Good day, everyone, and welcome to today's Northern Oil and Gas First Quarter 2012 Earnings Release Conference Call. Today's call is being recorded and at this time, I'd like to turn the conference over to Mr. Michael Reger. Please go ahead, sir.

Thank you. Good morning, ladies and gentlemen. 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 first 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 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 in our quarterly report on Form 10-Q that we filed with the SEC this morning. These forward-looking statements relate to our future plans, objectives, expectations and intentions. 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 and Form 10-Q, also filed with the SEC this morning. The first 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 10,000 net acres to our portfolio prospective Bakken and Three Forks acreage, bringing our total to over 173,000 net acres. We also have now reached over 90,000 net acres that are either developed, held by production or held by operations, meaning currently drilling. Also if you'll include permitted acreage, the number is now greater than 101,000 net acres that is either developed, held by production, held by operations or permitted. During the first quarter, we added 129 gross, 13.9 net, wells to our production base, that is nearly 1.5 gross wells added to production per day. We also spud another 112 gross, 12.4 net, wells in the first quarter, meaning that they hit the ground on acreage we control more than once a day. Our franchise is one of the largest non-operators in the Williston Basin and the clearinghouse for strategic, non-operated working interests is hitting on all cylinders and we look forward to growing production, growing reserves and adding to our acreage position with very minimal acreage explorations throughout 2012 and beyond. I would now like to turn the call over to Northern Oil’s President, Ryan Gilbertson, to highlight our first quarter operating results.

Thanks, Mike. Northern Oil had another excellent quarter, with production increasing 117% for the first quarter of 2012 compared to the same period last year. Our total production for the quarter was 775,000 barrels of oil equivalent, or Boe. Our sequential quarter-over-quarter production on a Boe basis increased 21% and reached approximately 8,500 average Boe per day for the first quarter. This production was impacted by well shut-ins that allowed completion of adjacent and in-fill wells as well as service delays experienced by many of our operating partners, which deferred turn-on dates. At this time, we continue to remain confident in our guidance of approximately 4 million barrels of oil equivalent production for the calendar year 2012. We reported net income of $8.8 million for the first quarter. However, this amount included a $9.4 million pretax, unrealized non-cash loss on mark-to-market derivative instruments. Excluding the unrealized mark-to-market loss on derivatives, net of tax we reported net income of $14.4 million, or $0.23 per diluted share. As Mike mentioned, the earnings release includes a reconciliation of these non-GAAP numbers, net income and net income per share. As of March 31, 2012, we controlled approximately 173,000 net acres in the Williston Basin, Bakken and Three Forks plays. During the first quarter of 2012, we acquired leasehold interests, covering an aggregate of approximately 10,278 net mineral acres in our key prospect areas for an average cost of $1,672 per acre, an aggregate cost of $17.2 million. As of March 31, 2012, we controlled approximately 90,700 net acres that were either developed, held by production or operations, which represented approximately 52% of our current total Bakken and Three Forks acreage position. During the first quarter of 2012, we had leases expire covering approximately 4,300 net acres. We currently have approximately 1,900 developed (sic) [undeveloped]…

Thanks, Ryan. Before I get into the financials, I'd like to first comment on another company press release made this morning. As you may have seen this morning, we announced our intention to offer $250 million of 8-year unsecured senior notes in a private placement eligible -- to eligible purchasers. We plan to use the net proceeds we receive to repay borrowings outstanding under our revolving credit facility, fund capital expenditures and for other general corporate purposes. Due to security law restrictions, we're not able to comment on this topic further at this time. Moving on to the financial results. Strong cash flow growth was a key first quarter highlight. We reported adjusted EBITDA for the first quarter of 2012, 141% increase over adjusted EBITDA for the first quarter of 2011. Adjusted EBITDA reached $44.8 million in the first quarter 2012, which increased 15% when compared to the fourth quarter of 2011. Adjusted EBITDA growth in the first quarter of 2012 is fueled by 21% quarter-over-quarter production growth. For the first quarter of 2012, we reported net income of $8.8 million and income per diluted share reached $0.14. During the first quarter of 2012, oil and gas sales, including hedging settlements, reached $59.8 million, which was a 151% increase over the comparable amount in the first quarter of 2011, and $9.2 million, or 18.4%, on a sequential quarter-over-quarter basis. Comparing the first quarter of 2012 versus the first quarter 2011, oil and gas sales growth was driven by 170% increase in production, as well as a 16% rise in average realized price per Boe. Higher average realized prices per Boe during the quarter were partially offset by higher oil differentials. Oil differentials during the first quarter averaged a little over $14 per barrel, as compared to $5 per barrel in…

[Operator Instructions] And we'll go to Neal Dingmann with SunTrust.

