Northern Oil and Gas Inc (NOG) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Northern Oil and Gas first-quarter earnings release conference call. At this time, all participants are in a listen-only mode. Later in the call, there will be a question-and-answer session with Northern's covering analysts.

(Operator Instructions)

I would now like to turn the call over to our host, CEO Michael Reger. Sir, you may begin.

Thank you. Good morning, ladies and gentlemen. My name is Michael Reger. I'm the Chairman and CEO of Northern Oil and Gas. Ryan Gilbertson, our President, is also here on the call with me today. We are excited to welcome you to the 2011 first-quarter call for Northern.

Before we begin this morning's call, we'd like you to 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 on our annual report on Form 10-K for the fiscal year ended December 31, 2010, and our other reports that 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.

For those of you who are joining us to learn about Northern Oil for the first time, I'd like to take a moment to explain our operational strategy in the Bakken and Three Forks play. As a nonoperator, we participate in wells on a heads-up basis in proportion to our leasehold interest in drilling units. At any time a well is permitted, all parties controlling the leasehold interest within the drilling unit are automatically included in the well. As such, Northern Oil's leasehold interests are included in any well drilled within drilling units containing our interest. As an example, if we control 160 acres in a 640-acre drilling unit, we would own 25% of any well drilled in that unit and participate heads-up with a 25% working interest.

When a well is drilled in the unit, we then pay 25% of our share of all expenses and receive 25% of all crude oil and natural gas sold from the well, less our royalty burden. We do not farm out interest or dilute our working interest in any way. We participate for our proportionate working interest without the infrastructure and overhead costs of our operating partners. We believe capital is most efficiently deployed through this strategy, due to the substantial discount for which nonoperating leasehold interest can be obtained.

With over 25% of our Bakken and Three Forks positions developed to date, or under the bit, we believe we are moving ahead at an excellent pace. Importantly, we continue to acquire acreage at prices significantly below levels indicated in recent publicly announced transactions conducted by other industry participants. We believe our expertise and specialty in nonoperated interests continues to yield excellent results, and we look forward to continuing to add to our acreage inventory throughout 2011.

With no debt, and cash receivables and short-term investments of approximately $150 million, we are well positioned to fund the development of our core acreage position in the Bakken and Three Forks play. With that in mind, I would like to now turn the call over to Northern Oil's President, Ryan Gilbertson, to review our financial and operating results for the quarter.

Thanks, Mike. Northern Oil and Gas today announced record first-quarter oil and gas sales of approximately $27 million. Excluding the effect of unrealized mark-to-market oil hedges, Northern Oil had net income of $5.9 million, representing $0.09 per fully diluted share. Including the effect of unrealized mark-to-market oil hedges, Northern Oil had a first-quarter loss of $7.1 million, representing $0.11 per share.

Oil and gas sales for the first quarter of 2011 were $27 million, compared to $8.4 million for the third quarter of 2010. This represents a 223% increase. These results also represent a 13% increase in oil and gas sales during the first quarter of 2011 compared to the fourth quarter of 2010.

Production volumes for the first quarter were a quarterly record of 356,000 barrels of oil equivalent, representing a 185% increase over the first quarter of 2010, and a 5% increase compared to the fourth quarter of 2010. The first-quarter production volumes represent Northern Oil's thirteenth consecutive quarterly increase in production. First-quarter production consisted of approximately 94% crude oil and 6% associated natural gas and other liquids. Northern Oil exited the first quarter with production volumes of approximately 5,400 BOE per day. Northern Oil does not include flared and unsold gas volume in its production figures.

During the first quarter of 2011, Northern Oil spud approximately 9.8 net wells and added production from 55 gross, just under 5, net wells. Northern Oil has maintained a 100% drilling success rate in the Williston Basin, Bakken, and Three Forks trends since the Company's inception. Northern Oil's average realized crude oil sale price for the first quarter of 2011 was $74.10 per barrel, after taking into account a $9.73 per barrel loss due to the settlement of crude oil derivative contracts. This compares to an average of $70.49 per barrel realized price in the fourth quarter of 2010, which took into account a $4.25 per barrel loss due to the settlement of crude oil derivative contracts.

Production expenses for the first quarter of 2011 were $5.24 per BOE on an accrued basis, compared to $3.15 per BOE on accrued basis for the first quarter of 2010, and $3.69 per BOE on an accrued basis for the fourth quarter of 2010. The increase in production expense is expected and primarily due to the continued addition of producing oil and gas properties, exposure to new operators and development areas, an increase in working interests, mature wells utilizing artificial lift, and the general aging of our production.

Depletion expense for the first quarter of 2011 was $6.9 million, or $19.25 per BOE. As such, Northern Oil's first-quarter 2011 depletion expense was consistent with its peer group in the Bakken and Three Forks play. General and administrative expense, net of share-based noncash compensation, for the first quarter was $1.4 million, compared to $1.1 million in the fourth quarter of 2010.

Share-based compensation for the first quarter 2011 was $1.9 million, compared to $835,000 in the fourth quarter of 2010. The increase in share-based compensation was primarily due to share issuances related to the amending and restating of employment agreements, which included the extension of noncompete terms from one to three years, along with other various modifications. Adjusted EBITDA for the first quarter 2011 was $18.6 million, or $0.29 per diluted share, which represents a 190% increase over adjusted EBITDA of $6.4 million, or $0.14 per diluted share for the first quarter of 2010, and a 2% increase compared to the fourth quarter of 2010.

As of May 9, 2011, Northern Oil held working interest in a total of 395 gross, or 34 net, producing wells. As of May 9, 2011, Northern Oil was also participating in 138 gross, or just under 13 net, Bakken or Three Forks wells, drilling, awaiting completion, or completing, meaning Northern Oil has participated in 532 gross wells since inception. Northern Oil affirms that it expects to spud approximately 40 net wells throughout 2011 and reaffirms its guidance to produce an average of 6,500 to 7,100 barrels of oil per day through 2011.

