Northern Oil and Gas Inc (NOG) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Northern Oil & Gas year and fourth quarter earnings conference call. At this time all participant lines are in a listen only mode. Later we will conduct a question-and-answer session with Northern Oil's covering analysts. (Operator Instructions) As a reminder, this conference is being recorded. I would now like to turn the conference over to Mr. Michael Reger, Chairman and CEO. Mr. Reger, you may begin.

Thank you. Good morning, ladies and gentlemen. My name is Michael Reger. I am the Chairman and Chief Executive Officer of Northern Oil. Ryan Gilbertson, our President, is also here on the call with me today. We are excited to welcome you to our 2010 fiscal year and fourth quarter earnings call for Northern Oil & 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 ended December 31, 2009 and other reports we have filed with the SEC. These Forward-looking statements relate to our future plans, objectives, expectations and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

For those of you joining us to learn about Northern Oil & Gas for the first time, I would like to take a moment to explain our operational strategy in the Bakken and Three Forks play. As a non-operator, 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 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 interests.

For example, if we control 160 acres of leasehold interest 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 drilling in the unit, we then pay our 25% 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 non-operating leasehold interests can be obtained.

With that background in mind, I would like to now turn the call over to Northern Oil's President, Ryan Gilbertson, to review our financial results for the quarter.

Thanks, Mike. Today we announced record quarterly production volumes and record quarterly revenues which were due, in part, to Northern Oil's 36% increase in production in the fourth quarter of 2010 over the third quarter of 2010. We also announced 2010 reserve growth of 158% and a reserve replacement ratio of 1,183%. Northern Oil achieved 2010 fiscal year record oil and gas sales of $59.5 million and earnings of $15.8 million, representing $0.31 per fully diluted share excluding the impact of a mark-to-market charge from oil hedges. Including mark-to-market charges from oil hedges we had 2010 net earnings of $6.9 million, representing $0.14 per fully diluted share.

Oil and gas sales for the fourth quarter of 2010 were $23.9 million compared to $15.5 million for the third quarter of 2010. Representing a 54% increase quarter over quarter. For the fourth quarter of 2010, we had a net profit of $7.3 million, or $0.13 per fully diluted share, excluding the impact of a mark-to-market charge from oil hedges and a one-time depletion adjustment. Including mark-to-market charges from oil hedges, and the depletion adjustment, we had a net loss of $1.75 million for the fourth quarter, representing $0.03 per share.

Our production volumes for the 2010 fiscal year were an annual record of 888,914 barrels of oil equivalent, representing a 215% increase compared to the 2009 fiscal year. Production volumes for the fourth quarter of 2010 were a quarterly record of 341,074 BOE, representing a 36% increase compared to the third quarter of 2010. The fourth-quarter production volume growth exceeded our previous guidance of 30% to 35% on a quarter over quarter basis, and represents Northern Oil's twelfth consecutive quarterly increase in production. Fourth quarter 2010 production consisted of approximately 95% crude oil and 5% associated natural gas. We exited the fourth quarter of 2010 with production volumes approximating 5,200 BOE per day. Northern Oil does not include flared and unsold gas volumes in its production figures, as some operators have.

During the fourth quarter of 2010, production was added from an additional 5.85 net wells. We have maintained a 100% drilling success rate in the Williston Basin, Bakken and Three Forks trends since the Company's inception. For the fiscal year 2010, our average realized crude oil sale price was $70.09 per barrel, after taking into account a $0.55 per barrel loss due to the settlement of crude oil derivative contracts. This compares to an average $56.85 per barrel realized price in the 2009 fiscal year which took into account a $3.60 per barrel loss due to the settlement of crude oil derivative contracts. During the fourth quarter of 2010 our average realized price for crude oil was $70.49 per barrel after taking into account a $4.25 per barrel loss due to the settlement of derivative contracts. This compares to an average $69.64 per barrel realized price in the third quarter of 2010, including a $3.22 per barrel gain due to the settlement of crude oil derivative contracts.