Say, just a couple of questions. First, Mike, or I think it was actually Ryan, talked about a bit on the well delays you're currently seeing. Just wondering how those are looking. And just when you look at some of your operators out there, how they're looking on completion delays and previously there was more frac delays, kind of how those are stacking up today?

This is Mike, Neil. I think one issue that we face in the first quarter was well shut-in while adjacent wells were being frac-ed by either the same operator or different operators and then it takes a short period of time to get a workover rig come in and drill out the plugs and get the well back producing again. That is mitigating itself but we'll see how's that progresses. As a non-operator, we see this in somewhat realtime but we're monitoring it and looks to be improving. As far as completion is concerned, that's one of the bright spots in the Bakken right now. We feel that the pressure pumping, availability is more available now than it has been, maybe since the play's inception. We're seeing a lot of capacity and we're seeing the spud-to-sales time tighten very nicely.

Okay. And then maybe just 2 others, quick. Just wondering, you mentioned differentials, wonder how those are working currently. And then maybe lastly -- just sort of an idea on the tax rate you see going forward?

We -- as far as differentials are concerned, it was clear that February and March we saw a fairly significant spike in differentials that affected our average for the quarter. Those have been improving. There's various ways to look at that. We've been seeing Clearbrook come back dramatically and is now, as of today, I believe, positive on the day. We also see significant rail takeaway and those -- the marketers in the field with rail allocations have been bidding the most aggressively being that they're able to deliver those barrels into prices more closely reflecting Brent, whether it's in the South in Louisiana or -- the East Coast is also fairly strong, we bid right now for those rail barrels for the light sweet.

And then, just on tax rate going forward?

I didn't hear what he said.

The tax rates going forward.

39.8%, that's what I've used.

And production tax rate for us is in the 9s right now. Given certain tax holidays, we think over time, unless there are additional holidays placed on production, we believe those will trend back up to 11.5%.

No, actually, I think they're going to trend probably with our Indian reservation, probably closer to about 10%. We've got a enough -- nice slug in their now and I think we'll probably be closer to 10% once some of the others go off. Probably not as high as 11.5%.

Neil, does that cover -- is that the answer to your...

That does.

We'll go next to Scott Hanold with RBC Capital Markets.

So on the CapEx increase to $360 million, you indicated that you're seeing more pad drilling and longer laterals. And is -- do you think that trend will progress when we look at $8.4 million. I mean, is that assuming sort of a static rate at lateral lengths going forward?

I think one of the [indiscernible] -- obviously, throughout the entire play, well costs have gone up to a degree over the past year. Our mix of 12 80s has gone up as we -- even EOG and Slawson, who we have been participating with for the last 5 years or so, have started to move more to 12 80s than 6 40s. So our mix has gone up quite a bit from 6 40 to 12 80. So that's affecting it. But we also expect to see a significant change in economics, especially as these pad wells are being drilled. We expect that to affect our well costs going forward. But right now, we think that the $8.3 million number, which is just an average of our current AFE costs for the wells -- the well proposals that we've received, we expect that to be fairly static for a while and then we're obviously hopeful on service costs, but that remains to be seen.

Okay, understood. And with regards to acreage acquisition, you bought a nice slug again this quarter for a pretty impressive price. Can you talk a little bit about where that was? And -- and I'm going to make this sort of a long question, a couple other things related to that. Regarding non-operated interests from other like large operators, you've seen several of the guys come out and announced packages. What kind of impact do you think that has to your business model? And then also one other thing on acreage. I think, Tom you may have mentioned something about some reservation land. Has Northern started to move on to the reservation versus -- where, previously date, I don't think you have a whole lot of reservation assets?

So I'll break that into the 3 questions. First of all, the acreage that we acquired in the first quarter of 2012 was scattered throughout North Dakota, as you would imagine, for the most part. One acquisition that we made was in Richland County, Montana that we acquired jointly with our partner Slawson Exploration, who we -- are in 2 separate areas of mutual interest with -- in Richland County, one is Big Sky and one is Lambert. Together, we acquired a block of acreage from a private seller that was -- that supplemented both of those areas of mutual interest. So Northern and Slawson took that opportunity. That was one of the reasons that we brought our cost down per acre in the first quarter. Just to give you a little color that going forward, in April, we've acquired approximately 2,600 acres at just over $2,000 an acre so the business model of acquiring these small, strategic, minority, non-operated interests continues. From time to time we may find some slightly larger packages but the one change in the first quarter was that Northern and Slawson joint acquisition. And then the second, as you would -- as you could imagine, several of the operators are divesting some of their non-op packages. That hasn't affected us to date. We'll continue to monitor that but we continue to see fairly robust activity as it relates to acreage opportunities in Bounty or at Northern. And again most of it is primarily permitted acreage that we're acquiring. And then we've never participated in any tribal mineral acquisitions. However, some of our acreage in Southern Montrail falls within the ancient boundary of the 3 affiliated tribes reservation. That actually is the net benefit to the operators, primarily Slawson and EOG and Northern as their -- one of their -- not the largest partner in Southern Montrail. So those are fee minerals that we own but the surface happens to be part of the old, the ancient boundary of the reservation, giving us a really attractive tax holiday. So that's what Tom was referring to.