Northern Oil continues to develop its core Bakken and Three Forks acreage position at an accelerating pace. According to the North Dakota Industrial Commission, 178 rigs are currently drilling in North Dakota. This significant rig increase in the play continues to accelerate the development of Northern Oil's core acreage position.

We currently expect to drill approximately 40 net wells in 2011, with drilling CapEx approximating $252 million. Based on current yet evolving conditions in the field, Northern Oil continues to deploy additional funds towards further strategic acreage acquisition during 2011. Northern Oil expects to fund all 2011 drilling commitments using cash on hand, cash flow, and its currently undrawn credit facility.

During the first quarter of 2011, Northern Oil acquired leasehold interests covering an aggregate of 11,500 net mineral acres, for an average of $1,600 per net acre and an aggregate expenditure of $18.4 million. Importantly, of the acquired 11,500 net acres, 3,400 net acres were permitted under the bit or begin producing as of March 31, 2011.

As of March 31, 2011, Northern Oil had 37,226 net acres, either held by production or under the bit, which represents approximately 25% of Northern Oil's Bakken and Three Forks position. Based on the current pace of drilling, Northern Oil expects that approximately 50% of its current acreage will be held by production or under the bit by the end of 2011.

Northern Oil recently participated in the Water Moccasin 1-34, a successful Three Forks test well operated by Slawson in the southern Montreal County Windsor project area. Northern Oil controls a 44% working interest in the well, which had an initial production rate of just under 1,500 barrels a day. The well had an initial tubing pressure of 2,800 PSI on a 12/64 choke.

On the same drilling pad as the Water Moccasin 1-34, yet in a different spacing unit, Slawson Exploration recently completed the Vagabond 1-27 well. The well is a Bakken producer in which Northern Oil controlled a 49% working interest. The well had initial production rate of 1,229 barrels per day and initial tubing pressure of 3,100 PSI on 11/64 choke. The Water Moccasin and Vagabond results confirm the expanding productivity of the Three Forks formation and the efficiencies gained from pad drilling.

Importantly, Slawson has received approval from the North Dakota Industrial Commission to drill six wells per spacing unit in the very highly delineated Windsor project area. Northern Oil also announced today that its Board of Directors approved the stock repurchase program to acquire up to $150 million of Northern Oil's outstanding common stock. The stock repurchase program, which will allow Northern Oil to repurchase its shares from time to time in the open market and negotiated transactions. At this point, we will open up to analyst questions and come back with a conclusion.

(Operator Instructions)

Derrick Whitfield, Canaccord.

Good morning, guys, and congrats on some very positive operational updates. Wanted to focus my first questions on a couple of recent corporate developments. Could you share with us a little extra color on your stock repurchase programs? You guys have certainly demonstrated quarter after quarter that you have the ability to acquire acreage accretively, and would this program imply that there's better value internally than externally?

Absolutely, Derrick. You know, Northern Oil has always maintained a certain amount of financial flexibility and what we believe has been the best use of our capital. The most important aspect of our growth right now is the ability to continue to acquire acres in the play. If you look at where Northern Oil is priced right now, the cheapest acres in the North Dakota Bakken play are in Northern Oil and Gas stock. If you take a round $20 stock price on our shares, you come up with a market cap of about $1.25 billion. Back out of that roughly $100 million in cash, and the asset market value of 10,000 barrels a day.

With the wells Northern has drilling or completing and paid for, we have 10,000 barrels a day of production that we will grow to. On the asset market, if you assume 10,000 barrels a day of production at $100,000 per full-in barrel, that's $1 billion dollars in asset value cash flow. Again, back out the cash, and that leaves only about $150 million for Northern's 150,000-acre core Bakken position. The market at $20 is valuing us at $1,000 per acre.

We can't find acres of the quality that Northern Oil owns for $1,000 an acre, and we're comfortable increasing the leverage of the Company to benefit shareholders by buying back Northern Oil shares. And we'll make that decision based on continued evolving conditions in the field, availability of capital, and the stability of oil prices, which at least for the morning, seem to have returned. And we'll always deploy capital to where we think the best return is, Derrick. And right now, we may be approaching a point where that is in Northern Oil and Gas shares.

And along the same lines of that ending point, how should we think about the timing of this initiative if in fact you guys do effect it?

The plan calls for purchases that can begin immediately, assuming the Company is not in possession of any material nonpublic information and things as such. We'll abide by Rule 10b5-1 of the Securities and Exchange Commission and effect purchases as we deem it appropriate. We won't necessarily telegraph that to the market, but we will say the stock is approaching a level where its acreage valuation is significantly below the cost to acquire new acres in field. So, we won't necessarily telegraph much on timing, but I will say that purchases could begin as soon as tomorrow.

Good, and then staying on leasing for a moment, could you comment on the competitive landscape in the Bakken? And really thinking about it from the standpoint of the quality of acreage opportunities and the amount of acreage opportunities you guys are seeing in the marketplace?

Well, we think the first quarter was still a fantastic quarter for us, being able to acquire 11,500 net acres, and an average price of $1,600 an acre means that these leases are still, we think, very accretively priced. Certainly, we've seen competition increase in the basin. We've seen prices continue to increase. You know, we've said many times that it's not the entrance of any new players to the Bakken that make it harder for us to acquire nonoperated interests. It's the sticky fingers of the land men and the lease groups that are generally holding those leases that we source our deal flow from.

So, the more stability in oil price in many cases, the tougher it becomes to acquire leases. But that's offset significantly by the increased drilling activity. Our opportunity set, as we've said many times, is in some ways converse to others in the play because the more drilling activity we see, the more AFEs out there, the more sort of forced sellers of these small pieces we see in the market. So as long as there's activity and there's volatility in the play and the price of oil, the opportunity seems to us to still exist.

And then one last question, if I could. Then I'll hop back in queue. Wanted to get some more color from you on the Windsor area Three Forks wells. They definitely appear to be very strong wells based on IP choke size and pressure stats. And while early, really interested in your thoughts on whether they appear as productive as the Middle Bakken wells you're drilling in the immediate area.

