Northern Oil and Gas Inc (NOG) 2012 Q1 法說會逐字稿

Good day everyone, and welcome to today's Northern Oil & Gas first quarter 2012 earnings release conference call. Today's call is being recorded, and at this time I would like to turn the conference over to Mr. Michael Reger. Please go ahead,sir.

Thank you. Good morning ladies and gentlemen. My name is Mike Reger, I am the Chairman and CEO of Northern Oil & Gas. Also with me today isRyan Gilbertson, our President, and Tom Stoelk, our Chief Financial Officer. We are excited to welcome you to the 2012 first quarter earnings call for Northern.

Before we begin this morning's call you should be aware that certain statements made during this call may contain forward-looking statements that are based upon management's expectations, estimates, projections, and assumptions that involve certain risks and uncertainties. We encourage you to review the various Risk Factors relating to our business, which are available in our Quarterly Report available on Form 10-Q that we filed with the SEC this morning. These forward-looking statements relate to our future plans, objectives, expectations, and intentions, results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

During this conference call we will also make references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in our earnings release on Form 10-Q also filed with the SEC this morning.

The first quarter of 2012 was another record quarter for us in terms of production, oil and gas sales, and adjusted EBITDA. We also had another great quarter of acreage acquisitions, adding over 10,000 net acres to our portfolio. prospective Bakken and Three Forks acreage, bringing our total to over 173,000 net acres. We also have now reached over 90,000 net acres that are either developed, held by production, or held by operations, meaning currently drilling. Also, if you include permitted acreage, the number is now greater than 101,000 net acres that is either developed, held by production, held by operations, or permitted.

During the first quarter we added 129 gross, 13.9 net wells to our production base. That is nearly 1.5 gross wells added to production per day. We also spud another 112 gross, 12.4 net wells in the first quarter, meaning the bit hit the ground on acreage we controlled more than once a day. Our franchise is one of the largest non-operators in the Williston Basin, and the clearing house for strategic non-operating working interests is hitting on all cylinders, and we look forward to growing production, growing reserves, and adding to acreage position with very minimal acreage expirations throughout 2012 and beyond.

I would now like to turn the call over to Northern Oil's President, Ryan Gilbertson, to highlight our first quarter operating results.

Thanks, Mike. Northern Oil had another excellent quarter, with production increasing 117% for the first quarter of 2012, compared to the same period last year. Our total production for the quarter was 775,000 barrels of oil equivalent, or Boe. Our sequential quarter-over-quarter production on a Boe basis increased 21%, and reached approximately 8,500 average Boe per day for the first quarter. This production was impacted by well shut-ins that allowed completion of adjacent and in-fill wells, as well as service delays experienced by many our operating partners which deferred turn-on dates. At this time we continue to remain confident in our guidance of approximately 4 million barrels of oil equivalent production for the calendar year 2012.

We. reported net income of $8.8 million for the first quarter. However, this amount included a $9.4 million pre-tax unrealized noncash loss on mark-to-market derivative instruments. Excluding the unrealized mark to market loss on derivatives net of tax we reported net income of $14.4 million, or $0.23 per diluted share. As Mike mentioned, our earnings release includes a reconciliation of these non-GAAP numbers, net income, and net income per share.

As of March 31st, 2012 we controlled approximately 173,000 net acres in the Williston Basin, Bakken, and Three Forks plays. During the first quarter of 2012, we acquired lease sold interests covering an aggregate of approximately 10,278 net mineral acres in our key prospect areas, for an average cost of $1,672 per acre, and aggregate cost of $17.2 million. As of March 31st, 2012 we controlled approximately 90,700 net acres, that were either developed, held by production or operations,which represented approximately 52% of our current total Bakken and Three Forks acreage position.

During the first quarter of 2012 we had leases expire covering approximately 4,300 net acres. We currently have approximately 1,900 developed net acres that are prospective for the Bakken and Three Forks that could potentially expire in the remainder of 2012. This number represents approximately 1% of our overall Williston Basin position. As Mike mentioned earlier, 13.9 net wells were completed and placed onto production in the first quarter. Bringing our total producing net well count to 71.8 of March 31st, 2012. We had an additional 16.5 net wells drilling or waiting completion at the end of the quarter.

The average AFE costs for wells drilling or waiting completion at quarter end was $8.3 million. We will be using this number as our average going forward. During the quarter we spent approximately $125 million on the drilling and completion of wells. Based on our current understanding of our operating partners' development plans for 2012, we expect total capital expenditures for the year for the drilling and completion of wells to be approximately $360 million. This estimate represents an increase from previously announced $325 million drilling budget, and is primarily due to more pad drilling and a higher concentration of longer lateral wells, which we believe provide more favorable production economics, and cost savings on future wells.

