Northern Oil and Gas Inc (NOG) 2013 Q1 法說會逐字稿

Good day and welcome to the Northern Oil and Gas first quarter 2013 earnings release conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Michael Reger. Please go ahead, sir.

Thank you, Jessica. Good morning, ladies and gentlemen. This is Mike. We are happy to welcome you to the first quarter 2013 earnings conference call for Northern Oil and Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from the first quarter.

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, 2013 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. 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 last night.

As I mentioned in the earnings release last night, we are pleased to have added approximately 130 gross, 10 net, wells to production in the first quarter despite typical first quarter weather challenges. The level of activity in the basin remains strong with 190 rigs drilling in North Dakota alone. As of the end of the quarter, Northern was participating in an additional 152 gross, 12.2 net, wells that were either drilling, awaiting completion or completing. Most notably, approximately 50% of our net wells that were drilling, awaiting completion or completing at the end of the quarter were in Mountrail County. In particular, Slawson Exploration has been operating three rigs on the peninsula in southern Mountrail since the beginning of the year and EOG has been actively down spacing the partial field, both of which is where Northern has incurred the largest step changes in production. Another highlight from an operational standpoint is the average number of wells that are drilled per rig per month continues to increase, as pad drilling efficiencies gain momentum. Pad drilling is playing a significant role in rig efficiency and for Northern, approximately two thirds of our gross wells that are currently drilling or awaiting completion are on a multi-well pad. As a result, we are seeing a steady decline in drilling and completion costs and we continue to expect our average well cost to land between $8.4 million and $8.8 million for the year.

We are very optimistic about the remainder of the year, especially the second half of 2013, as we expect a greater trajectory of production growth from pad drilling and vast completions without the effect of winter weather and road restrictions. Road weight restrictions are typical of April and May, as roadways are most vulnerable to damage by heavy trucks during the spring thaw. We don't know how road restrictions will impact activity, if at all, but we are cautiously optimistic about sequential production growth in the second quarter. Also, acreage acquisitions continue to be strong, as we were able to add 6,000 acres at just over $1,000 per acre, most of which were in permitted drilling units. Our ability to continue to acquire acreage at a steady clip and develop our extensive drilling inventory, all while improving our liquidity position is a testament to the quality of our asset base and our business.

Overall 2013 is shaping up to be a good year. We remain disciplined with our effective and efficient non-op strategy and the Williston Basin is maturing nicely, with ample service availability, infrastructure build-out and takeaway capacity. We are pleased to have a large core position in this premier oil resource play. With that, I am going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some financial Highlights.

Thanks, Mike. Northern's first quarter 2013 production reached 1 million barrels of oil equivalent. That is a 29% increase over the first quarter of 2012. On a sequential quarter-over-quarter basis, average production was up 2%, reaching 11,115 BOE per day for this quarter. During the quarter we added 128 gross or 9.6 net wells to production, bringing our total producing wells to 1,355 gross and 115.8 net.

We reported GAAP net income of $9 million or $0.14 per diluted share for the first quarter of 2013. Excluding the effects of a non-cash loss on derivative instruments, we reported adjusted net income of $18.1 million or $0.29 per diluted share. Earnings release includes a reconciliation of the non-GAAP numbers to our reported net income and net income per share amounts. We continue to see strong cash flow and high operating margins in the first quarter. We reported adjusted EBITDA of $63.5 million for the first quarter, which was a 42% increase compared to the first quarter of 2012. In the first quarter of 2013, oil, natural gas and NGL sales increased 28%, as compared to the first quarter of 2012. That was driven primarily by a 29% increase in production and partially aided by a 7% increase in realized price on a BOE basis after taking into account the effective settled derivatives.

Our average realized price, including all cash derivative settlements, during the first quarter was $82.78 per BOE, which compares to $77.16 per BOE in the first quarter of 2012. The higher average realized price in the first quarter of 2013 as compared to the same period in 2012 was driven by lower oil differential, which more than offset the lower average NYMEX pricing during the quarter. Our oil differential during the first quarter of 2013 was $3.62 per barrel as compared to $14.09 per barrel in the first quarter of 2012. During the first quarter of 2013 we had non-cash mark to market derivative losses of $14.9 million compared to a $9.4 million loss in the first quarter of 2012.