You know, Derrick, I think it is early to make a long-term prediction on what we're seeing for the Three Forks. But everything -- every piece of data we have to this point has been incredibly encouraging, and I don't think it's a stretch to say that what we're seeing in the Three Forks is as productive as what we're seeing in the Bakken. I think importantly, you noted in your question the significantly reduced chokes on these wells and the significant tubing pressures that indicate these wells, on an IP basis, could have posted much larger numbers than the numbers that were posted.

So, these are great wells. We've had a number of wells in the area in the Bakken that have been fantastic long-term producers, specifically the Stallion well, which I think made over 1,000 barrels a day average for close to four or five months. There's been a lot of data points there.

With the addition of the Water Moccasin, which is down to the south end of the loop, we've really delineated the entire Windsor area. I think what this should do is make it very clear in the Windsor area where we hold significant working interest, you will see six wells per unit. Slawson has gone to the state to obtain approval for that, and they've been granted it. And so I think it makes it -- it's really clear this is not a one-well per section area by any means, and we will have production in two zones.

Perfect. That's very helpful, guys.

Thanks, Derrick.

Peter Kissel, Howard Weil.

Yes, hi, guys. Good morning. One quick question. Actually, a couple here if I may. First of all, can you guys explain the formal process of changing your accounting firm? And really in particular, is it pretty fair to assume that Deloitte has looked through your past filings? And should we expect any sort of restatements, at least material restatements, coming out of the transition of auditors?

Thanks, Pete. You know, that's a great question, and we're very proud to welcome Deloitte as our new auditor. I can tell you a little bit about the intake process for Deloitte. The way that it works is that Deloitte essentially comes in, and with Mantyla McReynolds BDO Seidman, goes through all of the work papers from our audits. And they essentially test our internal controls and methodology, in other words, the way we account for wells. And Deloitte was -- Deloitte had no comments on our previous financial statements.

We don't anticipate any issues whatsoever going forward. We've never anticipated any issues. I'll reiterate that the accounting of Northern Oil is as simple as it gets. We're simply passed on these statements from the operators, which then flow through our financials. We don't have large assets on the balance sheet that need to be valued or assigned, and so it's pretty simple. And again, we're happy to have Deloitte.

We really appreciate the fantastic work that Mantyla has done for us over the years. There's never been any deficiencies in Mantyla's work that's ever been alleged to Northern Oil, or anyone for that matter. Northern Oil and Mantyla have both been vigorously inspected by the PCALB for the last couple of years. There's never been any deficiencies that have been pointed out. Mantyla has done a fantastic job, and we're very thankful for their support over the years. And we're happy and excited to be graduating as a larger Company to a big-four auditor and we look forward to looking with Deloitte.

Okay, thanks. That's helpful. And then secondly, can you please comment on your leasehold exploration outlook for the next twelve months or so, more on the corporate level than anything else?

Hey Pete, it's Mike. Thanks for your question. Northern, as you know, focuses specifically on nonoperated interests in the Williston, which means that we're not out looking for large blocks of acreage that may or may not be prospective where we can operate and having to go to the periphery of the play in order to find operatable blocks of acreage. We focus on the core of the play.

As we've said time and time again, Northern acquires small, nonoperated working interest in order to fully -- in order to quickly convert to production and cash flow. We typically know when we acquire an acre who's going to be drilling it, when they're going to be drilling it, how much it's going to cost, and roughly how many barrels we're going to get, given data from the surrounding wells. So Northern, from an acreage standpoint, is going to be more potent and likely have a significantly higher conversion rate from undeveloped acres to developed acreage than a typical operator, given the fact that we do acquire nonoperated interest within, primarily, permitted, docketed, or proposed wells.

So from that standpoint we've acquired -- as you know, we started acquiring acreage aggressively in 2006 and 2007. Those were five-year leases. Most of those early leases have converted to production. We have a significant acreage position in what we believe is the core of the play. Mountrail, Dunn, Williams, McKenzie. We have a new exciting block of acreage, block of nonoperated assets we've acquired in Stark after the recent discoveries of Whiting and Fidelity.

We continue to focus on the core areas of play. Therefore, we're seeing more exposure from a rig standpoint. There's currently, as Ryan mentioned, 178 rigs drilling in the North Dakota Bakken play. That's an astounding number, and as a nonoperator, that's the major driver of our development. And we believe that a vast majority of our acreage will be converted to production. And we feel very confident in our development.

Okay. So it's safe to assume that there's not a material amount of expiration coming due, in the near term at least.

No, we've listed it in previous filings where we have -- I think our average -- let me see if I can pull the data here. We've had -- we'll have probably about 10,000 acres that will expire in early 2012, and it's not anything that's material to Northern. And that's in our eastern Dunn County block. We acquired some acreage in the areas of, not to get too detailed with you, but township and range in the neighborhood of, say, 142, 93. And as you head east towards Mercer County, the shale gets fairly thin. So we acquired a block of acreage in 2008 in that particular area.

The broker we acquired that from wasn't going to let us just pick from the good townships. So we did buy some acreage down there that we thought would never be developed. It'll likely never be developed, but for the most part, the acreage we acquired is very exciting down there.

We have recently seen an increase in activity from OXY with Anschutz's group in southern Dunn, and we're seeing a tremendous amount of permitting down there from them. We believe that a good chunk of that acreage that we acquired in southern Dunn, we've always referred to it as the southern Dunn block, will be developed by OXY Anschutz, and we are excited to be working with them. They're a great operator.

But mainly, if you look through our future expirations, we don't start seeing any serious expirations until we start getting into 2012, and any expirations you do see are going to be probably in that Dunn block on the eastern side, which we wouldn't necessarily want to drill anyway. And remember, we bought that acreage back in 2008 for $400 an acre. So it isn't a material loss for us.

Okay, great. That's helpful. Thanks for taking my questions, guys.

Pete, this is Ryan. I'll just add on to that a little bit. In our 10-K, we disclose our acreage expirations by area, and it's important to note that we've always referenced our core Bakken and Three Forks position. And so what that means is that we've got some acres that are in the periphery that we haven't counted in our core. So I want to make this point clear, is that when we reference an acreage number, it's what we believe to be our core acreage position.

