Northern Oil and Gas Inc (NOG) 2012 Q3 法說會逐字稿

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

Good morning. My name is Michael Reger. I'm the Chairman and Chief Executive Officer of Northern Oil and Gas. Also with me today is Tom Stoelk, our Chief Financial Officer. We are happy to welcome you to the 2012 third 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, and that involves certain risks and uncertainties. We encourage you to review the various risk factors relating to our business, which we most recently updated in our form 10-Q that we 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 these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we put out this morning.

The third quarter of 2012 was another record quarter for us in terms of production, oil and gas sales, and adjusted EBITDA. Northern Oil's third quarter production was up 96% compared to the same period last year. Our total production for the quarter was 1.038 million barrels of oil equivalent, or BOE, and our average daily production for the quarter was approximately 11,300 BOE. During the quarter, we added 149 gross, 10.9 net wells to our production base. As drilling and completion activity remains strong in North Dakota and Montana. Through the first nine months of 2012 the total number of wells completed and added to our production base was 440 gross or 40.6 net wells. That raised our total producing wells as of the end of the third quarter to 1104 gross wells or 98.5 net wells. In addition we have participated in approximately 32.7 net wells that were spud during the first 9 months of 2012, which leads us on track to spud approximately 44 net wells for the year, as previously estimated.

We have also continued to grow our acreage position which, as of September 30, 2012, stands at approximately 184,000 net acres in the Williston Basin. During the third quarter of 2012, we acquired leasehold interests covering 3,815 net acres for an average cost of just over $2,000 per acre. We have approximately 114,000 net acres either developed, held by production, held by operations, or permitted in the Williston Basin. That represents 62% of our total acreage position. Also, 72% of our total North Dakota acreage position was developed, held by production, held by operations or permitted at the end of the third quarter. And we expect very limited acreage expirations throughout the remainder of 2012.

At this point, I am going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some financial highlights from the third quarter.

Thanks, Mike. This morning, we reported GAAP net income of $300,000 for the third quarter. However, this included a $13.4 million unrealized non-cash loss on mark-to-market derivative instruments net of tax. And $3 million of severance charges net of tax connected with the departure of our former president. Excluding these items, we reported adjusted net income of $16.7 million, or $0.27 per diluted share. As Mike mentioned, our earnings release includes a reconciliation of the non-GAAP numbers to net income, and net income per share.

We continue to see strong cash flow growth in the third quarter. We reported adjusted EBITDA of $63.1 million, for the third quarter. That's a 98% year-over-year increase compared to the third quarter of 2011. And it is a 19% sequential increase when compared to the second quarter of this year. Adjusted EBITDA growth in the third quarter of 2012, as compared to the second quarter of 2012 was fueled by a combination of increased production levels, and higher realized prices per BOE.

During the third quarter of 2012, oil and gas sales, including derivative settlements, reached $82.4 million, that represents a 97% year-over-year increase, compared to the third quarter of 2011. And a $13 million, or 19% higher on the sequential quarter over quarter basis. Comparing the third quarter of 2012, versus the third quarter of 2011, oil and gas sales growth was driven by a 96% increase in production. Realized pricing for the third quarter of 2012, including a $1.7 million gain on settled derivatives was $79.38 per BOE. That's up just $0.16 from a year ago. Compared to last quarter, realized pricing increased $6.19 per BOE, or 8%. In addition to realized hedging gains during the quarter, the sequential quarter improvement of realized pricing was driven by a drop in Bakken crude oil differentials. Comparing the second quarter of 2012 to the third quarter of 2012, the average oil differentials declined by $3.54, an average of $10.18 per barrel of oil equivalent. We remain highly oil weighted with 92% of oil production being crude oil during the third quarter.

