future development on those units?

Non-consents are fairly simple in that if we don't agree with the economics of the current well being drilled in the unit, we can elect to not participate in that well. And then after the operator recovers approximately 300% of their drilling costs, we back in for our portion of -- or our interest in that well. And then to answer your last question first, if another well is proposed in that same unit, say 90 days or 6 months or a year later, Northern has the same right to participate heads-up in that additional well. So there isn't a penalty other than we just forgo the economics of the first 300% of drilling costs. So it's really simple. We did elect to non-consent about 29 wells in the second half of 2012. The primary reason was just because of higher drilling costs. And our goal was -- the management and board goal was essentially to high-grade capital deployment and improve capital efficiency because we didn't know what well costs were going to end up doing. But they actually ended up stabilizing and then starting to drop. And just to give you an idea, to answer your first question, it really was across the board, across the board from a county standpoint and an acreage -- and an operator standpoint. There was no one area that stood out. And it wasn't a material amount of wells, just 29 gross (1.9 net) in every county -- really, every country we're developing in. One thing I'll note is as well costs have come down, we have non-consented less wells. And just to give you probably a metric that you might be interested in, in the first 2 months of 2013, Northern has only non-consented 5 wells. That's about a total of about…

Understood, very helpful. Just a quick follow-up then on the acreage. Looking at your 2013 acreage budget, do you expect this to essentially offset any expirations this year?

Could you repeat that question? I'm sorry.

Of course. Just shifting gears, I guess, to acreage. Looking at your 2013 budget, should that -- should we look at that as essentially offsetting any expirations you have on the leasehold side this year?

That would be a fair assessment, yes.

[Operator Instructions] We'll go next to Jared Lewis [ph] with Northwind Securities.

Just a couple of quick questions. When you look at 2013, can you give us an idea what your average working interest that you're looking at is?

Yes, we exited 2012 with 157 gross, about 12.4, 12.5 net, which is about 8%, which is consistent with our historical average. I think our average working interest on our roughly 1,250 PDP wells and roughly 157 or so on our PDNP are kind of averaging in that 8% to 8.5% range. So that's our historical average, and we expect that to be fairly consistent going through 2013. So I think just when it all comes out in the wash, we're still expecting the 44 net wells spud in 2013 with a consistent historical average working interest of about 8%.

Okay. Great. And just more a general question on the LOE expenses in the water and the disposal, what are you seeing as far as the infrastructure build? And do you see that coming down through '13?

I think the big push in 2012, which you're seeing for most of our operators as their conference calls have all happened here in the last 48 to 72 hours, we are seeing a big push for infrastructure development, specifically water gathering and water disposal. I think probably one of the biggest pushes in 2012 and into 2013 will be just further cutting the costs on water, on disposal and every area. Some areas are better than others. Some areas have more water than others. And infrastructures continue to ramp this. So that will be the big push here in 2013 because that's the biggest driver of our lease operating expense increases over the last year.

And we'll hear next from Curtis Trimble from Global Hunter.

I was hoping to gain a little bit of insight into difficulties, challenges, opportunities on forecasting production as more wells go into kind of a batch completion phase. Obviously, costs coming down aids you a great deal in the pad drilling. But how about line of sight into completion dates, initial production, et cetera?

That's going to be one of the benefits of 2013 is that the wells are going to be drilled more efficiently. They're going to be, we believe, a lot cheaper as they're all drilled through primarily on pads. We do, just from a conservative standpoint, expect the benefits from that to hit mainly in the second half of 2013 because we currently see approximately 2/3 of the wells that we're currently drilling as part of a pad drilling program. So that's going to be very beneficial to us. However, just from a conservative standpoint, we'll just say the weighting of our production drills in 2013 will probably be heavily weighted towards the back end of 2013. So it's fairly simple math. If you're drilling 4 net wells -- excuse me, 4 gross wells on 1 pad, you're going to get those wells drilled more efficiently. But they're likely going to be batch completed all at the same time. But one thing I just will note that is a little unique to Northern is that given the sheer number of wells that we're currently participating in, there isn't a scenario where we have certain dates where the wells -- where the production will come on or where we'll have a lumpy production. Given the fact that at the end of 2012, in December, we were drilling or completing 12.4 net (157 gross). Northern is always pad drilling wells, we're always batch completing wells and bringing new pads on. So there isn't a scenario where we have certain production coming on at certain months throughout the year. We're going to be constantly completing pads. And so we think we have a certain smoothing effect, for lack of a better way to explain that. But generally speaking, the pad drilling that has increased over the last few quarters will likely benefit us for the most part in the back half of '13.

Good deal, and that went down a little bit on the non-consent wells, you mentioned an $11 million figure for those. Would your assumption or theory be that a lot of those wells are science wells, they're testing deeper [indiscernible] of the Three Forks coordinated with co-development of the Middle Bakken, et cetera. Would it be fair to characterize that you're basically getting a free look at the science that other folks are conducting on those wells?

I don't think we had any science projects in 2012 to speak of. I think just generally speaking, not only were the costs escalating throughout the end of 2011 and the early part of 2012, but what we are seeing just given the sheer delay in completion, we're seeing overruns on those AFEs. So AFEs that were coming in the 10, 11 or 12 range, were all sending the overruns. So we were very careful with our CapEx deployment to those higher cost wells. So they were in -- these wells were in good areas. They were with good operators. But well costs just have come down materially over the last 2 or 3 quarters. So we expect this to be fairly limited. So there wasn't anything particularly unique. I think you've seen public data from some of the larger operators in the play who are consistently drilling wells in the 10.5 to 12 range in the Williston are now in the 8.5 to 10 range. I think that's just been a consistent theme of some of the operators who are drilling some of the higher cost wells. Some of our operators in 2012 that had the highest cost wells probably deserve most improved for 2012 for bringing the well cost down. So just to maybe finalize our thought on non-consent, we think they'll be limited if hardly any in 2013 just because of the decrease in well cost.

And that does conclude our question and answer session today. Speakers, I'll turn the conference back to you for any additional or closing remarks.

This is Mike. Thank you for your participation in this call this morning and your interest in our company. Kim will give you the replay information. And we look forward to seeing you during the conference season and sharing our results with you next quarter. Have a great weekend. Thank you.

And that does conclude our conference for today. If you would like to rehear this conference, the replay information starts today at 12 noon and ends on March 15 at 11 p.m. The phone number is (888) 203-1112 or (719) 457-0820. Thank you so much for your participation.