So when we post our acreage expirations, we may say there's 3,000 acres expiring in this quarter, 4,000 acres in this quarter. Some of that includes acres that are outside of the core that haven't been in that, exactly in that number. If you look at our average acreage expiration, it's fairly straight line through '12, '13, '14, and will be 50% held by the end of this year. Northern Oil doesn't expect to have any material changes to its acreage position due to expiration, just for clarity.

Okay. Thanks again.

Thanks, Pete.

Jason Wangler, SunTrust Robinson Humphrey.

Just on the production side, it looks like the exit rate was pretty strong, but obviously the quarter was a little bit lower than at least I had expected. Was that just basically the weather? Obviously, for the first couple of months was just pushing everything back, and now you're starting to get on track?

Yes. Thanks, Jason. There's no question that the first quarter in North Dakota was one of the worst ever from a weather perspective, and we've seen that reported by most of the operators as well. There was record snowfalls. We also saw that up here in Minnesota. What ended up happening is in many cases, it's actually tough to get to the wells if they're not already hooked up. The number of producing days per well was decreased, as well as the time from spud to sales.

So I think that the play, in a whole, continues to get better and better at this every year. We see more and more wells hooked up to intermediate gathering systems. We've seen a number of operators make very worthwhile investments in gathering systems at the well-head level and we're grateful for that. So we think that this issue continues to get better.

But this is North Dakota. It's an area that had very little oil production as of four or five years ago, so there's very little infrastructure in place. Every first-quarter production is going to take a rest, and we'll continue to see this every year. But as we've got here into the middle of May, the flooding in April and first week of May aside, things have definitely turned around and you'll see our drilling and completing list start to rotate over much quickly to the producing list.

Okay, and then just on the quarter as well, the pricing was a little bit lower than I expected. I know you got some hedges in there as well. But what are you seeing on the differentials, both in the quarter and then today? Are they getting better?

Yes, you know, we've seen the differential hover right around 9.0. We've seen a couple of days recently where -- or a couple of data points from certain wells for certain months where we've seen that tighten quite a bit. The WTI-Brent spread is unquestionably in our minds going to be a driver of tightening differentials. As we see more of this oil make its way from the Bakken down to points like St. James, Louisiana, where it's achieving LLS pricing, we should see that differential tighten.

Now, with the rash of production that comes online here as the weather warms up, we've typically seen differentials be strained and we're not seeing that this year. For the meantime, that Brent-WTI spread may be just keeping differentials where they were, but we think that as long as we see Brent-WTI at these levels, there shouldn't be much, if any, expansion on well-head differentials in the Bakken.

I'll turn it back. Thanks, guys.

Thank you, Jason.

Marshall Carver, Capital One Southcoast.

Yes, couple of questions. The Water Moccasin and Vagabond wells that were -- that have come online recently at those good rates. Were those included in the 1Q exit rate, or have those been put online since the end of the first quarter?

Thanks, Marshall. It's Mike. Those wells were right at the very end of the first quarter, and it's contributed to the most part to the entire first quarter. Those wells -- excuse me, the second quarter. To clarify what we mean by spacing units, different spacing units on the same pad. As you know, most operators, namely Continental and all operators in general now. But Continental's, Bakken, use these super pads or eco pads, or whatever they're calling them, whereby they can drill up to four or more wells per pad.

So the Water Moccasin well went south into a unit and the Vagabond well went north into a unit. One was a Bakken, one was a Freeport, which clearly highlights the productivity in both the Bakken and the Freeport in that Windsor program, which we've always known was coming, given delineation by other operators in the area. But that really leads to the ultimate down-spacing where Slawson has planned, three to the Bakken, three at Three Forks.

Okay, thank you. And would you like to give any guidance on second-quarter production? I know you've given full year production guidance, but any guidance for the second quarter? Or guidance on how many wells you expect to be put online in the second quarter?

Sure. You know, we -- Marshall, you can sort of derive from our yearly numbers where we think that will come in, and our visibility is fairly stable looking out to the numbers in the second quarter. And we should expect to increase production anywhere from 25% to 35%, which has been our normal historical growth rate as we go from the first quarter to the second quarter. And as we get more clarity on the third quarter and fourth quarter, you can see how that production will be distributed. But we do reaffirm our expected production for the year to average 6,500 to 7,100 barrels.

Okay, thank you. And one final question. On the share buyback, are you no longer thinking about the not wanting to go over 0.5 times debt to EBITDA? Is that ratio which you used to use no longer a ratio that you'll use?

Yes, thanks for the question, Marshall. That's an important one to notice. In looking at our CapEx plan coming into 2011, we've retained significant excess liquidity. We expect to do about $180 million in free cash flow, which we've stated, and spend about $250 million on drilling, $80 million on acreage acquisition. We're a little bit ahead of the pace on acreage acquisition.

We spent a little less than $20 million in the quarter, but that's sort of about what we expect to spend. That's really $330 million in total CapEx for the year. We came into the year with $150 million in cash. You add to that the $180 million in cash flow, and that really is our budget for the year. So, in thinking about 2011, that leaves us, given our current facility, about $100 million in excess liquidity.

We believe we could take our credit facility with very little work to $200 million to $300 million, somewhere between $200 million and $300 million very easily, and probably expand it beyond that. If we were to repurchase approximately $100 million worth of stock in 2011, we would be slightly above 0.5 times debt to EBITDA, but the addition of the reserves in 2011, setting up for 2012 cash flow, allows to us borrow more. And what we've basically said is that given the movement in the stock price, we do become a little more comfortable with some of this low cost reserve-based leverage.

We're going to be borrowing roughly 3% money on our credit facility. We're very easily able to take $100 million on that credit facility and stay just underneath that. If we bought the entire $150 million in 2011, we'd probably push up closer obviously towards just under 1.0 times debt to EBITDA. But I will say that from here on out, we are going to become comfortable with 1.0 to potentially 1.5 times debt to EBITDA, if our equity remains at the current levels. It just makes sense to use a little more of this cheap debt if the market's not giving us credit for the hard assets.

Okay, thank you.

Thanks, Marshall.

