Northern Oil and Gas Inc (NOG) 2011 Q4 法說會逐字稿

Good day, and welcome to the Northern Oil and Gas Incorporated Q4 2011 earnings release conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Michael Reger. Please go ahead.

Thank you. Good morning, ladies and gentlemen. My name is Michael Reger. I am the Chairman and Chief Executive Officer 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 2011 year-end earnings call for Northern Oil and Gas.

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 annual report on Form 10-K for the fiscal year December 31, 2011 and 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. During this conference call, we will also make references to certain non-GAAP financial measures. Reconciliations of non-GAAP financial measures to the applicable GAAP measures can be found in our earnings release on Form 10-K filed with the SEC this morning.

2011 was a very pivotal year, in which Northern Oil more than doubled production, more than doubled crude oil and natural gas sales, and nearly tripled proved reserves. In addition to be these accomplishments, we strengthened the Company in a number of ways to best position ourselves to exploit our tremendous asset base going forward. I would like to highlight several of these initiatives before we reveal our operational and financial performance. First, in the spring of 2011, we engaged Deloitte & Touche, a top-tier, Big Four accounting firm, to serve as our independent registered public accounting firm. This was a very important step as we accelerated our growth throughout 2011. Earlier this morning, we filed our 10-K, which included Deloitte's report on the effectiveness of our internal controls and an unqualified audit opinion for the year ended December 31, 2011.

Next, Northern Oil strengthened the independence and governance of its Board of Directors by adding two new independent directors. These new directors are Rich Weber, the former CEO of Atlas Energy, which was sold to Chevron in 2011, and Cy Jamison, the former Director of the Bureau of Land Management under President George H.W. Bush. Our Board of Directors is now comprised of six independent Board members and me as the Chief Executive Officer and Chairman of the Board. As we continue to mature as a Company, it is important to clearly strengthen our corporate governance and the independence of our Board of Directors, which we believe we accomplished in 2011. Third, Northern Oil hired Erik Romslo as our General Counsel. Erik joined us from our outside legal counsel, Faegre Baker Daniels, which is one of the largest and oldest law forms in the Midwest. Northern has utilized Faegre as our outside counsel, specifically Erik Romslo, since the spring of 2009. This was also a very important effort as we continued to implement the processes and controls that will facilitate our continued growth.

Fourth, Northern Oil hired Tom Stoelk as our Chief Financial Officer. Tom joined us from Superior Well Services, which was recently acquired by Nabors Industries. Prior to working at Superior, Tom spent 11 years with Range Resources and its predecessor. Prior to Range, Tom was a CPA and Senior Manager with Ernst & Young. Tom brings a wealth of financial and strategy experience to Northern Oil. Fifth, Northern Oil hired additional staff, specifically in the areas of land, accounting, and in-house reserve engineering to help manage our growing acreage position, growing production, growing reserve base, and growing oil and gas sales. In-house reserve engineering is increasingly important to us, given our growing reserve base that is, and has always been, audited by Ryder Scott, arguably the most respected and conservative third-party reserve auditors in our industry.

Sixth, Northern Oil broadened our reserve-base revolving credit facility from a single lender to an 11-bank, $750 million credit facility led by RBC and SunTrust. Throughout 2011, Northern Oil did not access the equity capital markets, and our expanding credit facility will allow us to efficiently develop our current acreage position by leveraging our growing reserve base without dilution. Each of these initiatives, which were executed carefully and thoughtfully throughout 2011, have not only strengthened our Company, but have provided us with a broader depth of experience and resources to help Northern Oil continue to execute its business plan. I would now like to turn the call over to Northern Oil's President, Ryan Gilbertson, to highlight our 2011 operating results. Thank you.

Thanks, Mike. Northern Oil had a great year in 2011, with production increasing 117% year over year. We finished the year producing just over 1.9 million barrels of oil equivalent. Our sequential quarter over quarter production on a BOE basis increased 21% and reached proximately 7,000 average barrels per day for the fourth quarter, but was impacted by well shut-ins that allowed completions of adjacent and infill wells, as well as service delays experienced by many of our operating partners, which deferred turn-on dates. A large number of our new wells only produced for a portion of December. Nevertheless, our average daily production during December increased to approximately 8,300 barrels per day, and we estimate that our exit rate, given the large completions of -- given the large number of completions in late December, approached 10,000 a day as previously indicated.