In addition to drilling capital expenditures we spent approximately $17.2 million on acreage acquisitions in the first quarter. And incurred an additional $8.2 million of development costs in return for acreage interests, earned through farming arrangements. At this point I am 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 would like to first comment on another Company press release made this morning. As you may have seen this mornings we announced our intention to offer $250 million of eight-year unsecured senior notes in a private placement to eligible purchasers. We plan to use the net proceeds we receive to repay borrowings outstanding under our revolving credit facility, fund capital expenditures, and for other general corporate purse. Due to Security law restrictions, we are not able to comment on this topic further at this time.

Moving on to the financial results, strong cash flow growth was a key first quarter highlight. We reported adjusted EBITDA for the first quarter of 2012, a 141% increase over adjusted EBITDA for the first quarter of 2011. Adjusted EBITDA reached $44.8 million in the first quarter of 2012, which increased 15% when compared to the fourth quarter of 2011. Adjusted EBITDA growth in the first quarter of 2012 was fueled by 21% quarter-over-quarter production growth.

For the first quarter of 2012, we recorded net income of $8.8 million, and income per diluted share reached $0.14. During the first quarter of 2012, oil and gas sales including hedging settlements reached $59.8 million, which was a 151% increase over the comparable amount in the first quarter of 2011, and $9.2 million, or 18.4% on a sequential quarter-over-quarter basis.

Comparing the first quarter of 2012 versus the first quarter of 2011 oil and gas sales growth was driven by 117% increase in production, as well as a 16% rise in average realized price per Boe. Higher average realized prices per Boe during the quarter were partially offset by higher oil differentials, oil differentials during the first quarter averaged a little over $14 per barrel, as compared to $5 per barrel in the fourth quarter of 2012. The spike in the oil differentials affected realized pricing for March, but differentials have since improved.

Total production expenses per barrel of oil equivalent were $8.40 in the first quarter of 2012, as compared to $5.65 in the fourth quarter of 2011. Production expenses on a Boe basis were higher in the first quarter of 2012 compared to the first quarter of 2011, due to higher water disposal costs, as well as increased number of workovers during the first quarter of 2012. Total production expenses per barrel of oil equivalent were $7.84 in the first quarter of 2012 as compared to $7.34 for the first quarter of 2011.

Production taxes on a barrel of oil equivalent trended higher in the first quarter of 2012 as compared to the first quarter of 2011 due to a change in the mix of wells that qualified for reduced rates. As a percentage of oil and gas sales production taxes were 9.3%, during the first quarter of 2012 as compared to 9.7% during the first quarter of 2011. Some of these tax reductions are temporary until a certain period of time expires or a volumetric threshold is achieved, at which point the return to North Dakota's 11.5% rate.

G&A expenses were $4.1 million(Sic-see press release) for the first quarter of 2012 compared to $3.3 million for the first quarter of 2011. This increase was primarily due to higher compensation and benefits expense. As a result of our growth, we have increased our staffing in the legal, finance, and land departments. Our personnel costs continue to increase as we invest in our technical teams and other staffing to support our growth.

Depletion expense per Boe increased modestly during the first quarter of 2012, and reached $23.62,compared to $23.23 per Boe in the fourth quarter of 2011. The increase in depletion expense per Boe is due to additional crude properties being transferred into the proven property pool, and their cost becoming subject to deletion, our effective tax rate in the fourth quarter of 2012 was unchanged from the fourth quarter2011 rate which remained at 39.8%.

We continue to layer in hedges opportunistically as the market warrants, so we can maintain our growth momentum and our capital expenditure program. For the remainder of 2012 we currently have hedged approximately 76,000 barrels under swap agreements, at an average price of $94, and approximately 1.1 million additional barrels under costless collars, with an average 2012 price of $91 per barrel, at an average 2012 ceiling price of $107 per barrel. For 2013 we have currently hedged 60,000 barrels under swap arrangements at a weighted average price of $102 per barrel, and approximately 2 million additional barrels, using costless collars at an average 2013 floor price of $90 per barrel, at an average 2013 ceiling price of $105 per barrel. For the first half of 2014, we have hedged approximately 240,000 barrels under swap agreements at weighted average price of $100 per barrel. We will continue to look for opportunities to increase these hedging levels, but we feel we have established some attractive base levels. At this point I would like to turn the call back to the operator to begin the Q&A session.

Thank you. (Operator Instructions). And we will go to Neal Dingmann with SunTrust.

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

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

Okay. And then maybe just two others quick, just one you mentioned the differentials. Wondering how those are looking currently, and then maybe lastly just sort of an idea on the tax rate you see going forward?

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

And the tax rate going forward.

I didn't hear what he said.

The tax rate going forward.

39.8% that is what I would use.

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

Actually I think they are going to trend probably with our Indian reservation probably closer to about 10%. We have got a nice slug in there now, and I think we will probably be closer to 10% once some of the others go off. Probably not as high as 11.5%.

Neal, does that answer your question?

It does. Thanks for that guys. Solid quarter.