Okay, so that clears up things. Good explanation. And one more if I could. Will you all kind of talk about where our current production is running right now?

Scott, I think that -- I think we'd like to take a pass on that question. As a non-operator, we typically don't have a perfect snapshot of what our production is on any given day. But what we will do going forward, as we mentioned in a previous production update, is very shortly after the calendar quarter ends, we will provide a production update for the quarter as we have clarity on the quarter, as we did in the first week or so of April. So in the first week or so of July we'll provide a quarterly production update on the quarter and give you and the other analysts an idea of where we expect to be for the second quarter.

Scott, this is Ryan. Scott, I just want to expand on that briefly. One of the reasons we've declined to provide quarter-over-quarter guidance is that, in the last 2 quarters we've added approximately 40% of our net wells. So really in the fourth quarter of 2011 and in the first quarter of 2012, 40% of our net wells have come online. And being that that's fairly young production, it's fairly inconsistent and just difficult for us to predict. So the metric that we like to follow is well spuds and well completions and you've seen that in the first quarter both those numbers were very robust. In fact, we completed more wells than we spud for one of the first times in a while, which indicates that shortening of spud, the sales time. So everything is moving forward, we're putting these wells online. It's just that the first quarter or 2 can sometimes be inconsistent and difficult to predict from the production standpoint.

We'll go next to Marcus Talbert with Canaccord.

Just a couple operational questions and maybe one financial-related one for Tom, if I could. Yes, I think it was great putting out this new metric in terms of days produced per quarter with the update that you guys offered a couple of weeks ago. Just maybe thinking about the drilling-complete list that you have, what visibility you have within that list in terms of how many of these new net wells that you're waiting on are infilled opportunities and if that can give you any insight, maybe just directionally, into which way this producing days metric might be moving as we go from quarter-to-quarter.

This is Mike. I think that our current inventory of infill wells is less than 10%. So it's not necessarily the issue of how many wells we're currently drilling are infill. We could have a well that's been on for several months or a year and it needs to be shut in because an adjacent well is being drilled by either the operator we participate with or an adjacent operating unit. So it's difficult for us to tell how that's going to be affected. But for us, we know that drilling and completion is very robust right now. Especially the time -- the spud-to-sales time has contracted quite a bit. So we're -- as we see the spud-to-sales date continue, or the time frame continue to contract, that's going to affect our overall acceleration.

Okay, great. I appreciate that. Maybe, Mike, you talked about the 2 AMI areas with Slawson. Could you offer any maybe incremental color into sort of his pace of development in Richland? Or how many rigs is he running in that area right now?

Well, Slawson is currently running 6 rigs throughout the play. One of the rigs is working currently in our Big Sky prospect. And either a new rig or sort of the rig in the Big Sky prospect is moving into Lambert here in June. That play has been a very attractive play for us. We're very pleased with the results. We will continue to update the market on color regarding that particular play out there, but we're very excited about it.

And maybe just one last financial question here. I'm not sure how specific you guys can be on this but based on the press release from earlier this morning, the notes that you plan to offer, does that have any impact on the current credit facility? Are there any, I guess, covenants or anything involved with the credit facility that related to an additional offering of senior notes?

Yes. We filed a 10-Q earlier this morning. If you take a look at the notes to the financial statements, you'll find out that when we issue permitted indebtedness, which this is, our existing borrowing base will be reduced by 25%. So that would be the impact it would have.

Okay. So the borrowing base might come in a little bit -- given I guess the level of activity in the last 2 quarters with 40% to 50% of the net wells producing coming online, would you expect to get a redetermination before the next, I guess, scheduled one if you have the ability to do that?

Yes. The answer is yes. Like we would expect -- probably request a special redetermination, given the size of the increase in our reserve base.

We'll go next to Marshall Carver with Capital One Southcoast.

Most of my questions were answered already. I did have a question, could you give a little extra color on the nonrecurring farm-in arrangements for the first quarter?

Sure, this is Mike. The nonrecurring farm-in arrangements were a handful of opportunities we took advantage of in Divide County with Samson and Baytex, where we were able to step into their shoes for their specific non-operated positions. In one -- I guess to make it as simple as I can, we would carry them for 15% of their interest and earn half of the underlying acreage under their unit -- under their interest, which kept our implied acreage acquisition costs under $2,000 an acre. So we saw those as very attractive opportunities. One reason for the nonrecurring nature is obviously clear: Baytex has sold its non-operated interest in Divide. But those were, we believe, onetime nonrecurring issues. They were great opportunities for us and we're happy to add them to production.