Looking forward to 2012, we estimate that our production will approximately double again to about 4 million BOE for the year. Mainly due to non-cash unrealized mark-to-market loss on derivatives, we reported a net loss of $1.4 million, or $0.02 per diluted share, for the fourth quarter of 2011. Our net income per diluted share, adjusted for the $23.6 million of non-cash unrealized mark-to-market derivative loss, was $0.21 for the fourth quarter and $0.62 per diluted share for fiscal 2011, which doubled last year's comparable amount. For the year, we reported net income of $40.6 million, which was just under 500% higher than 2010's net income. Net income per diluted share of -- reached $0.65. Full-year adjusted EBITDA was $112 million, a 138% increase over last year. Fourth-quarter adjusted EBITDA was just under $40 million, which was up 23% compared sequentially to the third quarter.

Northern Oil's total proved reserves at December 31, 2011, as estimated by Ryder Scott, were approximately 46.8 million BOE, representing just under a 200% increase as compared to 15.7 million BOE at December 31, 2010. Approximately 34% of Northern Oil's crude reserves at the end of the year are categorized as proved development. Approximately 66% are classified as proved undeveloped. Northern Oil's estimated future cash flows, discounted at an annual rate of 10% before giving effect to income taxes, this is commonly known as the pretax PV10 value, the proved reserves at the end of 2011 reached $1.1 billion, a 273% increase as compared $295 million at 2010 year-end. As of December 31, 2011, Northern Oil controlled approximately 168,000 net acres targeting the Wilson Basin, Bakken, and Three Forks plays. In 2011, we acquired leasehold interests covering an aggregate of a approximately 43,000 net mineral acres in our key prospect areas for an average cost of just over $1,800 per acre. These acquisitions consisted of an average of approximately 244 net mineral acres per transaction.

In the fourth quarter of 2011, we acquired leasehold interests covering an aggregate of approximately 12,600 net mineral acres in our key prospect areas at an average price of $1,850 per acre. As of December 31, 2011 Northern Oil, had approximately 82,400 net acres developed, held by production, or held by operations, which represent just under 50% of Northern Oil's total Bakken and Three Forks position. Northern Oil currently has approximately 17,700 net acres that are undeveloped, with expirations occurring in 2012. Of that 17,700 net acres, approximately 10,000 are currently either permitted to drill, drilling, or may be extended at Northern Oil's option, which limits our 2012 expiration risk to less than 5% of Northern Oil's overall Wilson Basin position.

In 2011, we spud approximately 40 net wells, consistent with our prior forecast, and added 32.3 net wells to production. This brought our total producing net well count to approximately 58 net wells at year-end. Northern Oil added 14.9 net wells to production in the fourth quarter of 2011, representing a record quarter for net well completions. Northern Oil participated in the first of several planned Three Forks lower-bench test wells with Continental Resources. We are optimistic about the potential with these new production horizons. The Charlotte 22-H well, located in McKenzie County, North Dakota, had approximately 1,396 barrel of oil equivalent per day IP rate and produced approximately 45,000 barrels of oil equivalent in the first three months of production, according to Continental Resources February 23, 2012 earnings call. And again, we participated in this well and plan to participate in many more planned Three Forks lower bench tests.

We remain focused on our Bakken and Three Forks opportunities and on our expanding our acreage inventory, which we believe provides decades of future drilling inventory. As I previously indicated, we're still growing in these plays and very excited about the opportunities we see ahead. We continue to layer in hedges to protect the value that has been created and help to ensure we maintain the development capital to exploit our opportunities. At this point, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some of the financial highlights.

Thanks, Ryan. Before I get into the financials, I'd to first cover in more detail our recent syndicated credit facility. As we previously indicated on the call and in the press release, we increased our credit facility to $750 million and extended the maturity date until 2017. Through this expansion, we not only were able to extend the maturity date and enlarge the facility size, but we also increased the borrowing base to provide additional liquidity necessary to fuel Company's future expansion. The net facility reduced our LIBOR borrowing base rate by about 50 basis points and added a number of new lenders, which will provide dry powder as our asset base continues to grow.

As Ryan mentioned, the adjusted EBITDA reached $39.1 million in the fourth quarter of 2011, which increased 23% when compared to the third quarter of 2011. Adjusted EBITDA growth in fourth quarter of 2011 was fueled by 21% quarter over quarter production growth. For the year, 2011 adjusted EBITDA grew 138% as compared to 2010 and reached $112.3 million. 2011 adjusted EBITDA was driven by 117% year over year production growth, as well as a 14% increase in average realized price per BOE in 2011 as compared to 2010. Oil differentials during the fourth quarter of 2011 averaged $5.01 per barrel and for the full year averaged $6.02 per barrel. Total operating expenses per barrel of oil equivalent decreased $1.30 per BOE from $43.68 per BOE in the third quarter of 2011 to $42.38 per BOE in the fourth quarter of 2011. Production expenses on a BOE basis were lower in the fourth quarter of 2011 as compared to the third quarter of 2011, as we were able to average aggregate production expenses over a larger production base.