Our production expenses for fiscal year 2010 were $3.3 million or $3.68 per BOE on an accrued basis, compared to $754,000 or approximately $2.63 per BOE on an accrued basis for fiscal year 2009. Production expenses in the fourth quarter of 2010 were $1.3 million or $3.69 per BOE, compared to $1.1 million or $4.19 per BOE on an accrued basis for the third quarter 2010. Depletion expense for fiscal year 2010 was $16.9 million or $18.99 per BOE, compared to $4.3 million or $15.06 per BOE for fiscal quarter 2009. Depletion expense for the fourth quarter of 2010 was $8.6 million or $25.31 per BOE, compared to $3.8 million or $15.06 per BOE from the third quarter 2010. The fourth quarter included a one-time depletion adjustment of $3.5 million.

General and administrative expenses, net of share-based compensation, for fiscal year 2010 were $3.6 million compared to $2.4 million in the fiscal year 2009. G&A expenses net of share-based compensation for the fourth quarter of 2010 were $1.1 million compared to $899,000 in the third quarter of 2010. Northern Oil's adjusted EBITDA for fiscal year 2010 was $47.1 million or $0.93 per diluted share, which represents a 338% increase over adjusted EBITDA of $10.7 million or $0.29 per diluted share for fiscal year 2009. Our adjusted EBITDA for the fourth quarter of 2010 was $18.2 million or $0.32 per diluted share, which represents a 43% increase over adjusted EBITDA of $12.7 million or $0.24 per diluted share for the third quarter of 2010.

Northern Oil defines adjusted EBITDA as net income before interest expense, income taxes, depreciation, depletion, and amortization, accretion of abandonment liability, pre-tax unrealized gains and losses on commodity risk, and non-cash expenses relating to share-based payments recognized under Accounting Standards Codification Topic 718. We believe the use of non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically we believe the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized commodity hedge gains and losses, and the depletion adjustments that management believes are not indicative of our core and ongoing operating results. In addition, these non-GAAP financial measures are used by Northern Oil's management for budgeting and forecasting, as well as subsequently measuring our performance. And we believe we are providing investors with financial measures that most closely align to internal measurement processes.

Using year-end SEC pricing parameters, Northern Oil's proved reserves were 15.7 million barrels of oil equivalent as of December 31, 2010. Reserves using SEC pricing parameters were calculated using a constant realized net price of $70.46 per barrel of crude oil. And $5.04 per 1,000 cubic feet of natural gas. The 2010 proved reserves represent a 158% increase from 2009 estimated proved reserves, and are comprised of approximately 14 million barrels of crude oil and 10.5 million cubic feet of natural gas. This increase in proved reserves equates to a 1,183% replacement of 2009 production. Approximately 41% of our 2010 proved reserves are categorized as either proved developed producing or proved developed non-producing, meaning behind pipe. Approximately 59% are classified as proved undeveloped. As a non operator, we account for a very limited number of proved undeveloped locations.

Our estimated future cash flows, discounted at an annual rate of 10% before giving effect to income taxes, otherwise commonly known as a PV10 value, for proved reserves at December 31, 2010 were $295.5 million compared to $87.8 million at December 31, 2009, representing a 237% increase in PV10 value year-over-year. Our independent reserve engineers also prepared the sensitivity case for Northern Oil's reserves at December 31, 2010 using recent February 25, 2011 pricing parameters, assuming a constant realized net price of $88.91 per barrel of crude oil. And $5.04 per thousand cubic feet of natural gas. This more accurate sensitivity case calculated our proved reserves as of December 31 at a PV10 value of $418 million.

