Northern Oil and Gas Management Discusses Q1 2013 Results - Earnings Call Transcript

|
 |  About: Northern Oil & Gas, Inc (NOG)
by: SA Transcripts

Operator

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.

Michael L. Reger

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 or awaiting completion or completing. Most notably, approximately 50% of our net wells that we're drilling or awaiting completion or completing at the end of the quarter were in Mountrail County. In particular, Slawson Exploration has been operating 3 rigs on the Peninsula in Southern Mountrail since the beginning of the year and EOG has been actively down spacing the Parshall 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 2/3 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 bass [ph] completions without the effect of winter weather and road restrictions. Road weight restrictions are typical of April and May as road weights are most vulnerable to damage by heavy trucks during the spring thaw. We don't know how road restrictions will impact the 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 buildout and take away capacity. We are pleased to have a large core position in this premier oil resource play.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss some financial highlights.

Thomas W. Stoelk

Thanks, Mike. Northern's first quarter 2013 production reached 1 million barrels of oil equivalent at 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 noncash 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 these 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 first quarter of 2012. That was driven primarily by a 29% increased production and partially aided by 7% increase in realized price on a Boe basis after taking into account the effect of 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 a 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 on the first quarter of 2012.

During the first quarter of 2013, we had noncash mark-to-market derivative losses of $14.9 million compared to $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 on 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 costs 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 at 9.4% in this quarter compared to 9.3% in the first quarter 2012 and 9.5% in the fourth quarter of 2012.

General administrative expense was $4 million in the first quarter of 2013 compared to $4.7 million for the first quarter of 2012. General administrative expenses per Boe during the first quarter of 2013 was $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 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 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 2/3 of the 2013 hedging is done with costless collars, but have an average floor price of $90 and average ceiling price of $104 per barrel.

In 2014, we have hedged approximately 10,600 barrels of oil per day and 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 $207 million -- $270 million.

At this time, I'd like to turn it back over to the operator for Q&A, Jessica, if you can please give the instructions for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] We'll go first to Cory Markling with RBC Capital Markets.

Cory Markling - RBC Capital Markets, LLC, Research Division

A couple of questions for you guys. Weather was a bit rough in early second quarter. Can you describe the impact that, that has on activity that you're aware of?

Michael L. Reger

So in January -- this is Mike. Thanks for the question. In January, the weather was pretty rough from a snow and a road condition standpoint. Our guidance is to add 44 net wells over the course of the year and we added 9.6 in the first quarter. In January, we added just under 2 net wells and then as we moved into February, where February was normal -- somewhat normal weather for North Dakota, we added approximately -- just up over 4 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 kind of 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.

Cory Markling - RBC Capital Markets, LLC, Research Division

Okay. And then how many wells in the Peninsula are completed right now? And can you give us a sense of the timing of that coming on?

Michael L. Reger

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 2 of April and will extend through the middle to end of May as the frost comes up and the -- as the roads thaw. And so we expect most of the wells that Slawson and EOG are developing, they're particularly on the Peninsula and in Southern Mountrail around the lake in particular, we expect those to be completed in late May, to the end of June. So it 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.

Cory Markling - RBC Capital Markets, LLC, Research Division

And just one last quick question, it 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?

Michael L. Reger

Yes, thanks. I have the sheet here in front of you -- or in front of me, so I'll 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 3,300 acres. It was -- there was no particular county. We had the highest number of expirations with just under 1,000 acres in Richland County, Montana and then everything else, kind of think the usual counties, McKenzie, Williams, Mountrail, Dunn, et cetera, all those are 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're 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 expirations 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're 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 on that particular area of mutual interest. So Richland County makes up about 50% of projected expirations 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, Mountrail, McKenzie, Williams, et cetera, all of those, we can potentially lose sort of 2,000 or under 2,000 for the remainder of the year and we'll likely get to that as the rig counts, now back to 190 in the field, is quite active. So just wanted to give you that color since I have the spreadsheet in front of me.

Operator

We'll go next to Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Michael L. Reger

Well, we review every package that's circulating about, if it has interest to us from a strategic standpoint, everything, from the small stuff, just a couple 100 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 anyone 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. So we're typically buying the stuff the way -- the way our franchise is designed isn't to grow the company with big material retail buys. We've built the company, basically 100 acres at a time, as you know. So it doesn't mean we don't bid on these things and it doesn't mean we're not interested in them. It's just Northern doesn't typically go into the market and pay for retail because we have a substantial position now that we have a very low cost base is on from an acreage standpoint.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Right, absolutely. And then shifting on 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?