Production taxes printed lower in the fourth quarter 2011, due to the addition of wells that qualified for reduced rates or tax exemptions. Some of these tax reductions are temporary until a certain period of time expires or a volumetric threshold is received, at which point they will return to the regulatory rates. Depletion expense per BOE during the fourth quarter 2011 was $23.23 as compared to $20.34 per BOE in the third quarter 2011. The increase in depletion expense per BOE is due to an increase in expected future development costs. The fourth quarter of 2011 reflects an increase in tax provision rate to 35%, which is up from 34%, and it also reflects certain nondeductible expenses for federal income tax purposes. For our year, the effective tax rate was 39.8% in 2011, which compares to 39% in 2010.

We continue to layer in hedges opportunistically so the market warrants so we can maintain our growth momentum and our capital expenditure program. For 2012, we hedged approximately 6,200 barrels per day, with approximately 2,900 of those barrels being swapped at a weighted average price of $91.50 and the remaining 3,300 barrels per day using costless collars, with an average 2012 floor price of $90.65 per barrel and an average 2012 ceiling price of $105.42 a barrel. For 2013, we hedged approximately 4,000 barrels per day with costless collars, with an average floor price of $88.02 per barrel and an ceiling price of $102.36 a barrel. We continue to look for opportunities to increase these hedging levels, but we feel like we've established some attractive base levels. Jennifer, at this point, I'd like to turn the call back to you to begin the question-and-answer session.

Jennifer, we're ready for the question-and-answer, please.

Thank you.

(Operator Instructions)

Scott Hanold, RBC Capital Markets.

Looking at the fourth quarter, looks like your working interest on those wells you did complete went up back toward more that -- the higher level, around 10% or so. When you look into 2012, it sounds like you're gearing towards, and correct me if I'm wrong, about 11,000 barrels a day on average, somewhere around there. What kind of well count and working interest are you looking at?

Scott, this is Mike. In 2012, we expect wells, based on geographic regions in the field and based on different operators' techniques, we expect well costs to be between $6 million and $8 million, which is consistent with most operators in the play. We expect our working interest to remain in that 10% to 12% range, where we -- just similar to how we added in the fourth quarter. We did add 14.9 net wells to production in the fourth quarter, which was a record quarter for us.

Okay, did -- that was a pretty hefty pace of completions for the quarter. I think before, correct me if I'm wrong, you talked about around 40 wells on a net basis for 2012. Is that still a good number to use?

Yes, 44 is still our net spud well -- or net spud estimate for 2012. We also expect our working interest to remain in that same ballpark of about 10% to 12%, and so far in the first quarter, we're on track to be in the same vicinity of the fourth quarter net wells production adds.

Okay. Okay, thanks. And then in general, what's your sense -- I know it sounded like the fourth quarter, toward the end of the quarter that things got delayed Bakken-wide. From what you're seeing from your operators, have things started to get back on track and catch up a little bit? And I know you gave an estimate of a production rate at the end of year. Are we above 10,000 a day right now?

Yes, hello, Scott. This is Ryan. We are above 10,000 a day right now, and you can see with the chunky pace that we're adding wells, it's hard to necessarily track that day-to-day. Our last update was on December 15, and at the time, in between December 15 and the end of the year, we added five net wells to production. You can imagine what these wells coming in anywhere with high triple-digit to four-digit IPs that the day-to-day movement on what we're actually producing in any given day can be pretty chunky.

With almost 15 net well additions in the quarter, and expecting a sort of similar amount going forward, obviously it can't be 15 every quarter, with spudding net 40 net wells. But what we expect to spud 44 next year, and given this year the fact that we brought about 32 net wells online, take that number up about 10%. You can expect us to add to production about 35 net wells in 2012. And those will be somewhat slower in the first, second quarter, somewhat faster the third quarter, just based on weather, and right now we are above 10,000 barrels a day.

Okay, I appreciate that color. And one last question if I could, for Tom. Obviously, with that financing in place, that kind of helps your liquidity through 2012. As you look forward into 2012 and 2013, and it seems like equity's probably not in the picture. Do you think about turning some of that out to -- on a more long-term basis, or do you feel comfortable with where your revolver will be through 2012?