Great. Thanks a lot.

We will go next to Scott Hanold with RBC Capital Markets.

Morning.

Morning, Scott.

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

Thanks, Scott. I think one of the issues that we have seen obviously throughout the entire play, well costs have gone up to a degree over the past year. Our mix of 1280s has gone up, as we even EOG and Slawson who we have been participating with for the last five years or so, have started to move more to 1280s than 640s. So our mix has gone up quite a bit from 640 to 1280. So that is affecting it but we also expect to see a significant change in economics, especially as these pad wells are being drilled. We expect that to affect our well costs going forward, but right now we think that the 8.3 number, which is just an average of our current AFE costs for the wells, the well proposals that we have received, we expect that to be fairly static for a while, and then we are obviously hopeful on service costs, but that remains to be seen.

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

Thanks, Scott. So I will break that into the three questions. First of all, the acreage that we acquired in the first quarter of 2012 was scattered thought North Dakota as you would imagine for the most part. One acquisition that we made was in Richland County, Montana that we acquired jointly with our partner, Slawson Exploration, who we are in two separate areas of mutual interest with in Richland County. One is Big Sky and one is Lambert. Together we acquired a block of acreage from a private seller that supplemented both of those areas of mutual interest. So Northern and Slawson took that opportunity.

That was one of the reasons that we brought our costs down per acre in the first quarter. Just to give you a little color though going forward. In April we have acquired approximately 2,600 acres at just over $2,000 an acre so the business model of acquiring these small strategic minority non-operated interests continues. From time to time we may find some slightly larger packages, but the one change in the first quarter was that Northern and Slawson joint acquisition.

Then the second is as you could imagine several of the operators are divesting some of their non-op packages. That hasn't affected us to date. We will continue to monitor that, but we continue to see fairly robust activity as it relates to acreage opportunities in bound here at Northern, and again, most of it is primarily permitted acreage that we are acquiring. And then we have never participated in any tribal mineral acquisitions. However, some of our acreage in southern Montrail falls within the ancient boundary of the three affiliated tribes' reservation. That actually is a net benefit to the operators, primarily Slawson and EOG and Northern as they are one of the their, if not the largest partners in southern Montrail, so those are fee minerals that we own, but the surface happens to be part of the old, the ancient boundary of the reservation giving us a really attractive tax holiday. So that is what Tom was referring to.

Okay. Okay. That clears it up. Thanks. Good explanation. And one more if I could. We all kind of talk about where current production is running right now?

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

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

Alright, I appreciate that. Thanks, guys.

Thanks, Scott.

We will go next to Marcus Talbert with Canaccord.

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

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

Okay. Great. Appreciate that. And maybe, Mike, you talked about the two AMI areas with Slawson. Could you offer any maybe incremental color into sort of his pace of development in Richland, or how many rigs is he running in that area right now?

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

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

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

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

Yes. The answer is yes.

Okay.

We would expect to probably request a special redetermination.

Okay. Appreciate it, guys.

Given the size of the increase in our reserve base.

Thank you.

We will go next to Marshall Carver with Capital One Southcoast.

Yes. Good morning, most of my questions were answered already, but I did have a question. Could you give a little extra color on the non-recurring farming arrangements for the first quarter?

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

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

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

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

Okay. Great. Thank you.

Thank you, Marshall.

Next we will go to Chad Mabry with KLR Group.

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

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

Correct. Great. That is it for me.

Thank you.

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

Hey. Good morning, guys.

Morning, Phil.

You hit most of the detailed stuff. I was wondering if I could ask kind of two bigger picture questions. This Clearbrook going positive kind of took everybody by surprise. I would be interested in your thoughts on why that happened, and then secondary, we are starting to see some news on South Dakota, and wondering if you guys are looking down a there and what you think about the geology down there?

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

Have you guys done any geological work?

No, we have not.

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

No. Phil, I mean this is Ryan. Our model would be we would be a long ways from getting into South Dakota. We would need to see development and activity out there. As you know, we always follow in the path of development after we have got good data.

Yes. I figured that, I just didn't know if you guys had looked at any of the geology, and is it for real or is it kind of people jumping on the next great band wagon, but appreciate the color and good job on the quarter.

Thanks, Phil.

Thanks, Phil.

Our final question Joel Musante with C.K. Cooper and Company.

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

Hey Joel,this is Ryan, standard covenants in the notes will make an MLP transaction still permitable, especially because it is inherently de-leveraging, and so we remain optimistic, and believe that the MLP opportunity is a very attractive one for our set of assets, and the offering of the notes doesn't affect our plans on the MLP, it just simply enhances our liquidity in and terms it out.

Okay. Alright. And then just one more. On the gas price it came up, it came out a bit higher than what I had expected, so is there any trend we should note there?

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

Okay. Well, that is all I had. Thanks a lot.

Thanks, Joel.

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

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

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