Josh Silverstein, EnereCap Partners.

Thanks. Good morning, guys. Just a question following up to that. I was curious how comfortable you guys might be of doing a bond offering and trying to accelerate some of the repurchase with the stock price down at this level.

Yes, that's absolutely an option that we've looked at. I mean especially given the recent move in rates. If we were to bond ourselves out, even as short as three to five years, which bridges ourselves to the point of significant cash flow, that is absolutely a possibility. We may consider that. We're going to compare and contrast what the costs of a bond offering would be versus the credit facility, and make a decision on that.

But we do become -- as we become -- as we layer on more hedges up here on $100 oil, the production profile becomes more stable and more visible. We do become more comfortable increasing that debt position. And like I say, to be very clear at $20 a share, the market's valuing Northern's oil acreage position at around $1,000 an acre. This is an acreage position that we've built piece by piece that is very core, that is very stable, and will turn to production. We represent, right now, by far the cheapest way to buy these hard assets in the Bakken. And so we will absolutely with our share price at this level consider increasing our debt to accelerate that buyback program.

Got you. That makes sense. And then also, I was curious, what the average AFEs were for the first quarter. I know you guys are still targeting about $6.3 million for the total year. A lot of the operators have been talking about cost inflation on all their conference calls. I was kind of curious what you guys were seeing.

Yes, you know, we still feel comfortable with our $6.3 million average for the year. We're very heavily weighted to Slawson, EOG, Continental, who are some of the best operators by far in the basin. They're very efficient. The areas that they are drilling near the Anticline and east of Anticline Mountrail county in many cases are shorter laterals, and a lot of these wells are actually coming in under $6 million. Most, if not all are actually coming in under $6 million. So we're seeing, no question, we've seen cost inflation from 2010 to 2011, but not enough to move us off our $6.3 million number. It's coming in about where we expect.

As far as wells west of the Nesson Anticline, we've seen continued efficiencies, and we've seen a continued great job by the operators west of the Anticline to really dial these wells in. Brigham's been doing a fantastic job as we've become more exposed to their wells. Same with Oasis.

These guys are doing a fantastic job of honing in on the most efficient, best practices on these wells. And so the growing efficiency in the play certainly will continue into the future. And the pressure brought about on services and whatnot by an increased rig count, we still feel should continue to be outweighted, equally weighted, if not overwhelmed by the increasing efficiencies of the operators who, again, are doing a great job.

Got you. And last one for me. I was curious if there was any update regarding some of your activity on the Montana side of the Bakken. It seems like there's been some good wells recently by some of your operators. Curious if activity is picking up there more rapidly than maybe some other areas.

Josh, this is Mike. We've started to see some really exciting data points coming out in Richland County, north of the Nesson Anticline -- excuse, north of the Coulee field -- and up into the southeastern corner of Roosevelt. Brigham announced the Johnson well, just right -- just north of Elm Coulee in Richland County, and we have a lot of acreage in that particular area, and then up just across the border into Roosevelt.

But as you know, as a non-operator, and as the clearinghouse for nonoperated interest, we will see, as more and more permits and more and more drilling activity come out in 2011 in that particular area, Northern will further expose itself to that new drilling and those new wells. We'll continue to buy interest from others in those units. We'll continue to buy acreage, minority interest splits in wells that are being permitted and docketed for permits. But a few data points, namely the Brigham Johnson well, have been exciting, and we look forward to more exciting data points in 2011.

Great. Thanks, guys.

Thank you, Josh.

Phil McPherson, Global Hunter Securities.

Hi, good morning, guys. Thanks for taking the questions. Ryan, just walking through the math that you did on the acreage thing. I was just curious. We all run these numbers on per-barrel economics and stuff like that, but to get to that 10,000 number of production you talk about to back into this $1,000 an acre, you have to spend the cash on your current balance sheet. So in fairness, wouldn't you have to basically deduct that or not deduct that out of your market cap right now? Wouldn't it be more like a $2,000 an acre thing?

We'd have to deduct some of it, but not all of it, because some of those wells have already been paid for, so they're already really essentially being [decremented] from our current assets. In addition, it doesn't include a lot of production that's already been paid for, for example, in the first quarter. So, you know, it's sort of rough and tough numbers, I guess, Phil. And if we were to break out where we are realtime, let's say it's somewhere between 1,000 and 2,000 in variance, but with 63 million shares outstanding, our cost on the acres is moving $300 to $400 per acre per dollar movement in the stock. So it's a fair point on how we want to break it out, but in rough terms, that's what we equate to, with the $20 stock price.

And the acreage number, it still includes this 10,000 acres in eastern Dunn, correct? Or not? That you're using for that calculation.

It doesn't include 10,000, no. It includes probably very few, if any acres in eastern Dunn. You know, you'll see our acreage continue to expand and, again, we're not going to count acres in total of the core that we think will expire. It may be plus or minus 2% or 3% here or there that may fall out. But it's a matter of 2,000, 3,000, 4,000 acres. I don't think it's a matter of 10,000.

Got you. So the 150,000 acre number is what we would be comfortable with right now?

Yes , absolutely.

Okay. With that eastern Dunn, should we potentially model an impairment charge then in early 2012? How does that work through the accounting?

No, it shouldn't. As acres expire, those dollars move from the unproved cost pool to the proved cost pool. As long as that proved cost pool doesn't exceed the PV-10 of the barrels in there, there's no impairment charge. So, essentially those dollars just move from one cost pool to the other. And so there -- you shouldn't expect at this point to see any flow-through to the accounting.

Okay. And I mean, you guys have done a great job acquiring prime acreage, and I feel your frustration here. Sounds like you guys are -- you used to be very aggressive, and seems like this call's more defensive. I was just wondering with the Deloitte coming in, are you guys addressing any corporate governance issues? I know there was another article out today talking about more entities that things have been done with. And do you guys want to address that and talk about what you're thinking going forward?