I think it's something that we continue to look at as a Company. The ability to term it out at some attractive rates is certainly interesting, but when you look at the facility that we established, we came out with about a $250 million borrowing base. We do have some more room with respect to that. We probably could've supported a $300 million to $325 million, as we sit now.

So, we have a lot -- we have plenty of liquidity. It's going to really get down to some internal discussions we're having now with respect to whether we try to term that out or use the facility. But with cash flow, and I think that the liquidity we have under that facility, it's -- we have a couple of options, to be honest with you.

Great. Thanks, guys.

Thanks, Scott.

Marcus Talbert, Canaccord Genuity

Couple questions, I guess, Mike, really, first for you. You guys had laid out the average leasing transaction that took place in 2011, 200 acres at a time. Given the range of funds that you're looking to allocate to the lease budget this year, are you under the impression that it's going to be continuing on as you guys have traditionally done, or would it be a little bit lumpier given maybe some of the size of the transactions that might be coming to the market in the Basin?

Markus, the acres that we're acquiring comes in your -- in a typical fashion of buying AFEs and buying acreage that is subject to a well proposal. We do that every day. That's how we've really built our franchise here.

There are some attractive packages out there that might add some chunky bolt-ons to our position. However, we expect to be in that same range of 6,000 to 12,000 acres a quarter in the same manner we always have. We expect 2012 acreage cost to average above $2,000, as opposed to, I think we were around $1,830 per acre in 2011. So, acreage costs are going up, there's no question. But with the continuing high rig count and what we believe will be a growing rig count in 2012, we expect to see additional activity and additional opportunities as we have in all of 2011.

Okay, great. And it looks like just from the quarter-to-quarter activity, the costs have come in just a little bit, but certainly thinking that the average cost for next year should be higher than this year, can you highlight where the majority of the acreage was picked up during the fourth quarter?

Are you referring to acreage costs or --?

The location of the acreage that you talked about adding, I think it was 12,600 or so during the quarter, that was done at a cost that was I think a little bit less than what you guys were having to pay in the second, third quarters. Where was that acreage, and is that somewhere where you'd be more interested in leasing on a go-forward?

Sure. We continue to add acreage in the core of the play. We do have several areas of mutual interest, two with Slawson Exploration and one with Continental Resources, where they are actively acquiring organically on the ground, both in North Dakota and Montana. And that's where we saw our lower acreage costs, where they were buying the acreage and we were subject to our proportionate interest in the area of mutual interest.

Okay. Great, thanks for the clarity on that. Maybe just one more question for me. You guys touched on the assumed well costs for next year. I think the last update we were at $7.5 million or so. Are you seeing, given the inflation in costs just in the past couple quarters here, does that -- are we pretty much on the high end of that range that you talked about here, given that you guys are probably moving to more longer laterals over the course of the year?

Yes, Marcus, this is Ryan. We budget about $7.4 million on average for next year, and the range we're seeing continues to expand. Some of those shorter laterals east of the [west] end we still see drilled in the $6 million or sub range.

The biggest well we've participated in thus far, the Whiting [Pronghorn] Federal, which I believe is still the biggest IP in the Basin, was completed for $6.3 million. Bigger dollars don't necessarily mean bigger wells. They can, but it's going to be more dependent upon geography and geology. We'll still see that range of $6 million to maybe even $9 million in some cases, but we feel pretty comfortable with our average of about $7.4 million for the year.

As we've always said, the tightness in service costs and the cost inflation that we see is always going to be offset to some extent by increasing efficiencies. And the way that you've seen a lot of these wells set up, in fact most wells now, are multiple well bores being drilled from the same pad. The efficiency from that operation isn't necessarily realized on the first well.

In fact, the first well is more expensive, with the net result being that the second, third, fourth wells coming from the same pad, whether it's at the Three Forks or whether infill wells, those wells end up being cheaper. The efficiencies that are created by the pad drilling and the infrastructure that's being put in place, we really haven't begun to realize yet. So, we've got those two offsetting forces and where that tug-of-war exactly ends up, we don't know, but we do expect well costs to remain in that $7.4 million range that we've estimated for the year.

Okay, great. Appreciate the color, Ryan. I'll hop back in line, guys.

Phil McPherson, Global Hunter Securities.

Nice job this year considering all the issues in the Basin. In the CapEx guidance, there was a little bit of a discretionary number around $9 million if you take the high end of the acreage. I was just wondering where that is at? Is that cost contingencies or anything?