As of March 1, Northern Oil controlled 147,400 net acres in the Williston Basin targeting the Bakken and Three Forks formation, and a working interest in 337 successful discoveries. Consisting of 332 targeting the Bakken and Three Forks formation, and five targeting Red River structures. We are currently participating in 136 gross or 13.32 net Bakken or Three Forks wells drilling, awaiting completion, or completing, which is a new Company record. We expect to spud approximately 10.6 net wells in the first quarter of 2011 and reaffirm our previous guidance of 36 net wells expected to be spud during 2011. We also reaffirm our guidance to produce on average 6,500 barrels of oil equivalent per day in 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, approximately 168 rigs are currently drilling in the North Dakota Bakken and Three Forks plays, up from approximately 99 rigs drilling last year at this time. The significant rig increase in the play continues to accelerate the development of our core acreage position.

In 2010 we acquired leasehold interests covering an aggregate of 56,858 net mineral acres for an average price of $1,043 per net acre in our key prospect areas. In the fourth quarter of 2010, we acquired approximately 18,000 net mineral acres for an average price of $954 per net acre in all of our key prospect areas spanning the counties of Billings, Burke, Divide, Dunn, Golden Valley, McKenzie, Mountrail, Stark and Williams, North Dakota. And Richland and Roosevelt counties, Montana. During the first quarter of 2011, through March 1, 2011 we have acquired 7,191 additional net acres at an average price of $1,900 per acre. As of March 1, 2011 Northern Oil had 23,279 net developed acres and 11,596 net acres under the bit. Which represents approximately 24% of our total Bakken and Three Forks position held by production or eminently to be held by production.

Our current Bakken and Three Forks prospective acreage position will allow us to drill approximately 921 net wells based on six net wells per 960 acre average spacing unit. This takes into account the fact that some spacing units consist of one section 640 acres, some 1,280 acres. We use 960 acres as an average spacing unit. As of March 1, 2011, we have hedged 1.789 million barrels of oil using open commodity swaps settled in NYMEX WTI pricing and a weighted average price of approximately $87. As well as 451,000 barrels of crude oil collared between $85 and $101.75, again quoted in WTI. The swaps settled between February 2011 and December 2012. The Costless Collar settles between February 2011 in December 2011. The costless collar is used to establish floor and ceiling prices on anticipated crude and natural gas production. There were no net premiums paid or received by Northern Oil in relation the Costless Collar agreement.

Our current commodity swap and collar portfolio represents approximately 58% of 2011 production and 27% of anticipated 2012 volumes. We expect to drill approximately 36 net wells in 2011 with drilling capital expenditures approximating $227 million. We currently expect to drill wells during 2011 at an average completed cost of $6.3 million per well. Based on current yet evolving conditions in the field, we also expect to deploy additional funds to our future strategic acreage acquisitions during the year. We expect to fund all 2011 drilling and acreage acquisition commitments using cash on hand, cash flow, and our currently undrawn $100 million credit facility.

Finally, our press issues released earlier this morning highlighted various recent wells completions in which we participated. The highest level, highest working interest list of completions that we have recently participated in. We encourage you to review that information.

And I will now turn the call back to Mr. Reger.

Thanks, Ryan. 2010 was a transformational year for Northern Oil as a significant portion of our Bakken position turned to production. With approximately 25% of our Bakken and Three Forks position developed or under the bit, we believe we are moving ahead at an excellent pace. Importantly, we continue to drive shareholder value with our non-operated franchise by acquiring acreage significantly below levels indicated in recently publicly announced transactions. We believe our expertise and speciality in non-operated interest continues to yield excellent results. We look forward to continuing to add to our inventory of acreage throughout 2011.

With our cash position in excess of $150 million and an undrawn $100 million revolving credit facility, we retain significant liquidity to grow and develop our substantial Bakken position. We continue to be impressed by the extension of the field and the down spacing potential that is now clearly evident. We wish to thank all the operators with which we have participated for their innovation in this premier oil resource play.

Thank you for joining us on this call. This concludes the overview of our 2010 fiscal year and fourth quarter financial results. And we would now like to entertain questions from our covering analysts.

Thank you. Our first question is from Derrick Whitfield with Canaccord. Your question, please.