Yes, absolutely. Northern Oil is not deficient in any way in its corporate governance, we don't feel. We clearly have been the target of short selling, of blogs, of paid bloggers, paid journalists, and whatnot. We recently found out that our shares were lifted without our knowledge on the Frankfurt exchange, which is a typical MO for naked short sellers. Shortages have declined dramatically. Northern Oil is an asset-based company with no debt. And so we've -- the issues that have been brought out, that have been brought up have been a distraction, without a doubt.

Let's just address them one at a time here. So the article comes out today. There's a company that Northern Oil sells acreage to. What Northern Oil has done is divest working interest under 0.5% per well. We don't sell the acreage. We simply divest the well bore.

And we also get paid for the acreage included in that well bore without giving up the down-spacing possibility. So should we later acquire more acreage in that unit that pushes us over 50 basis points, we will participate. To give you a marker on what these types of well-bore interests are worth, since the beginning of 2010, Northern Oil has acquired 13 gross well bores that comprise just over 1.5 net wells at $0 acreage cost, meaning companies have called us and literally given them to us for free. Every company has a threshold at which their working interest is not material. What we were able to do in the transaction with Ashwood Resources was divest 91 well bores, which was 90 wells that need accounting, engineering, and need to be tracked in everything that we do.

So at the time, it was I think roughly a quarter of our net well bores. The aggregate net well count included in those was 0.23 of 1 net well. So it's approximately, hand waving numbers, 5 -- .005 to .006 of our net well count. For example, there are several wells in there where we may have owned 1 or 2 or 5 basis points per well. And the reason that would happen is because we acquire nonoperated interest, we may acquire 10% in one unit. Some of those acres may be included in other units that are subject to division, and that will reduce the number even more.

And so we absolutely believe that divesting well interests under 0.5%, getting paid for the acreage. The buyer of those interests is also paying their drilling costs. So we're actually getting paid for acreage that we retain the down-spacing right on. The transaction was vetted by Northern Oil's audit committee and was -- all transactions have been within prices included in the market, and it's very, very immaterial to the size of our position.

So really, the net effect of these articles is that it's taking time away from us being able to run our business. It's significantly attacking shareholder value in an asset-based company, and certainly you've sensed our -- you've correctly sensed our frustration. The transaction with Ashwood Resources we have confidence in. And it's not a related party transaction. We'll address that as well later in the call.

And that's a great exploration, Ryan, because when you read it, you start reading these things, and it's like I was reading about a Chinese E&P company as opposed to a Bakken E&P company. But I mean, do you think going forward, that it might make sense not to involve people that are related or are related to board members in divesting of these well bores? Is that something -- it's kind of like a light bulb went off? Whether it's beneficial to them or not, it's the perception is usually more important than the reality of matters when it comes to stocks.

Yes, you're absolutely right, Phil. And we will -- we're certainly contrite about the rapid pace that we've grown as a Company. You know, we understand that we're on the radar screen, and we're a shortable stock that large hedge funds can get big blocks of in short. And we're a target for that because of the growth of the Bakken and the growth of Northern Oil. And the -- probably the greatest transgression that we're guilty of is going 100 miles an hour in growing this business.

I will tell you that we focus very, very carefully on corporate governance, and if you pick apart any company to the level that the shorts have dug in for detail -- I'm embarrassed to say that they referenced our land manager's grandfather's funeral and tied the pallbearers in his funeral into some sort of impropriety. It's embarrassing, and it has nothing to do with the assets or the business of Northern Oil.

The bloggers or the shorts may want to attack us personally, but nothing that they can say or attack us on impairs the asset value of Northern Oil. The fact is we have 150,000 core acres in the Bakken. Like us or hate us, it's a diversified asset base that we have the capital to turn to production and cash flow. We certainly will be more cognizant in the future of the appearance of things, but we are absolutely 100% certain that what we've done does not constitute any impropriety that benefits us. And I'm actually going to turn it over to Mike for a second to read -- give him a second on the bit of conclusion here with relation to the Ashwood issue. And thanks for the question, Phil. And we want to address this, and we're happy to address this with any shareholder, anyone that may have a question with regard to this.

I want to just reiterate that we're very proud of what we've done in Northern Oil, and we've tried to do our absolute best to build this Company in the most efficient way to deploy shareholder capital. We believe very heavily in the stock. Mike and I are compensated 100% in stock, as you all know. We've always been compensated 100% in stock. As a result of that, we've had to make stock sales to pay our taxes. Mike and I have turned off our 10b5-1 trading plans that make sales tied to different share level, or different share vesting. And so you won't see any sales from us come on that, even though we continue to have significant amounts of shares vest that we owe taxes on.

So, we want to be as open, as forthright with any of these transactions that are being thrown up on blogs and whatnot, and we're happy to take any and all individual investor questions that's related to. We have nothing to hide here at Northern Oil, and we're happy to discuss any of the transactions that we've made that we believe are in the best interest of the Company.

And Phil, this is Mike. One thing I just want to address personally in regard to a blog post this morning regarding Ashwood Resources, who we divest these minute interests to. In September of 2010, five months after Northern executed the agreement with Ashwood to divest these minute working interests, Brittany, my wife, began assisting Ashwood as an independent contractor to process the massive amounts of paperwork that's associated with owning over 90 minuscule well bores. She's paid a monthly fee as an administrative assistant. It's not dependent on the profitability of Ashwood or any other factor.

The agreement with Ashwood makes sense for NOG, and it's not improper in any way. We stand behind the decision we made to divest the minuscule working interest, and I understand the goal of article was to damage my credibility or my family's credibility or Northern's credibility. But nothing that's being alleged affects the value of Northern's assets.

We haven't done anything wrong. This was not a related-party transaction. We believe we execute the most potent ground game in the Bakken play, and this PR issue has no bearing on our ability to participate in successful wells or otherwise execute our business plan. We appreciate that question. We wanted to hit it head-on, and if there's other questions regarding the -- any recent blog posts over the past several weeks, we're happy to address them head-on today.

Thanks, guys. That's a great explanation, and more than I was even expecting. Appreciate it. Keep up the good work at least in acreage.

Thanks.

Thanks, Phil. And again, I'll just indicate that we're going to keep the queue open for questions here from all the analysts, as long as you guys want to keep asking. I think we'll move on to the next one.