For the third quarter of 2012, we had an unrealized non-cash loss in derivative instruments of $22.3 million. That compares to $27.1 million unrealized non-cash gain in the third quarter of 2011. And a $49.8 million unrealized non-cash gain in the second quarter of 2012. Total production expenses per barrel of oil equivalent were $8.42 in the third quarter of 2012, as compared to $7.40 in the third quarter 2011, and $7.70 in the second quarter of 2012. On a per unit basis, production expenses were higher in the third quarter of 2012, compared to both the third quarter of '11 and the second quarter of 2012, primarily due to a rise in production-enhancing workover activities as well as higher salt water disposal expenses. Total production taxes per BOE were $7.80 in the third quarter of 2012, as compared to $8.07 in the third quarter of 2011 and $7.03 in the second quarter of 2012. As a percentage of oil and gas sales, production taxes were 10% during the third quarter of 2012, as compared to 9.8% in the third quarter of last year, and 9.5% during the second quarter of 2012.

The third quarter of 2012's average production tax rate was slightly higher than the third quarter of 2011 and the second quarter of 2012, due to greater levels of production that didn't qualify for reduced rates or tax exemptions, during 2012. Some of these tax exemptions are temporary, or for a certain period of time, or until we reach a volumetric threshold, at which point they return to North Dakota's standard 11.5% rate. General and administrative expenses were $9.5 million for the third quarter of 2012, which was up from $4.1 million in the third quarter of 2011, and $4.4 million from last quarter. The vast majority of the year-over-year increase is due to a $4.9 million severance charge, in connection with a departure of our former President, of which $4.3 million is in the form of non-cash share-based compensation expense. Generally Accepted Accounting Principles required us to recognize the entire cost of the separation agreement during the third quarter of 2012. The remaining portion of the year-over-year increase is primarily the result of increased staffing throughout the company, to support our growth.

Our depletion expense per BOE during the third quarter of 2012 was $26.93. That's the same rate as it was last quarter, but an increase over the 2011 third quarter rate of $20.34 per BOE. The year-over-year increase in depletion expense per BOE is due to an increase in our future development and operating cost estimates, as well as an increase in the depletive base as additional unproved properties are proved up and become subject to depletion. Interest expense net of capitalized interest was $5.2 million for the third quarter of 2012, which compares to $200,000 in the third quarter of 2011. The increase in interest expense is due to higher level of borrowings in 2012. Including $300 million of 8% senior Notes we issued in May of 2012.

During the third quarter, we expanded our borrowing base under our revolving credit facility to $350 million, of which $68 million was outstanding at quarter end. That left $282 million of borrowing capacity under this facility, together with an additional $8.2 million of cash on hand at the end of the second quarter, and this should provide us with the necessary liquidity to fund our planned capital expenditures. The ratio of our trailing four quarters EBITDA over our total debt was 1.9 times at September 30, 2012. During the third quarter of 2012, we spent approximately $119 million on oil and gas expenditures. Approximately $109 million of these related to drilling and completion expenditures. We continue to layer in hedges opportunistically as the market warrants to increase the predictability of our cash flow and help maintain a strong financial position. For the fourth quarter of 2012, we currently have hedged 563,000 barrels under swap agreements at a weighted average price of $93.66, and approximately 384,000 additional barrels under costless collars with an average floor of $91.20, an average ceiling price of $105.93 per barrel.

For 2013, we currently have hedged 960,000 barrels under swap agreements at a weighted average price of $91.86 and approximately 2.2 million additional barrels under costless collars with an average 2003 (sic) floor price of $90.01 per barrel and an average 2013 ceiling price of $104.17 per barrel. For 2014, we've hedged approximately 1.7 million barrels under swap agreements at a weighted average price of $91.92 per barrel, and approximately 240,000 additional barrels using costless collars with an average 2014 floor price of $90.00 per barrel and an average 2014 ceiling price of $99.05 per barrel. We will continue to look for opportunities to increase those hedging levels, but we feel we have established some attractive base levels at this point.

At this point I would like to turn the call back to Mike to discuss some recent trends in the Williston Basin.