Good morning, guys, and congratulations on a solid year end. Thinking about your recent activities to date, could you comment on the competitive landscape and what, in your view, is putting upwards pressure on non-op acreage? And maybe it's a follow-on to that question, and noting that there remains a wide valuation arbitrage, what is your current appetite for further acquisitions at the $1,900 breaker range?

Thanks, Derek. This is Ryan speaking. We certainly feel that $1,900 an acre is still incredibly economic in this play. A really important statistic on our first-quarter acquisitions thus far is that 40% of them are already under permits or drilling. So, we are still keeping a very short time frame on these acquisitions. We're not really wildcatting, again, out into new areas. We are buying acres that very quickly go under the bit. Given the data that we have seen, and especially in some very recent transactions, indicating acreage prices $10,000, $12,000, $15,000, $17,000 an acre, there's plenty of room to grow. As we've anticipated, prices have started to move up across the board in 2011, but still not meaningfully so. We have budgeted, going forward here, our expectations towards that $1,700 an acreage average. We continue to see our ability to acquire acres at that price exist, and our appetite remains strong. In the transactions that we have executed here in the first quarter, that 7,100 acres has come at an average transaction size of 342 acres. So, we continue to buy in those smaller chunks. That is where we continue to see the edge and we expect to continue with more of the same as we go forward.

Thanks.And then moving over to your development activities, you note in your press release that approximately 24% of your acreage has been developed or is under the bit. Do you have available what percentage of that falls within your core Windsor, Southern Mountrail area?

In the Windsor area, of the held by production acres, it's about 20%. About 20% of those held by production acres are in what we consider to be the Windsor area. More accurately, our core area is really the scope of the very productive area of the play, and all the acres fall under that definition. But I think if your question is with regard to a level of specificity, as far as what is in the Windsor area, it is about 20%.

Terrific.As a follow-on to that, how many rigs is Slawson currently running in the Windsor area, and how do you see that projecting in 2011?

Right now, Slawson is current running four rigs in the Windsor area. They began to downspace that area fairly aggressively. As you may know, there is a tax trigger that takes place on July 1 where right now we are paying very favorable taxes in the Windsor loop, we are paying 5%. And that will ratchet up to an average of about 9% for wells that are spud after July 1. So, Slawson has been running four rigs down there fairly aggressively, and they are in the process of moving to five to drill that area as aggressively as they can, again, with both new wells and downstream wells as well as Three Forks development.

Great. And then lastly, if I could, could you offer some color on what you are seeing with AFEs by general area, and comment on the spreads, if any, between AFEs and actuals?

Sure.The general trend there has definitely been higher. We are seeing inflation, we'll probably see inflation across the board of about 10% compared to this time last year. Our range in AFEs right now is probably about $5 million to $8.5 million. The highest AFEs we're seeing out to the far western part of the play, with the operators that are in the deeper part of the basin. We will probably see those particular AFEs start to hone in a little bit more towards the $7.5 million number, and probably see less of those $5 million short lateral AFEs. Our average for the year is $6.3 million in our budget, but there is no question we have seen inflation pressure on the play. We have seen operators continue to drill ahead into this commodity price environment, and with that we have certainly seen the service companies benefit, as well. As far as how long that trends continues, and how severe it becomes, it's really anybody's guess. We see the same pressures remaining but we also see that, again, offset by continuing growth in efficiencies. So we don't think well inflation is something that is going to push this play towards its economic boundaries, although we'll probably continue to see a little bit of it as we go along.

Perfect, thanks. That is very helpful, guys.

Thank you. Our next question is from Phil McPherson with Global Hunter Securities. Your question, please.

Good morning, guys, nice job on the acreage acquisition side. Could you go into a little detail about the reserve bookings and give us your philosophy on PUDs? I was doing some back of the envelope math and it didn't look like you booked a lot of PUDs this year.