Marty Beskow, Northland Capital Markets.

Yes, I would say good job on the production side being up 7% quarter-over-quarter, which is even more than what I had anticipated. Was there anything that drove that, that you were on the high end of a lot of other Bakken operators as to the quarter-for-quarter production? Was it higher working interest, or certain areas that you had better production from?

Marty, it's a combination of a lot of things. This is Mike. As you know, we're very good on the ground at buying new interests and new well bores. We also are, as you know, fairly heavily weighted to EOG, Slawson, and Continental. Given the strength of those particular operators with their take-away, with their ability to convert their wells to production and get it sold, we were able to have a gain in production for the quarter. And most operators, as you saw over the last week or so with earnings releases, were in the neighborhood of flat to down, which is where the field has been guided in general.

The real issue is when you have whiteout days, roads that you can't drive on. You can't even get to the well pads or several days of just moving snow on well pads. You just can't get the oil out of the tank. When the tanks are full, the well switches off and turns off, and until the tanks are drained, you can't flow anymore oil into those tanks. That was the issue with the first quarter.

But from a drilling and completion standpoint, Northern, as you saw, continues to add, add new net wells at a brisk pace. The wells were spudding at a brisk pace, which several weeks ago, about six weeks ago, allowed us to increase our guidance from 36 to 40 net wells based on the rig count, based on the permitting activity we're seeing ,and based on the wells that were spud in the first quarter. So we just have a really potent bite of this Bakken, and we're going to continue to grow. Where I believe most of the field was in the neighborhood of flat to down in production in the first quarter, we're not surprised that we increased production in the quarter.

And also you listed quite a bit of detail regarding wells that you're currently drilling or waiting on completion or completing that seemed to have some pretty high working interest. What's your outlook for, say, even past that? Some of the wells that aren't in that detail that could very likely get spud this year or maybe even early next year. What kind of working interest are we looking at there?

Well, I think we're going to be averaging in that 10% or higher working interest throughout the year. You know, we published some of the highlighted completions. We published our drilling and completing list. And then the longest list of all is the permitted but not spud list. So we get a good amount of data from operators when we see AFEs come in, or we see permits come across, and we know what interest we own per acre. We have a pretty solid breakdown in our permitted yet unspud category.

So we get a good feel for what we're doing. We see significant pace of drilling this summer, especially as the weather has now improved. The rig count's the key. Again, 178 rigs. That's basically double from this time last year.

That's the driver of the development of this play. That's the driver of a lot of our new acquisitions, when an AFE or well bore or well proposal is sent out, it's likely that Northern is going to get a look at any of the nonoperated interests on that sheet, given our balance sheet strength. People do use this as a tool and they do consider us the nonoperated clearinghouse in the field.

And then on the expense side, could you give a little guidance as to your best guess as to production going forward for the rest of the year, G&A, and also stock-based comp? What should we be looking for second quarter, and third and fourth?

Hi, Marty. This is Ryan. As far as lease operating expense, we expect it to stay in the $5 to $6 range. To be honest with you, we don't get the data as quickly as operators do, so if we're seeing LOEs creep up for various reasons in wells, we don't always hear about it, but we do expect it to stay in that $5 to $6 range.

Our cash G&A for the year is about $4.5 million, and our stock-based compensation for the year is about a similar number, but of course that's dependent on where the stock is. As you know, Mike and I's salaries and everything is paid in stock. So as those different share blocks vest, they have either a lesser or greater effect on the actual P&L based on where the stock is on that day. So we've trimmed stock G&A roughly a third, along with our stock price in the last month.

Okay, all right. Thank you.

Peter Mahon, Dougherty & Company.

Good morning, guys. Most of my questions have been answered, but I just had one follow-up. In the sense that you deal with utilizing artificial lifts, how much does that, does putting a well on an artificial lift impact the cost per BOE? And where -- what's your general guideline for one that occurs over the well's life?

I'll answer that question. This is Mike. At a well during its life, if you consider from the beginning when it's flowing naturally, there's very little work that needs to be done to that well. Once you start employing the artificial lift, which is the pump jack, you're getting to a point where now you're dealing with less barrels per day naturally, because you're now using artificial lift. And you're now -- you now have the functionality of a full typical surface system on the well. You've got the pump jack, the treater, and so on and so forth.

So everything becomes just different. You have mainly a lower production volume from those -- because the well is now to a point where they would want to put it on artificial lift. That's the main driver. That's usually the trigger. But all of the costs associated with maintaining your well once it's on artificial lift is very different than when it's flowing naturally.

Okay, perfect. Thanks a lot, guys. Good work.

Thank you.

Derrick Whitfield, Canaccord.

Hey, guys. Just a couple of follow-on questions on the short reports. Can you comment on the Austin well and the O'Toole issue that the blogger raised today?

Yes, thanks, Derrick. This is Ryan. To clarify further on the issue was - the blogger had said that overriding royalty interests had been assigned to a son of one of our directors. One of the things we're very proud of is our network and our connections in the Williston Basin. And the son of Mr. Lauren O'Toole, who is highly regarded as one of the finest, most ethical, and most honorable oil and gas attorneys in the Williston Basin, works as a land man, an independent land man, and from time to time will direct us, or direct sellers to Northern or whatnot.

We've never transacted directly with any of the O'Tooles. We bought a lease, in this instance, directly from a land owner, and the group that Mike O'Toole was partnered up with reserved I think a 2% or 3% -- a 2% overriding royalty as their compensation on the lease, which is very typical for lease groups. And he was one of the three in the group. And so he was assigned out one third of 2% of the overriding royalty on that lease. And so it's a minuscule, minuscule part of a well. And it's very tough to do business in the Williston Basin with somebody we don't know.

We focus this Company 100% on the Williston Basin. And so it's a nonmaterial transaction, well, well below the threshold. It's one single lease, and the transaction was entirely appropriate. And so just to clarify that, the assignment of this immaterial overriding royalty lease was to Mike O'Toole, the son of one of our board members, who is a professional land man in the Williston Basin. And I hope we have the opportunity to do more transactions with him in the future, because it was a great piece of acreage at a great price.