Thanks, Tom. We're seeing some nice trends in the field today, as a number of our operating partners have mentioned drilling and completion costs are expected to trend lower throughout the fourth quarter and into 2013, primarily due to service availability and increased efficiencies. These improvements have shortened spud to sales times as well. Also due to additional infrastructure in the Williston Basin, take-away capacity remains very healthy right now and differentials have tightened since earlier in the year. All of this bodes extremely well for our non-operated business model. Infill drilling and down spacing activity on our leasehold positions has been increasing and so far, the results have been promising. In recent press releases and conference calls, many of our operating partners have stated their intentions to dedicate a significant portion of their rigs to multi-well pad drilling and begin a robust infill development program.

At this point, I would like to turn the call back to the operator to begin the question-and-answer session and provide more color on our quarter.

(Operator Instructions)

Ryan Oatman with SunTrust.

Hi, guys. Good morning.

Good morning, Ryan.

Given the financial strength and flexibility you guys have, what are your thoughts on taking a working interest higher than that typical 5% to 10% in areas?

Well, I think it comes down to the mix of the operator base that we're targeting. We've been in that, for the last five years or so, we've been in about the 6% to 12% range for average working interest, at given times. It moves throughout that range. We expect that our percentage to increase here, as we move through the end of this year and into 2013. Primarily due to the fact that Slawson Exploration, specifically, is going to move two rigs back into the Southern Montrail Peninsula, we call it, or Loop, our Windsor area, depending on what you want to call it.

And then at the beginning of 2013, he is going to move a third rig into there. That is where our working interest is significantly higher, where we're looking at wells, or looking at average working interest in the 20% range. That will increase our percentage going through 2013, which is really exciting for us. That's the beginning of the infill and down spacing for Slawson in that Southern Montrail County Loop area. As we continue to buy additional working interest, they come in various forms, obviously, but we just target specific areas, specific acreage, specific drilling partners, and it may come in the neighborhood of 5%, it may come in the neighborhood of 20%. But we buy the attractive acreage as we see it and we don't make any specific decisions relative to size.

Okay. That's helpful. It sounds like working interest will kind of increase next year, especially in more efficient areas. Do you see the chance for corporate-wide efficiency to increase next year? And then just thoughts on activity levels, as well. It looks like it has been pretty steady at around 10 or 11 net wells per quarter. Based on this working interest, all of these moving parts, do you see that number moving higher as well? Thanks.

Yes, thanks for that question. And that's what we expect in 2013, for basically the field to remain the same, from a rig count standpoint. Maybe a slight increase in rig count. However, the rigs, as you know, are getting more efficient. And the drilling times and number of days it takes to drill a well, is just decreasing across all of our operator base. And so I think next year, with all things remaining equal, with a similar number of rigs, we expect to drill more net wells. And if you think that we're going to drill a similar number of wells, 44 net wells, or maybe, let's say a 10% increase potentially next year, as efficiencies increase, with the same number of rigs, we also expect to see a subsequent decline in overall drilling and completion costs, by at least 10%. So we think our activity is going to remain very predictable, as we go.

One other thing, if you will indulge me, that I will highlight here, is that the number of net wells that Northern is adding is no longer lumpy. Our drilling and completion list, or if we spud roughly 150 gross, 10 to 12 net each quarter, we're going to be completing a similar number of gross and net wells. So as we go forward, 2013 is going to be far more predictable from a cash flow and CapEx standpoint than 2012, because the spud to sales times have now compressed to less than 90 days. So it is more of a predictable turnover on a quarter-by-quarter basis. The activity we think will remain the same. We think efficiencies may actually increase our net wells throughout 2013, given the same number of rigs, and all things remaining equal. But efficiencies and costs are also going to be on our side as well. So, thanks for that question.

Very helpful. And then just one more, if I may. 2013 guidance, when do you guys plan to communicate that?

We're currently in the process of preparing our 2013 capital spending budget, since it hasn't been presented or approved by our Board, we don't have anything to share really at this time. Once that is completed, then you will see us kind of come out with some guidance. It probably is -- we haven't formalized this, so it's a little tough to kind of give you a date but it will be after the first of the year, I would think.