That's a great point, Phil, and thank you for that question. As a non-operator when we sit down with Ryder Scott, our reserve engineer, they will give us credit for very few PUDs. Basically a well has to be permitted or docketed or in a publicly disclosed drilling schedule for Northern Oil to be credited with a PUD. So you'll see our ratio of PDP in our reserve report is much higher than most of our peers. If we were a "operator", I could scratch out a well list on a piece of legal paper, hand it to Ryder Scott and receive PUD credit for every one of those wells. But as a non-operator we simply don't. And you will see our PUD credit probably continue to grow over time, but as a percentage of total reserves, it will probably still remain lower. The one thing you will see is our ratio of PUD conversion will be higher than any one of our peers. Let me just see if I've got that number in front of me here.We've converted between 80% and 90% of our 2009 PUDs in 2010. So you won't see a ratio that high by virtually anybody. There is really no way around it, from our perspective, Phil. We just simply book far less PUDs as a result of our position as a non-operator.

That makes sense. Were you able to get all 24 net wells into the reserve report?

No, we were not. In fact, we had two net wells, two net wells that were PDNP, completed, fraced, and not in the flow back phase that were excluded from the well report. So, again, our reservoir engineers are, we believe, consistently hyper conservative with us and with our reserves, and you will see a big difference in our reserve numbers from the PUD perspective in just the credit we're given as non-operators. So basically 10% of our production at the end of the year was not able to be included in the reserve report, as well.

Great. And I was just wondering, you give us the guidance on the 6,500 barrels. It looks like from other people first quarter is going to be down just from weather related. So is there any way you can guide us to a little more specifics, maybe even what an exit rate might look like in 2011?

We still feel good about the 6,500 number. We don't see -- we certainly aren't going to decrease production in the first quarter. We expect to hit our typical 30% to 35% quarter over quarter increase again, from fourth quarter to first quarter. We really haven't seen that, to be honest with you, in the field. We have seen, certainly, somewhat of a slowdown in activities, and we continue to see our drilling and complete list back up. Right now we've got 13.3 net wells drilling or waiting to come online, so that is a significant amount of production. We continue to see that number grow. It usually reaches its peak around the wintertime. But with the pace of drilling we have in front of us, we continue to expect it to stay high all year. As we mentioned in the press release, we have got 136 gross wells right now that are drilling or completing. So, an appreciable portion of the wells in the field we're involved in.

We think that diversity also helps mitigate some of the seasonal effects that we have seen in the past. And it also insulates us from specific areas and specific problems. One thing you will see is that if an operator -- with the tightness in completion crews, if an operator misses a completion appointment or misses a frac appointment, that fractor is going to move onto another well. It may affect that operator disproportionately but from our perspective, we are in so many wells that if it is moving from one well, it's moving onto another well where the first well might've been pushed back two weeks, but the well it's moving to just got pushed up two weeks, and we are probably in both of them. So it ends up being much more of a net-net no change for us. And the biggest change that we have seen as far as this winter versus last is that Slawson has now picked up 1.5 dedicated frac crews to support their rigs. Which they didn't have last winter. And with a disproportionate piece of our drilling occurring with Slawson, the addition of their dedicated frac crews has really helped shorten the time for us from spud to sale, and we hope that trend continues.

That is great. And just two quick housekeeping questions and I will jump off. It looked like the DD&E rate jumped up. Should that be the normalized rate for 2011?

The normalized rate for 2011, based on the new reserve report, will be right around $19 a barrel, just under $19. And based on restriking the reserve report and what-not. The way that some of those PUDs are handled affects us, as well. You will see the rate in the quarter was higher than both the year's average and what we expect for 2011 going forward for that one-time $3.5 million charge. But as we go into 2011 you can model a DD&E rate of about $19 a barrel.

Great. And can you give us a hard number for 2011 G&A costs including both non-cash and cash costs?

For 2011 budget, all in is $7.2 million, Phil, including both cash and non-cash charges.

Great, thanks, guys.Keep up the great work.

Thank you. Our next question is from Jason Wangler with SunTrust Robinson Humphrey. Your question, please.