In our total CapEx number, we also built in some of our capitalized costs, and some of those are actually non-cash. But anything that we have at the corporate level that ends up being capitalized into the cost of wells, it's counted in our CapEx, as well. And that may be title work, land work, things like that that end getting pushed up into there. So some of those expenses will get moved in there, and that's why you may see some of that extra room.

Okay, great. And just a little cost guidance, like the DD&A rate has been jumping up. Is that the number we should be using going forward?

Yes, I would be using the $23.42 that we experienced in the quarter.

Okay, great. On your acreage that you recently acquired in the quarter, any kind of geographic breakdown? I know you guys are pretty scattered, but are you seeing one area in particular where you're getting more aggressive? And then on the 5,000 or so acres that's due to expire, is that somewhere that is just not getting a lot of rig activity? Can you give us a little color on that?

Sorry, Phil. What was that second part of your question about the rig activity?

You alluded that you're going to have about 5,000 to 7,000 acres that could expire, and I was just wondering if that's in a concentrated area where you're not seeing any rig activity and what you're thinking there.

Phil, this is Mike. We saw, in 2011 in the fourth quarter, the acreage exploration exposure we were dealing with is primarily in eastern Dunn County. Of the acreage that we acquired, to answer your first question, about 75% of that was in North Dakota, and about 25% of it was in Montana, primarily in Richland County and our areas of mutual interest with Slawson Exploration. It breaks out in -- in North Dakota, to give you some color, a large portion was in the area of mutual interest that we are in with Continental Resources, which is at the intersection of Billings County, Dunn County, and Stark County, which we believe is very, very core. That's what Northern and Continental refer to as the Normandy Prospect.

We bought into that area of mutual interest in the fourth quarter. So that was a very interesting acquisition, or an exciting acquisition for us. The balance was primarily Montrail, Williams, Divide, and then McKenzie and Stark, in that order. Just to give you some color on where our fourth-quarter acquisitions came in. That's how it happened.

That's really helpful. Appreciate it. You made the comment about your borrowing base could support potentially $300 million to $325 million. What are they using? Can you give us a little color to get to -- come to that number, given you have a PV10 of $1.1 billion? Are they basically giving you a third? Is that the way to think about it?

No, I think all banks use different numbers, but I think they're using -- they're running a $75 oil price for us, primarily. My number comes from macro numbers, and I'm saying about 60%, 60% to 65%, something like that of our year-end PV, just based on the sensitivities I'm seeing. But the way it's -- every bank has a different price parameter as they run, but what we saw this go round at least, my mental average was around $75 a barrel.

Great. I appreciate it, guys. Keep up the good work.

Thanks, Phil. This is Ryan. I just wanted to add a couple more points of clarity there, and to be real clear on the acreage question, I want to be really crystal clear and analytical about this. We have a total of 17,600 net acres that have 2012 expirations. Of those acres 10,000, are already permitted or included in units. And then there's -- of that 10,000 number, maybe 1,000 or 2,000 are expendable at our option out beyond it.

So if there were no more permitting activity in North Dakota, the most you could see expire from our position is about 7,500 acres. If you hear anything different than that, it's absolutely untrue. And we expect that 7,500 number to decrease as the year goes by and as more additional permits come out. To be clear, Northern Oil faces no significant expiration risk in 2012.

Great. Thank you.

Jason Wangler, SunTrust.

Mike, I think you may have alluded to it a bit, as far as we moved to more pad drilling up there from the operators. Do you have a sense, either from what you're seeing on the ground today or even on the AFEs coming in, a rough estimate of what you're seeing drilled on pads, whether it's as little as two wells or even more?

The original wells that we're seeing now are primarily wells with two wells per pad drilling north and south, for the most part, into two separate units. So that generates a certain amount of efficiency. As we're going to go forward, once we get past the hold-by production phase of drilling over the next, say, 18 months, it's going to be primarily development drilling. And that's where we're seeing the four wells per pad from most operators being designed, whether it's one well to the Bakken and one well to the Three Forks going north into the same unit, and then one well to the Bakken and one well to the Three Forks going south in the same unit and then moving over in the unit approximately a quarter mile and repeating that process.

That's where I believe most of the operators have been communicating with us about their future plans as it relates to our acreage, and I believe that's what we've been hearing in most of the operators' conference calls. So, we'll continue to see cost efficiencies. We've seen ranges anywhere from $300,000 to $700,000 per well once you go to pad drilling, efficient pad drilling, in the future. We look forward to seeing those efficiencies as they come on.