Sure. Makes sense. Thanks, guys.

Thank you.

JB Juve, RBC Capital Markets.

Good morning, guys.

Good morning, how are you?

I'm good. Thanks. I had a follow up about the previous question, and in particular, with regards to pad drilling you mentioned earlier. And I guess this pattern goes hand in hand with the quantity of acreage that is now HBP. What kind of impact do you see from that pad drilling to your net activity? Does it affect your ability to stake your interest in your wells or does it do anything at all?

What it will do is it could potentially, because of that particular efficiency, and not having to move rigs around the field, we actually think that could be an increase from a net well standpoint, but we also think that we will have a corresponding and more potent cost efficiency benefit to Northern. So we think that could, if they're drilling a Bakken and Three Forks well in the same unit where we have the same obvious corresponding working interest. That could increase our efficiency and it could increase the number of net wells. But we think that if we do add more net wells, in 2013, than we have here in 2012, then we think the corresponding efficiency and cost benefit is going to be better.

The one thing that would potentially have an impact, but I would say very minimal, is that when multi-well pads are utilized, they will likely drill all two, three, four, or more wells on that pad, before they frac all the wells at the same time as well. So because of the number of net wells that we have, that won't necessarily create lumpy production, where it all comes on at one time. But the first, second, and third well on a four-well pad will clearly be awaiting frac while the fourth well is being drilled. And once they're all drilled, then we will frac all those wells. But the smoothing effect of the sheer number of growth in net wells that we are participating in, we don't see that as presenting any lumpiness, if you will, for our production base.

Okay. Thanks. And then another one, if I may. What are you currently seeing in the basin regarding infrastructure, and in particular, gas infrastructure?

We think that in the areas that we're participating in, and if you're familiar with our asset base, we are heavily weighted to the Nesson Anticline and east of the Nesson Anticline. So we've been benefiting from infrastructure that is being developed since 2006, and even earlier than that. I feel as a whole, there's new areas that are being developed by some operators, but most of our acreage as you know is in fairly tight to the core of the play. And so we're benefiting from, maybe infrastructure that is further along in the process. Gas is being hooked up. Our wells are, for the most part, that's not a big issue for us. From time to time, we will have a certain percentage of our gas being flared, but that percentage for us is, we think, good and we will continue to increase. Just like all of our operating partners have indicated as well.

I will add some other color since you mentioned infrastructure. Water gathering, water disposal, that is really going to be the big driver of cost reductions going forward, because water has been an issue, water disposal has been an issue for the entire basin. We think that, the increase in infrastructure there is important. Currently, the crude by rail take-away, my understanding is well over 50% of the take-away in the field right now. That bodes very well for differential. So take-away remains healthy. So that kind of infrastructure has been very beneficial to the play as a whole. And in particular, that additional infrastructure bodes very well for our non-operated model.

Okay. Thank you. Cheers.

Thank you.

Peter Kissel, Howard Weil.

Hi, guys. Good morning. I was wondering if you could please comment on some of the Management changes that have occurred over the last few weeks. I mean, are we looking at more a change in strategy or cost-saving measure? Or really just anything you care to mention on that would certainly be helpful.

Sure, thanks, Pete. You know, we've covered a lot of this in the different press releases, but I will just give you some color here, right from me. As you know, Ryan Gilbertson, co-founded Northern with me, Ryan and I have been essentially paid as co-CEOs since inception, with identical salary, identical bonuses, et cetera. Ryan's primary strengths were the capital markets and as you also know, most of our capital markets activities are now behind us, as we get closer to cash flow positive. The Board and the Management Team, and Ryan for that matter, determined that Northern no longer needed to pay two CEOs. We feel great about our current team. And these decisions position the Company for a very profitable 2013. Given our expected production ramp and the associated hedge profile that goes along with that. So this has been more of a streamlining effort than anything.