Hi, this is Joanna for Jason. Can you just talk a little bit about the differentials you are seeing for oil?

Sure, that's a very good question.That has definitely been a hot topic lately. Differentials that we're still seeing are starting to come in fairly consistently around 10. But what is interesting is we have actually seen a couple of very important data points where on an individual well basis, with the spread we are seeing right now between WTI and Brent, or more accurately WTI and LLS, Light Louisiana Sweet, we are actually seeing pressure on those differentials to tighten. We are seeing less and less oil shipped out in the traditional way, as we are seeing a significant amount of oil leaving the field now via rail. The oil that leaves North Dakota via rail, most of it ends up in St. James, Louisiana, where it is priced on the LLS benchmark. There's a very very wide spread between where WTI and LLS are pricing.It's around -- LLS is actually, I believe, above Brent right now, so you are looking at about a $16 or $17 spread between those two. So $10 back at the well head is really $27 or so back of LLS.What we're actually seeing is more competition for the barrels at the wellhead. So this blowout in the spread between WTI and Brent is actually a very, very net positive for the play. We expect to see our differential, as it relates to WTI, hopefully tighten over the next year. But $10 right now is a fairly good number, but if we do see this LLS relationship continue to exist where it is, I think unquestionably that will tighten down in a meaningful amount.

And just secondly, are you having any transportation issues for your oil?

No transportation issues right now. Every barrel seems to be finding a home. Production in the field is growing much more quickly than the take away is growing. So that's certainly going to be an ongoing discussion to have in the future. And we believe that the capital will find its way to the field to move the barrels out. But we haven't had any trouble moving barrels on an absolute basis. We have certainly seen differentials grow over the last couple of years. And that is the situation we are all going to have to monitor going forward. But it is one aspect of this play that does keep us up at night. With high oil prices, the fast pace of drilling, excellent well results, take away will become an increasing concern in the field as we go forward.

Thanks, that's it for me.

Thank you. Our next question is from Marty Beskow with Northland Capital Markets. Your question, please.

Mike and Ryan, very good job on your acquisition for acreage over the last couple of quarters here.Can you give a little more color as to the types of acres you are acquiring? You had an average cost of about $945 an acre during the fourth quarter. And that increased to a little over $1,900 an acre in the first quarter. Was the type of acreage you were acquiring quite a bit different, on average, as you went from quarter to quarter?

Sure. Marty, there was one specific acquisition in the fourth quarter that drove our average down a little bit, and that was a piece of acreage that we bought in Montana. It was approximately 7,000 acres in Montana. That's, Marty, one reason why we had the average drag down. The types of acres we are acquiring, I think, are most accurately reflected in our conversion ratio of acres to production and how quickly that occurs. 40% of the acres we've purchased so far since January 1, 2011 are permitted or drilling. The fourth quarter acres we've purchased, approximately 85% are permitted or drilling. So what we are actually -- excluding the Montana piece. I think that is probably most indicative of the quality. We are really not, again, our philosophy has never been to be the bravest in the field. We've never wanted to be the first into a new area. We've never wanted to step out of the comfort zone or the zone of activity. And as a non-operator it is important for us to preserve our capital and opportunities that very clearly will work. So the acres that we are buying, in general, are fairly spread across the play. There's a couple of new areas that we are focusing on that strategically we won't go into too high of a level of specifics there.But we really continue to acquire across the play, but most importantly the acres we're acquiring are very quickly turning into production.

Can you also talk about the pipeline of activity for acreage acquisition? How is that, how many deals are you seeing right now and opportunities to acquire acreage, and how does that compare to what it was third and fourth quarter, or even, say, the first half of last year? Is the activity picking up or is it about the same or is it a little bit slower?