Production expenses were $8.6 million for the first quarter of 2013, which compares to $6.5 million in the first quarter of 2012. On a per unit basis, the average production expenses increased 3% to $8.64 per BOE versus the first quarter of 2012, but declined 12% when compared to the fourth quarter of 2012. The largest cost driver in our Williston Basin operation continues to be the disposal of water. The year-over-year increase on a per unit basis is primarily due to increased cost associated with water hauling disposal and servicing expenses. Our production taxes totaled $7.8 million in the first quarter of 2013, which compares to $6.1 million in the first quarter of 2012. Average production tax rates were 9.4% in this quarter compared to 9.3% in the first quarter of 2012 and 9.5% in the fourth quarter of 2012.

General and administrative expense was $4 million in the first quarter of 2013 compared to $4.7 million for the first quarter of 2012. General and administrative expenses per BOE during the first quarter of 2013 were $3.99 per BOE, which was down 34% compared to the prior quarter of last year. The decrease in aggregate dollars between the first quarter of 2013 and the first quarter of 2012 was primarily due to lower compensation costs. DD&A was $26.8 million in the first quarter of 2013. That compares to $18.4 million in the first quarter of 2012. Depletion expense, which is the largest component of the DD&A, averaged $26.66 per BOE in the first quarter of 2013. That compares to $23.62 per BOE in the first quarter of 2012. It was flat when you compare it to the fourth quarter of 2012. Depletion expenses rose on a year-over-year basis due to increased estimates of future development costs and increased production expense estimates. The provision for income taxes was $5.6 million in the first quarter of 2013 compared to $5.8 million in the comparable quarter last year. The effective tax rate in 2013 was 38.5% as compared to a 39.8% rate in last year's comparable quarter. The effective tax rate was different from the federal tax rate of 35%, primarily due to state income taxes.

During the first quarter of 2013, capital spending totaled approximately $100.5 million. This capital spending is broken down as follows -- we spent approximately $88.7 million on drilling and completion costs; incurred $7.4 million on acreage and related activities; and $4.4 million on the other capital expenditure activities, including capitalized workover costs. As of March 31, 2013 we were participating in 152 gross and 12.2 net wells that were actively being drilled or awaiting completion. At March 31, 2013, Northern controlled approximately 181,823 net acres targeting the Williston Basin, Bakken and Three Forks, as Mike mentioned earlier. During the quarter, Northern acquired leasehold interests covering approximately 6,000 net acres in the Williston Basin for an average cost of $1,087 per net acre. As of March 31, 2013 approximately 63% of Northern's total acreage position and approximately 72% of Northern's North Dakota acreage was developed, held by production, held by operations or permitted.

We continue to layer in hedges opportunistically as the market warrants to increase predictability of our cash flow and to help maintain a strong financial position. Currently we have hedged approximately 9,400 barrels of oil per day for the remainder of 2013. Approximately two thirds of the 2013 hedging is done with costless collars that have an average floor price of $90 and an average ceiling price of $104 per barrel. In 2014 we have hedged approximately 10,600 barrels of oil per day. The majority of the 2014 hedges are crude oil swaps at an average price of $90.50 per barrel.

Northern ended the quarter with $139 million drawn on its revolving credit facility, which has a borrowing capacity of $400 million. Northern ended the quarter with $8.5 million in cash resulting in liquidity of approximately $270 million. At this time I am going to turn it back over to the operator for Q&A. Jessica, if you could please give the instructions for Q&A.

(Operator Instructions).

Cory Markling with RBC Capital Markets.

Weather was a bit rough in early second quarter. Can you describe the impact that had on activity that you are aware of?

So, in January -- this is Mike. Thanks for the question. In January, the weather was pretty rough from a snow and road condition standpoint. Our guidance is to add 44 net wells over the course of a year and we added 9.6 in the first quarter. In January we added just under two net wells and then, as we moved into February, well, February was normal, somewhat normal weather for North Dakota, we added approximately or just over four net wells in February.

And then we added -- in March, as it started to get -- weather was not as good as February, but better than January, we added about 3.6 net wells. So, just to give you some color on how it works, when the weather is rough in a particular month, it's all about net wells completed and then oil moving around. So, that was the main driver of activity from a weather standpoint.