Okay, and just one more. It's been a kind of a topic of conversation across a lot of the names up there last month or so. What are you seeing in terms of the pricing? And a commentary on what you're seeing in terms of transportation getting the oil out of there?

Hello, this is Ryan. There's always -- there's never going to be oil stranded in North Dakota. The transportation infrastructure has grown up around this field with the robust addition of rail, and what's been helping differentials lately is the disconnect between WTI and Brent. We've seen that move back out to $15 a barrel, so it's highly motivated the rail shippers to bid aggressively for the barrels and has really kept a firm bid underneath Bakken oil, despite some of the short-term, even day-to-day, disconnects we've seen with Clearbook Bakken pipe pricing.

The market for marketing oil out of the Bakken is much larger than just a single Enbridge pipe going into Clearbrook, and we'll continue to see increased allocations of capital where the marketers are able to make money. Our differential for the fourth quarter was about $5 back of WTI, but you can expect to see that widen a little bit as we get into March, here.

And there's always going to be a logical cap on where these differentials can go, given that there's been the investment there's been in rail infrastructure. We're not concerned at all about barrels moving out of the Bakken and the Williston Basin. They will find their way out. They will be very transitory, short-term disconnects, but at the end of the day, the infrastructure is there. And we'll see these differentials fluctuate at times, potentially as high as $8 to $10, potentially lower than we've seen in the last quarter, which was $5. But they'll ping around, but I think they'll generally continue to move the right direction.

That's good color. Thank you, Ryan. Thank you, gentlemen.

Marshall Carver, Capital One.

Couple of questions. On the CapEx spend in 2011 coming in at $414 million was a little higher than what I was modeling. Can you help me connect the dots here? You spent about $80 million on acreage, given you bought 43,000 acres at $1,800 an acre, which would leave about $335 million for drilling and completions. Was there some other expenses in that $335 million? Because with just 40 wells being spud, if you divide $335 million by 40, you get about a point for me in dollars so well, which is a good bit above what you all were guiding to.

Yes, there's some internally capitalized cost in there that when we report CapEx is in our cost incurred numbers in our 10-K, and that's been included in the release, and we've got about $16 million to $17 million of internally capitalized cost. In addition, our average working interest did go up between Q3 and Q4. Our average working interest in Q4 was about 6%. It nearly doubled. Our Q3 was 6% and a nearly doubled in Q4 to 12%, so you're actually seeing the CapEx drive probably -- that's probably the disconnect from your number. It finished about 11% for Q4.

Okay, that's helpful. Also, are you all -- do you usually offer guidance one quarter ahead? Are you all offering Q1 guidance at this point?

You know, we're not going to be offering quarterly guidance. One is the issues with a non-operator is the fact that you've got a large number of wells with a large number of operators with a high level of activity. We've got over 200 rigs running now.

We feel like we've got good visibility over the year, but trying to put pick those data points quarter-to-quarter, it's become problematic with respect to the accuracy of it. We don't think we serve the market very well by putting up an estimate that we may be high or low on, and we feel comfortable with annual numbers, but on quarterly numbers, we're going to discontinue that practice.

Okay, that makes sense. And one last question. Any updates on the potential for an MLP this year?

Hey Marshall, this is Ryan. The MLP remains a fantastic vehicle to transition some of the Northern Oil production, and we continue to work down that path. You will absolutely see clarity and the beginnings of execution on the MLP in 2012, and as we continue to grow and see our production base mature, and as we continue to see markers in the marketplace that indicate where the value of this Bakken production could and should trade, we'll continue to hone in on the exact proper structure for that MLP. And we're every bit as excited and focused on the MLP as we were three months ago, and it's absolutely a 2012 initiative that will happen.

Okay. Thank you.

Chad Mabry, Rodman & Renshaw.

Congrats, guys, on achieving your target of getting roughly half your acreage HBP at year-end. On that point, how much of your core position in Montrail do you think is held at this point? And what are you seeing in terms of down-spacing and Three Forks development in Montrail?

I think I can get you that exact number. It's -- about 50% of our Montrail position is held by production, so pretty consistent with our general percentages across the Basin. And I'm sorry, what was the second part of your question?

What are you seeing there in that core area in terms of down-spacing and Three Forks development on that piece?