Okay. That's helpful.

And -- thanks, Derrick. And then the second part is recent article published today alleges assignment of 3% of an Austin well that the article alleges changed to 50 basis points, and we don't have all the data on that. I can tell you that we pulled the file on the Austin well, and by the time that a drilling title opinion had come back, the working interest was under 5%. Working interests are changing and moving all the time.

To see a working interest go from 3% to less than 50 basis points is not uncommon. In our research, we actually found in the well next door that our working interest went from 5% to 7.5% by the time it drilled. So, we don't know exactly the detail behind that change. We've only had a couple hours to research it. But we certainly didn't move any working interest around. Nothing changed on that. It may be logical to assume that 2.5% was allocated to the other option well, which moved it from 5.0% to 7.5% and moved this one from 3.0% to 0.5%.

We're not exactly sure. But it's a very small, ridiculously minute level of detail to get into for a Company with over 150,000 net acres of leases. And so, I understand this is an unorthodox conversation. Certainly an unorthodox conference call, but we just want to reiterate and be very clear that we want to be as open as possible to all investors about any possible transaction or anything these blogs will continue to come out with. Thanks for the specific questions, Derrick, and if there's anything else, please let us know.

Quickly, and Mike or Ryan, if you can comment, please do. But given the aggression of these articles more recently, are you guys considering pursuing legal actions on either the blog or the Frankfurt listing?

Absolutely, Derrick. We've engaged German counsel to begin the work immediately on the Frankfurt listing, and Northern Oil will absolutely investigate any naked short selling in the stock, any slanderous or untrue accusation. You know, Derrick, these bloggers and paid shorts are good at what they do. And certainly, if we can find any illegal impropriety, we will absolutely prosecute it to every legal extent available to us.

We were amazed at the continued hassle that this has brought us. For the good of Northern shareholders, we don't want to be distracted any more than we have to from the business of running this oil Company the best we possibly can. So, if there are any legal remedies that we're able to find, we will absolutely pursue every possible legal avenue available to us.

And Derrick, let me jump in. This is Mike. The best way to respond to these short sellers and their attacks is to execute our business plan. We have a very simple business plan. It's very effective. And we will continue to respond with the execution of our business plan. That's the best way to respond, but we will be vigorously looking into any impropriety.

Great message, Mike. And then just as a follow-on to that, and really returning back to what's relevant, how many permits do you guys have ready for spud in Q2? Just trying to get a sense of the backlog that you're staring at.

It changes every day. We don't have the exact number of wells. However, we do have -- one thing we look at closely is drilling pads, actual pads that are set for drilling, and usually that corresponds to development in the quarter. Currently, we have approximately 60 gross or 6.22 net wells that have cleared pads ready for drilling with the flowback pits ready. We expect those to be added to our already existing wells in Q2.

Thanks. That's all for me, guys.

Thanks a lot, Derrick.

Marshall Carver, Capital One Southcoast.

Yes, thank you. Just one quick follow-up on the acreage. We're about halfway through the second quarter. Could you make any comment on the pace of acreage acquisitions quarter-to-date? Is it still tracking like it was tracking in the first quarter at about 10,000-acre a quarter clip, or has it slowed down or sped up since the end of the first quarter?

We're only about -- this is Mike. We're only about a month into the quarter, and we're getting to about the midpoint in the quarter. We have been acquiring acreage. The exact number we're pulling right now, it's in the neighborhood of -- in the first month, we've acquired around 3,500 acres, and we expect to be in the -- we expect to continue to develop or acquire acreage at the same pace that we have in the past. We don't see the field materially changing from that standpoint, but there's no way to tell exactly what our number's going to be at the end of any given quarter.

Right, okay. Well, thank you. That's helpful. And thanks for addressing all the issues you've addressed on the call. Thank you.

Thank you.

Thanks. Thanks, Marshall. This is Ryan. Just to give you some more hard numbers around that. The total amount of acres that Northern Oil has expiring in 2011 is about 37,000 acres. Okay? That assumes we hold no acres by production, which we'll hold a significant amount of those, and it assumes that -- it also counts some acres that we consider out of the core. So I'm going to try to be as specific as I can here with this, because I understand this has been another short thesis on the Company.

There are 37,000 acres that expire. Of that 37,000, a very good chunk, I'm going to say roughly two-thirds, will be held by production by wells that will be drilled in 2010. So -- or 2011. So roughly a third of that, call it 11,000 to 12,000 to 13,000 acres are what we will potentially lose in 2011, which is 7% or 8% of our acreage position. And decrement from that number, some of those acres that may be outside of the core, which are probably about half.

In general, Northern Oil can expect to lose 3,000 to 5,000 acres of core delineated Bakken that we don't want to lose in 2011. Call it somewhere between 2% and 2% slippage in the position of acres that will expire this year, if everything doesn't go exactly to plan. Again, like Mike said, that number is hard to pin down, but you can see what the book ends are on it. Northern Oil does not lose material core acres in 2011 period

Thank you.

All right. Thanks, everyone. This is Ryan again. We'll wrap up the call with just a final comment. The thing that Mike and I just want to convey to the investors personally is that we want to be available and accessible for any questions. We certainly would much rather be in North Dakota leasing acres and building this Company. But given the issues that have been raised recently, we want to make sure that we're available.

We encourage investors to reach out to us, and we're happy to go through any of these transactions again in detail. And to again be very clear, none of the allegations or issues raised in any of these blogs pertain to the impairment or the damage of Northern Oil's assets. They pertain strictly to the smearing of the character of management. Whether you like us or not, Northern Oil controls 150,000 acres in the premier oil resource play in North America that is very quickly turning to production and cash flow. And that is what we will continue to do as managers and shareholders of this Company.

Thank you, everyone, for joining the conference call. We apologize for the length and the unorthodox nature of today, but we're here to stay to run this Company and continue to execute on our business plan as we turn our nonoperated interests into production. Thanks, everyone, for dialing in, and we're here and available if there's any questions.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone have a wonderful day.