It's about the same, Marty. I'll tell you what really is the driver. And this will seem counter-intuitive, but the higher the oil price, the more rigs, the more activity, the easier it is for us to acquire acreage. And the reason that happens is, as these rigs mow through the field, and continue to AFE more and more acres, those are the kinds of opportunities that specifically are coming to us right now. Imagine if you're a small acreage holder in North Dakota and you have an AFE that shows up, you have 30 days to pay. The operator is not going to slow down for you. If you're not elected and paid, you are non consented into the well. And believe it or not, we still see almost every single AFE that we get containing some sort of non-consenting parties. Some people just simply can't come up with the cash quickly enough or sell the acres quickly enough. And what we really tried to do is build our franchise in North Dakota as being the first and last and, in many cases, the only call for those acres.

So the faster the pace of drilling, the more opportunity we see in the field, and, importantly, we continue to see this field expand. We continue to see new frontiers being pushed. We are always -- we're monitoring that very closely. And with our wide diversity of activity, we are able to see how different parts of the play evolve and allocate our capital accordingly.We see about as much opportunity to continue to acquire as we did last year at this time. We continue to acquire at the rate of 200 to 300 acres a day. We expect to continue to grow that. And we move through the field like a Pac-Man just gobbling up these working interests that are shaken loose as the AFEs come. So in the robust pace of development we see right now, it's a great environment for us to continue to acquire.

All right. Great quarter. Thanks.

Our next question is from Peter Mahon with Dougherty & Company. Your question please.

Good morning, guys.I just had two follow-up questions. One, you guys have a CapEx plan for 2011, $227 million. How much of that is going to be devoted towards acreage acquisition?

The $227 million, Peter, is just our drilling budget, so we plan on using that entire $227 million to drill wells. If we continue to acquire at the rate that we have been, our target is, call it, 200 acres, 250 acres a day at the levels we are seeing acres. Acquisition on top of that could be another $75 million or $80 million. And we could do all of that within our cash flow and credit facility and cash position.

Got it. I apologize, I missed that. The second question has to do with your guidance. You guys said that the exit rate out of the March quarter was 5,200 BOE a day. Is there anything that concerns you guys in 2011, why you didn't move that guidance range north of 6,500 BOE per day? If you are already tracking at 5,200 going into the year, it seems very conservative to say that you're going to finish the year averaging 6,500, especially with the growth rates we are seeing out there. Is there anything that you guys are -- is there any reason for that?

There is nothing really specific. As a non-operator we are always somewhat cautious on the pace. And certainly you can see, based on the wells that have spudded in the first quarter, that we are ahead of that 36 net well pace. I think that nobody is wrong in triangulating, potentially, where this production could go to But 6,500 is a number we feel comfortable with right now. A lot of this early stage production can be very lumpy. And if you imagine 13.3 net wells waiting to come online, I'll just do some quick math here, 13.3, and let's say wells that are going to come online at a 30-day average, of, let's say, 700 barrels a day, which is probably conservative. That's 9,300 barrels a day of production. If those wells come on, on average, a month earlier or a month later, 280,000 barrels, divide that by 365 days, that is a swing in our annual production of 760 barrels per day. So with the large amount of wells we have in the queue, we do have some variance around that number, and so just think of it that way. If those 13 wells we have in the queue come online plus or minus a month from what we expect, it moves our daily rate for the entire year by 700 or so barrels. So it's a substantial swing and it's why we tend to be on the cautious side with everything that we do. As a non-operator, we always maintain a very clean balance sheet, very strong cash position, and very reasonable expectations going forward.

Perfect, thanks a lot for the color guys, good work.

I believe that concludes our conference call for today. I want to thank you all for attending and listening in, and thank you all for supporting us in 2010, and we look forward to another great year in 2011. Thank you so much.

Ladies and gentlemen, today's Northern Oil & Gas year end and fourth quarter earnings conference call will be available for replay after 2.30 PM Eastern Standard Time today through March 16, 2011 at 11.59 PM.You may access the teleconference replay system at any time by dialing 866-837-8032 and enter access code 1508609. Again, those numbers are 866-837-8032, access code 1508609. That concludes the conference for today, and thank you for your participation. You may now disconnect.