This is Mike. We see a wide range of plans for infill drilling in the play by operator. We've seen DOG say given the nature of their rocks that three Bakken and two Three Forks efficiently recovers the same amount of oil in their Bakken core. In their Bakken light, they might go to four Bakken, three Three Forks. Whiting has been actively, based on what we've seen, planning on four Bakken, three Three Forks.

That's the same for Conoco. Now if you take Slawson, Hess, Continental, and XTO, their plans are three in Bakken, three to Three Forks, fairly simply with pad drilling, three separate pads with four wells per pad, two going north into a separate unit, two going south into separate units. So, it really depends on the rocks.

We've seen operators over in the Rough Rider area. We've heard engineers say that potentially in the deeper, tighter rocks over in Rough Rider that they could have in the neighborhood of five Bakken, five Three Forks. I think we see that with Brigham and others. We -- it's really just going to depend on the rocks and the operator, but that appears to be the plan going forward.

And we'll see how it comes about over time, but that's -- we're just reiterating what our partners are saying and doing. We're excited about the infill drilling inventory because it gives us literally decades of infill drilling opportunities on our existing held-by-production acreage. We've got a lot of work ahead, and back to what Tom was mentioning, given this credit facility and cash flow, we're ready to meet our CapEx going forward.

Okay, that's helpful. Thanks. And then shifting gears to the backlog. I think last time you updated the market you had a little over 21 net wells drilling or waiting on completion. Can you update that number currently?

Yes, thanks for that question. In fact, because of the mild weather in the Bakken, which has been amazing for everybody over the last few months, our backlog has actually slightly decreased. We're in the neighborhood of about, on any given day, right around 160 gross wells drilling or completing with that, right around that 10% working interest average. At one point, we were as high as 210 wells drilling or completing, with about 23 net in that total. It's working its way out.

Even though drilling has been increasing, we've been cutting our spud-to-sales time. In fact, in one particular interest, we know that several operators have been advertising frac dates from their dedicated crews, so that we believe is going to be material to the cost of fracs going forward. We're -- the efficiencies from that standpoint have been really important to us in the field as a whole.

Okay, great. And just one last modeling question. Looks like you had a little catch-up on your effective income tax rate in Q4. What's a good rate to use going forward? And then also, do you think there will be a cash tax payer in the near term?

We might have a small amount of alt-min tax, but not a significant amount. Modeling, I'd probably use somewhere around 39.5%. I think if you look at our annual rate, it's probably not a bad model to use. But an effective rate, call it 39.7%, 39.8%, somewhere around there.

Great. I appreciate it, guys.

Scott Hanold, RBC Capital Markets.

Yes, thanks, guys. Quick follow-up on the differentials. Just out of curiosity, I believe this is true, but just refresh me, you all basically sell your crude along with your operators, and do you generally know how much of that is nominated by like on the forward month versus sold at spot volumes?

Scott, we do not take any of our oil in kind, which means that we market alongside our operators. We defer to them to manage our marketing contracts with the different buyers, first purchases in the play. Each operator has a different system and how they do it, and we get certain amount of clarity, but it's delayed probably about six weeks to two months where we actually see what they were nominating and where.

But we have been hearing from our operating partners is that the rail marketers, or the marketers with rail capacity have been bidding more aggressively per barrel, and those marketers who primarily had capacity or allocations on the Enbridge line weren't able to bid as aggressively on barrels for March and April.

We know that in some cases we've seen contracts, rail contracts, be as low as $4 or $5 for March, which we expect given the Clearbook issues over the last month that March is going to be in that $8 plus range. We defer to our operators and we -- but in the first two months of 2012, we've seen our differential be in that $5 to $7 range, but trending higher.

Okay, got it. Do you plan on keeping that strategy, just taking your oil in kind? Or is there any other thoughts of marketing from your own group?

To be clear, we do not take our oil in kind, so we do not intend to market our oil at this point. We do have that option, obviously, but we've always elected to market with our operators because we've always found the greatest benefit with the scale with most of the operating partners that we participate with.

Okay, thank you. Thanks for clarifying my misstatement then. That helps. Thanks.

Josh Silverstein, EnereCap Partners.

Sorry if I missed this before, but I know you had mentioned the participating in the Continental deep bench test. Have any of your other operators talked about doing that in any of the wells you think will go down to that zone?

I believe Whiting has announced plans to spud a well, and I think they mentioned that in their call, and I'm not sure if we are in that well or not. But we have working interest in the Charlotte 2-22 that Continental drilled and we were encouraged, obviously, and we'll see if they continue to delineate that.