How many wells in the peninsula are completed right now, and can you give us a sense of the timing of that coming on?

So, also as I mentioned in the press release and in this conference call, road restrictions are in effect -- that came into effect in the first week or two of April and will extend through the middle to end of May as the frost comes up and the -- as the roads thaw.

So, we expect most of the wells that Slawson and EOG are developing, there particularly on the peninsula and in southern Montreal, around the lake in particular. We expect those to be completed in late May to the end of June. So, should be a fairly robust completion schedule for us during that period once road restrictions are lifted. Just easier to move equipment around and fluid around when you can have full loads.

One last quick question, looks like about 4,000 net acres dropped off this quarter. Where was that and how much non-core acreage is set to expire this year?

Yes, thanks. I have the sheet here in front of you -- in front of me. I will walk through exactly how this played out and how it plays out for the rest of the year based on the data we have right now. We had expirations of about 3300 acres. There was no particular county. We had the highest number of expirations with just under 1,000 acres in Richland County, Montana. Then everything else, the usual counties, McKenzie, Williams, Montrail, Dunn, et cetera, all those were right around 500 or under 500 acres. So, no big cut from any particular county. As we go through the end of the year, the acreage that could potentially expire is about 15,800 that we can see based on the data we have now. That doesn't mean that we are not going to get to that acreage, because we may get to most of it or all of it.

The largest of that, about 50% of the potential explorations by county, is in Richland County, Montana. So, we don't lose a lot of our core acreage this year. We don't expect to lose a material amount of core acreage this year. It would just be out in Richland County. And we are very confident about Richland County as Slawson has been very actively drilling on a unit by unit basis in our Big Sky AMI, where Northern and Slawson own the vast majority of each section out in that particular area of mutual interest.

So, Richland County makes up about 50% of our projected explorations, but with Slawson active in Big Sky we don't expect to lose a material amount of acreage out there either. The remainder of the counties, the better counties for us, Montrail, McKenzie, Williams, et cetera, all of those we could potentially lose 2,000 or under 2,000 for the remainder of the year and will likely get to that as the rig count's now back to 190 and the field is quite active. Just wanted to give you that color since I had the spread sheet in front of me.

We will go next to Ryan Oatman with SunTrust.

Historically, I believe Northern hasn't really participated in these public sale processes, but can you see that changing in the future at all?

We review every package that is circling about if it has interest to us from a strategic standpoint. Everything from the small stuff, just 200 acres, up to the EOG package that was being marketed last year, which was fairly sizable. We look at all of these packages, we analyze all these packages and in some cases we bid on these packages. I'm not going to comment on any one in particular. However, typically Northern has acquired its acreage on the ground, in the neighborhood of kind of 40 to -- 40 acres to 160 acres in a typical transaction. We are typically buying the stuff -- the way our franchise is designed isn't to grow the Company with big material retail buys. We have built the Company, basically, 100 acres at a time, as you know. It doesn't mean we don't bid on these things and it does not mean we are not interested in them, it is just Northern doesn't typically go into the market and pay retail, because we have a substantial position now that we have a very low cost basis on from an acreage standpoint.

And then shifting on you just a bit here, how should we expect operating expense to trend on a per unit basis? It seems like several operators are working on water infrastructure that might reduce the water handling costs. So, just curious on your thoughts there?

This is Tom. I think you are going to see them trend, probably, to around the 850 range. I think they were a little bit higher in the first quarter. Mike commented a little bit on the weather. The weather increased field logistics and things like that. Historically, they are a little bit higher in the first quarter of the year. At least right now, with the visibility that we have, we think around 850 per BOE.

Thanks. That's it for me, guys.

Thanks a lot, Ryan.

(Operator Instructions)

We will go next to Jason Wangler with Wunderlich Securities.

Mike, you talked a bit about the pad drilling and batch completions. Do you see really the situation that -- obviously, first quarter and even fourth quarter with the weather and everything starting to ramp that up, are you seeing more and more where you are getting a runway of a lot of the pads and batches coming on to production here second and third quarter maybe into the peninsula and even other areas?