Thomas W. Stoelk

This is Tom. I think you're going to see them trend probably through about $8.50 range. I think we're a little bit higher in the first quarter. Mike commented a little bit on the weather. The weather increases some -- increased field logistics and things like that. So historically, they are a little bit higher in the first quarter of the year. But at least right now, with the visibility that we have, we think around $8.50 per Boe.

Operator

[Operator Instructions] We'll go next to Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Mike, you talked a bit about the pad drilling and bass [ph] completions, do you see, really, the situation that obviously first quarter and even fourth quarter, with the weather everything just kind of starting to ramp that up, are you seeing more and more where you're getting the runway of a lot of the pads and batches coming on the production here second and third quarter into the Peninsula and even other areas?

Michael L. Reger

I think, Jason, to answer your question, we've said this several times on other conference calls, is that Northern, with its sheer volume of gross wells that we're participating in and just sheer volumes of pads drilling and bass completion units were Northern has interest, there's no particular wave that's coming. I would say that given weather, we expect to have a fairly decent wave of production coming on from bass [ph] completions once road restrictions are lifted. In particular, as I mentioned, in Southern Mountrail County with EOG and Slawson and Slawson on the Peninsula. I don't see any material lumpy production coming on other than just a fairly consistent -- or I would say, a better trajectory of production growth as pad drilling just starts to really shine. Most of the units that we're on, as I mentioned, are on pad drills, are being drilled on pads with very few being the single well pads. You just don't see a lot of that anymore. Most of these wells are on multi-well pads and typically, 4 or more. So it's going to be fairly smooth for us. If we are a 1-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 the summer to be fairly robust with a lot of bass [ph] completions in a lot of areas with a lot of different operators. So it's going to be -- it should be robust, but it's not in one particular time frame, not in any particular month or quarter. The second and third quarter should be quite good.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. Maybe to just -- that's helpful. Just to rephrase it maybe or just to make sure I understand it. It's mostly just the weather improving that will really help if you'd get -- obviously, the efficiencies are getting a lot more of these wells coming on kind of like you watched in January, February and March, as we get out of April and May, just maybe better operations overall in the basin and that will help with that production growth as you get to your guidance?

Michael L. Reger

Yes. It's just so much more efficient to operate in the Williston during the summer months. It's not only easier to move equipment around, but it's cheaper. So we're 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.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay, that's helpful. And then just my last one is quickly on the well costs. I think you said $8.2 to $8.4, is that what you're seeing now or is that what you for the year? And if so, what are you seeing now?

Michael L. Reger

Our guidance for the year is $8.4 to $8.8 and we expect to land, from an average, in that range fairly comfortably. Our hope is, and we're again, cautiously optimistic that we'll be ending the year in the neighborhood of about $8 per well and that really is driven by not only what we're seeing in the field, but the sheer number of wells we're participating in and the wide range of operators who we're participating with. But their guidance, our operator -- our operating partners' guidance has been in that neighborhood as well, where we expect the cost to trend towards $8 million towards the end of the year. But we feel very comfortable with $8.4 to $8.8 for the year and that's what our CapEx guidance has led us.

Operator

[Operator Instructions] We'll go next to Jared Lewis with Northland Securities.

Jared Lewis - Northland Capital Markets, Research Division

A quick question, you mentioned that 50% of the wells awaiting for completion are in the Peninsula or in EOG's partial. Given the historic streak of those wells, how do you see that kind of affecting production, if it does, going forward?

Michael L. Reger

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 benefit towards the end of the year. We just think that the quality of the production coming from Mountrail County, which has typically been where Northern pad has step changes in production over the years. We believe we're 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 at the end in the second half, in particular, of 2013.

Jared Lewis - Northland Capital Markets, Research Division

Okay, great. And just how quickly the pad drilling and the efficiencies you're hearing from other operators might be a little earlier. But do you see any change in how many net wells you think you might complete for the year?

Michael L. Reger

We're still sticking with 44. I think the fact that we are at -- we're just under 10 for the first quarter and if you assume the straight-line, it's 11 a quarter. So as we get into the 3 best quarters from an efficiency standpoint, we're very comfortable at 44. We're not going to be making any changes to guidance at this point, but you can just assume that as pad drilling takes hold, the spud-to-spud cycle time will go down. So we're -- it used to be rig on to rig on 30 days, it can be under 20 days to move 1 rig from 1 well to another well after total depth, so on the same pad. So that efficiency might increase on a percentage somewhere in the double digits, might be a 10% increase and sort of rig-on-to-rig-off time frame. But with pad drilling, you can see it's easier to move the equipment around, so we're going to stay with 44 for now and we'll 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.

Operator

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.

Michael L. Reger

Great. 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 our results with you next quarter. Have a great day.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!