Thank you, Mike.

Thanks, Pete.

Marshall Carver, Capital One Southcoast.

Good morning. A couple of questions. It looks like you spent about $110 million on drilling and completions in the quarter. If I take that, divide that by the 11 wells completed and spud, that works out to about $10 million a well. You talked about well costs dropping, should that really impact the fourth quarter? It doesn't look like it hit the third quarter yet. So could you help me with the direction on well costs for 4Q and your thoughts around the full-year budget with the slight outspend in the third quarter?

One thing I wouldn't do, is I wouldn't divide our current quarter spend by the number of wells that we put into production. Because part of that spend is related to the wells that are awaiting completion. And at the end of the quarter, we had a little over 10 wells that were awaiting completion. So that is an apples to oranges sort of comparison, and it is going to skew your statistics, and they're not really going to be representative of what we're seeing. The current costs are starting to come down. They've been slight so far. As a non-operator we're 60 to 90 days behind in the billing cycle from our operators.

Effectively, at the end of the third quarter, we had about $8.7 million average well cost, for the wells, estimates for the wells that are awaiting completion. That is down just slightly. It is down about $100,000. We're starting to see a lot of estimates on our current levels of activity filter in, and those are more in the neighborhood of the 5% to 10% reductions. We're hearing a lot of our operating partners continue to talk 10% or in excess of 10%, and we're starting to see that bleed in, if you will. Our capital budget remains the same at $387 million for drilling costs for 2012 spuds, and about $50 million for acreage through September 30.

We've incurred approximately $225 million of that $387 million of drilling costs related to the wells that we spud in 2012. We think we've got about $162 million to go. But when I say that, one of the things we need to keep in mind, is even we may spud wells in December, we won't receive or pay for those expenditures, so there will be a little bit of lap-over into 2000 -- or into the next year, rather, if you will. So I think the spending level for the fourth quarter, similar, maybe slightly higher. It is going to depend on the pace of activity, holiday shutdowns, possibly a little bit of weather and such. But I wouldn't look for necessarily a really big bump in our fourth quarter CapEx, is my view on it.

Okay. And a question on, more and more of your acreage is getting held by production. And you probably have, with such a good survey of participating in so many wells in the Bakken, would you -- it seems like in the past, you've elected to participate in every well that gets AFE'd to you. Do you plan to change that going forward and being more focused on just what you consider the better areas to be? What are your thoughts on that? Would that happen next year? Would that happen in 2014? Or would that never happen?

This is Mike. I think the question, or the answer to your question is, we will elect to any well that pencils out and when we look at buying acreage, we run the math on the well essentially when we acquire the acreage. This is no longer an exploratory business, if you will. This is predominantly just development, and most of our acreage is exploratory. We would consider non-consenting well if the well costs are abnormally high for a particular operator, relative to a particular area. However, we usually make the decision to participate in these wells when we buy the acreage. So as you well know, the acreage that we have is well delineated within the high quality productive area of the field. Unless there is some unusual cost issue related to a particular well, we intend to participate.

Just maybe a couple of added comments to that. One of your questions, if I understood it, was whether we're non-consenting on wells and actually we're already in the process of doing that. We perform an internal rate of return analysis with respect to the well proposals that come in, look at the areas, look at the offsetting production as part of our analysis. Over the last two quarters, a rough estimate is probably 10 gross wells that were proposed to us, we non-consented on probably about one net. I mean generally. That already happens, if I understood the question right.

Yes, okay. Thank you. Just one last question. So that $119 million spent in the third quarter, that is going to be what shows up in the 10-Q as the cash flow from investing? Am I --

Yes, it is going to show up as the net change between gross oil and gas properties in the 10-Q, which you can reconcile to your cash flow statement, that's correct.

Okay. Thank you.

(Operator Instructions.)

Curtis Trimble, Global Hunter Securities.