Thanks. I think, Jason, to answer your question, we have said this several times on other conference calls, is that Northern, with its sheer volume of gross wells that we are participating in and just sheer volumes of pad drilling and batch completion units where Northern has interest, there is no particular wave that is coming. I would say that given weather, we expect to have a fairly decent wave of production coming on from batch completions once road restrictions are lifted, in particular, as I mentioned, in southern Montrail County with EOG and Slawson and Slawson on the peninsula. I don't see any material lumpy production coming on other than a fairly consistent or I would say a better trajectory of production growth as pad drilling starts to really shine. Most of the units that were on, as I mentioned, are on -- are being drilled on pads with very few being single well pads. You just don't see a lot of that any more. Most of these wells are on multi-well pads and typically four or more. It is going to be fairly smooth for us.

If we were a one rig operator drilling a pad and that was really our only exposure to the Williston, obviously that would be fairly lumpy. But for Northern, we expect this summer to be fairly robust with a lot of batch completions in a lot of areas with a lot of different operators. It is going to be -- it should be robust, but it is not in one particular time frame, not in any particular month or quarter. The second and third quarter just should be quite good.

Just to rephrase it maybe or just to make sure I am understanding it. It is mostly just the weather improving that will really help you get, obviously, the efficiencies of getting a lot more of these wells coming on, like you walked through January, February and March, as we get out of April and May to see better operations overall in the basin and that will help with that production growth as you get to your guidance?

It's so much more efficient to operate in the Williston during the summer months. It's not only easier to move equipment around but it is cheaper. We are optimistic that the momentum will really pick up here at the end of the second quarter and then it should be, I can't think of any other word than robust, in the third and fourth quarter.

My last one, just quickly on the well costs, I think you said $8.2 million to $8.4 million. Is that what you see now or is that what you see for the year? If so, what are you seeing now?

Our guidance for the year is $8.4 million to $8.8 million. We expect to land on an average in that range fairly comfortably. Our hope is and we are, again, cautiously optimistic that we will be ending the year in the neighborhood of about $8 million per well.

That really is driven by, not only what we are seeing in the field with the sheer number of wells we are participating in and the wide range of operators that we are participating with, but their guidances, our operator, our operating partners guidance has been in that neighborhood as well where we expect the costs to trend towards $8 million toward the end of the year, but we feel very comfortable with $8.4 million to $8.8 million for the year and that's where our CapEx guidance has led us.

That's helpful. I will turn it back. Thank you.

(Operator Instructions)

We will go to Jared Lewis with Northland Securities.

Quick question, you mentioned that 50% of the wells waiting for completion are in the peninsula or in EOG's Parshall. Given the historic strength of those wells, how do you see that kind of affecting production, if it does, going forward?

Well, we would just say that the trajectory of production growth given the nature of where the wells are located in addition to the momentum of pad drilling taking hold and really starting to show its benefits toward the end of the year, we just think that the quality of the production coming from Montrail County, which has typically been where Northern has had its step changes in production over the years, we believe we are going to see a lot of that in the third quarter and the fourth quarter.

So, I would just say that the material change, if any, will just be a different trajectory of production growth as we see these benefits here in the second half, in particular, of 2013.

How quickly the pad drilling and the efficiencies, we are hearing it from other operators, might be a little early, but do you see any change in how many net wells you think you might complete for the year?

We are still sticking with 44. I think the fact that we are at just under 10 for the first quarter and if you assumed a straight line, it is 11 a quarter. As we get into the three best quarters from an efficiency standpoint, yes, we are very comfortable at 44. We are not going to be making any changes to guidance at this point. You can assume that as pad drilling takes hold, the spud to spud cycle time will go down. So, where it used to be rig on to rig on, 30 days, it can be under 20 days to move one rig from one well to another well after total depth on the same pad.

That efficiency might increase on a percentage somewhere in the double digits. Might be a 10% increase in sort of rig on to rig off timeframe, but with pad drilling you can see it's easier to move the equipment around. So, we are going to stick with 44 for now. We will be able to update you later in the year as we start to see what pad drilling really does mean for us and what it means for the field.

Excellent. Very helpful. Thanks.

Thank you.

And that does conclude today's question and answer session. I will turn the conference back over to Mr. Reger for any final or closing remarks.

Thanks, Jessica. Thank you, everyone, for your participation in this call today and your interest in Northern. We look forward to seeing you all soon and sharing the results with you next quarter. Have a great day.

This does conclude today's conference. Thank you for your participation.