And Marshall, this is Ryan, I'll expand on that. The reason we break it out is that it's essentially an acreage-based transaction, where we're paying a share of drilling costs to earn acreage in the unit. But we have to count that capital as drilling or development CapEx rather than acreage. So we're not able to count those acreage additions in the quarter. So we break it out, essentially, the way it's -- these weren't really drilling costs but essentially additional acquisitions of acreage in line or cheaper than what we've been paying.

Okay, that's helpful. One other question, I think other people have sort of hinted at this with their questions, but are there any sort of unusual items that would impact production for the second quarter? Or do you just want to pass on that until April? Or if there's any items that you're aware of, could you pass those on to us?

Yes, this is Mike. I don't think there are any specific unusual items in the quarter -- in the field right now that would affect second quarter production. I think shut-ins due to workover will affect the production to a certain degree. We don't know if it's to the same extent as the first quarter. It might have improved greatly. So we don't know that exactly. But there's nothing unusual in the play. The play is operating fairly efficiently. And again, I'll just highlight the spud-to-sales time is contracting nicely due to the availability of pressure pumping.

Next we'll go to Chad Mabry with KLR Group.

Just a quick one on the model here, real quick. I did see a pretty healthy uptick in unit LOE in Q1, appears to be a function of workover activity in water disposal. But at what point would you expect to see this kind of level off?

Well, I think that the -- where we model it is right around 7.5 going forward for the long term. The issue is, we've brought on a fairly significant amount of new production. As Ryan just mentioned, over the last 2 quarters about 40% of our net wells has come on in the first couple of quarters. So, that increased our water disposal costs, as you would imagine. And then the workovers that we've talked about regularly relating to adjacent and infill wells being completed to our existing producing well bores has been affected. So I think that's where we model it going forward. But this quarter it was slightly higher, primarily due to well workovers, the workovers and the water.

[indiscernible] maybe normalizing back downward a bit going forward?

Correct.

And next we'll go to Phil McPherson with Global Hunter Securities.

You hit most of the detail stuff, I was wondering if I could just ask kind of 2 bigger-picture question. This Clearbrook going positive, it kind of took everybody by surprise. I'd be interested in your thoughts on why that happened. And then secondarily, we're starting to see some news on South Dakota and wondering if you guys are looking down there and what you think about the geology down there?

I'll answer the first question in that we are obviously hopeful with differentials. They have clearly improved since February and March. We don't know where they are exactly and we don't know exactly where they're going. Clearbrook, obviously, is a very positive indication of where differentials are going. Rail has been a big positive for us in the field. The answer to your second question is that we currently aren't looking at South Dakota for prospective Bakken and Three Forks.

Have you guys done any geological work or did you work...

No, we have not.

You haven't. Okay, so you just -- not in the picture for you right now?

No.

So I mean -- this is Ryan. Our model would be -- we'd be a long ways from getting into South Dakota. We need to see development and activity out there. As you know, we always follow in the path of development after we've got good data.

Yes, I figured that. I just didn't know if you guys had looked at any geology and if it's -- is it for real or is it just kind of people jumping on the next great bandwagon? But appreciate the color.

Our final question comes from Joel Musante with C.K. Cooper & Company.

I've got a couple of questions. First, your decision to offer the notes, does that affect your plans to do the drop-down MLP at all? I mean, you probably, you wouldn't be able to -- presumably, you wouldn't be able to pay down the notes, or debt on the notes, with acquisitions from the MLP -- to the MLP.

Joel, this is Ryan. Yes, standard covenants in the notes will make an MLP transaction still permittable (sic) [permissible], especially because it's inherently deleveraging. And so we remain optimistic and believe that the MLP opportunity is a very attractive one for our set of assets. And the offering of the note doesn't affect our plans on the MLP, just simply enhances our liquidity and terms it out.

Okay. All right. And then just one more on the gas price, your -- it came up -- it came out a bit higher that what I had expected. So, is there any trend we should note there?

Yes, we're -- this is Mike. We're just following it like anyone else. I think the liquid content and the richness of Williston Basin, Bakken crude, light sweet crude is a positive for us and we're hopeful, but we're monitoring it just like you are.

And with no further questions in the queue, I'd like to turn the call back to Mr. Reger for any additional or closing comments.

Great. Thank you, everyone, for your participation in this call and your interest in our company. Have a great day.

Once again, ladies and gentlemen, that does conclude today's call. We thank you all for joining.