Sure, thank you. Good morning, everyone. Just wanted to stress your database here a little bit and see if I can get an idea of the incremental level of detail that you guys collect. You can tell me the number or the percentage of AFEs that are infill drilling, that you've received over the last six weeks, months, and/or the number that are maybe looking at down spacing and/or looking at testing deeper benches of the Three Forks, et cetera?

Yes, thanks for that question. In taking a look at that data, from our entire PDP well base, essentially, less than 20% of the wells, net wells that we have on our PDP base, are infill wells or down paced wells, you know, second wells in each unit. Going forward, that number is going to be obviously increasing. And as we get into 2013, we expect the number of net wells that we add to be under 50% from an infill standpoint, because the field is still in the process of holding acreage. And as we fully develop our acreage position, and as our held by production acreage percentage gets closer and closer to 100%, the wells that will be drilled will be obviously closer and closer to 100% infill. And what is important to note there, is that over the past six or seven years in the Bakken, specifically in North Dakota, as the wells have been drilled, the decisions have been made not just on economics, but have also been made for the purpose of holding acreage and holding blocks of acreage.

But going forward, and really starting now, as we will start to get, in 2013, as we will start to get closer and closer to 100% held by production, and the number of net wells that we add, which are infill wells that we will cross above 50% and so on, the decisions to drill these wells will be made purely on an economics basis. And in addition to that, the design in the Bakken, as you know from all of the operating partners that we participate with, that the optimal design appears to be pad drilling, and so the efficiencies and speed at which we develop this acreage from an infill standpoint will increase and the economics will increase. And it will further magnify the returns that we are seeing in this premiere oil resource play. So, that kind of breaks down the data, as we have it in front of us. But it is pretty simple math.

When we're 100% held by production, it is going to be 100% infill drilling on our acreage positions. Our inventory there is substantial. We believe we've only developed about 10% of our total net wells, if you include infill drilling and just assume three wells to the Bakken and three wells to the Three Forks. We have a lot of inventory and as we get here closer to 100% held by production, it's going to be all burning through that inventory of infill drilling. And those decisions, as I mentioned earlier, will be made primarily on an economic basis.

Sure. And taking that one level lower, can you sort of soft circle a number in terms of cost savings in which you've seen recent AFEs for pad drilling, for infill, vis-a-vis other's wells that are simply looking to HBP?

Sure, I think we get our data essentially realtime from our operating partners. The same way that the market gets their data from the different operators in the Bakken. Several of our operators have mentioned 20% to 30% decreases in total drilling and completion costs. Northern, we have a particularly good set of data, in that when we load a new well proposal, or AFE, into our system, when it becomes permitted and we receive the well proposal and the AFE, and then once it is spud, it moves into, we call it our drilling and completion list, which is wells drilling, completing, or awaiting completion. We know the AFE cost, the AFE estimate on the bottom right-hand corner of that AFE, and we load that into our system. So we can always take a snapshot of the roughly 150 wells that we're participating in at any time. And that number has been decreasing.

Currently, as it sits, it is at $8.7 million, for every well that we have in our list of the roughly 150 or so that we're drilling. That's down from about a month and a half ago, which was $8.8 million. We expect that to go down further. I think the easy answer to your infill drilling standpoint is, it varies throughout our operator set. Pad drilling, based on what our operators are telling us, and what we're seeing, saves somewhere in the neighborhood of, on a per well basis, a per gross well basis, saves anywhere from $300,000 to $500,000. We think that efficiency will continue to show itself, as we start to develop the fields for more of an infill standpoint, once we get all of this acreage held by production here, over the next 18, 24 months. And as it gets more and more efficient, and the well decisions are based on economics, this number is going to go down, we believe.

Very good. I appreciate the time.

Thank you very much.

And that concludes today's Q&A session. I will turn it back to our speakers for any closing remarks.

Thank you all for your interest in Northern Oil and Gas. We look forward to a very successful fourth quarter, and 2013. Thanks a lot. Have a good day.

That concludes today's conference call. We appreciate your participation.