We look back several years, I think it is 2009 when Continental first started announcing their upper Three Forks wells, and that could be a potential doubling to the field, et cetera, et cetera. At the time, they were promoting it we had working interest in their first wells there, too. So we're very hopeful, and again, just to reiterate, we're very encouraged by not only Continental, but the work that every operator's doing in the field to unlock this premier resource.

Got you. And then the 15 net wells that you guys brought online in the fourth quarter, do you have an average IP rate for those? Usually you guys put up that list, and I didn't see that this time.

I don't think we have an average IP rate offhand. We can get that to you, I'm guessing. But we have seen most of our wells generally be in the four-digit range, 1,000 plus on an IP. That's peak IP rates. 30-day rates I think were probably still in that same neighborhood, pretty close to 1,000 barrels a day, but we can work through that and get back with you.

Got you. Lastly for me, just curious if you're still seeing your estimated EURs being that $550 to $600 range or if you think now that you're moving off, out of the core Montrail area that there might be some differences to that?

Hello, Josh, this is Ryan. We carry our average EUR and our reserve report lower than that, and probably find that our EURs are lower than our peers in most cases. Being a non-operator and not being able to supply the operator's data necessarily on the wells doesn't give us as much room in our discussions with the reservoir engineers.

I think those are generally good numbers for what the field believes these wells will produce, and as time continues to go by, we'll continue to see these EURs really hone in. One thing I think that's really important about our reserve report this year is that we had net additions to EURs. There was no net subtraction to EUR. In other words, evaluating to these wells a year later, there was no net subtraction to the EURs, only additions.

So, that's a pretty important statistic, and that's one that I would follow I think closely on everyone's reserve reports going ahead is with another year of data, or six months of data, are you seeing the EURs in these wells increase or decrease? And the EURs on our case, we have see an increase. So just touch again on how that filters through to the depletion number, we've also seen future development costs increase, which has made that depletion number greater in this quarter with this new reserve report, but it's not because of EURs dropping. Actually, the contrary was the case.

Got it, that's helpful. Thank you.

Sergei Hillery, IBERIA Capital Partners.

You mentioned that the held-by-production was slightly under 50%, and I was just curious are there any counties where that percentage is significantly higher or significantly lower than that number?

In Richland County, Montana, we have two areas of mutual interest with Slawson, which we have now drilled seven wells. And we have a lot of inventory with Slawson there. We have an additional seven or eight permits that we've seen hit on Slawson's acreage there. In one area of mutual interest, we are a 20% partner. In one area of mutual interest, we are a 50% partner with Slawson, and they are permitting and drilling that area aggressively, and we are very pleased with the results of those wells.

Throughout 2012, that's where we're going to add a material amount of held-by-production. In addition to, we believe, we're going to be getting to the balance of our Montrail County undeveloped acreage, as well as our Williams and McKenzie acreage, which is being very actively developed currently.

This is Ryan. I'm just going to add to that a little bit more. The answer is there's really no counties that have a significant deviation from that number. That has to do really with the nature of how we're acquiring these acres. We've never been a Company that has been an acquirer to push the fringes of the play and buy large blocks of acreage.

We've always sort of moved along with the path of development and continue to acquire acreage ratably as the pace of rigs moved into different counties. There are certain counties -- I misspoke slightly earlier when I said Montrail was about 50%. It's actually more than 50%. It's pushing about 60% in Montrail County, and as I look down the rest of the list, we're generally around 50%.

There's a couple of counties where we're less, but the acres are very small. For example, in Stark County, we have about 4,400 acres, 700 of which are developed. That's a smaller number, but it's a very small amount of acres. So, there's really no county that has a high concentration of either developed or undeveloped acres.

Okay, thank you. That's very helpful. And on the land acquisition costs, you'd mentioned that for 2012 it would be somewhere in the above $2,000. Is there any further clarity you could give? Is it mid-$200,000s, or just above $200,000, or whatever you can offer there would be helpful.

We really can't predict the future of where the pricing is going to go here. We just -- assuming that we continue to see the trends in place, we expect it to be over $2,000, but we really can't provide any more clarity on that anymore than we can provide clarity on the price of oil.

I understand. Well, thanks so much for your time.

And at this time, I'll turn the call back to Mr. Reger.

Thank you, Jennifer. 2011 was a great year for Northern Oil. We significantly increased reserves, production, and cash flow and positioned the Company for years of growth ahead. I want to thank you for your participation in our year-end call and your interest in our Company. Have a good day.

This does conclude today's conference call. We thank you for your participation.