Northern Oil and Gas Inc (NOG) 2015 Q1 法說會逐字稿

Good day ladies and gentlemen and welcome to the Northern Oil and Gas Inc. first-quarter 2015 conference call.

(Operator Instructions)

As a reminder, this call is being recorded. I would now like to introduce your host for today's call, Chairman and CEO, Mike Reger, sir please go ahead.

Good morning everyone. First I'll turn the call over to Brandon Elliott to get things started.

Thanks Mike. We're happy to welcome you to Northern's first-quarter 2015 earnings call. I will read our safe harbor language and then turn the call back to Mike for his opening comments, and then Tom Stoelk, our Chief Financial Officer, will walk you through the financial results for the quarter.

Please be advised that our remarks today, including the answers to your questions, may include forward looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements.

Those risks include, among others, matters that we have described in our earnings release as well in our filings with the SEC, including our annual report on form 10-K and our quarterly reports on form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call we will also make references to certain non-GAAP financial measures, including adjusted net income and adjusted EBITDA. Reconciliations of these measures to the closest GAAP measures can be found in earnings release that we issued last night. With disclosures out of the way, I will turn the call back over to Mike.

Thanks Brandon. Good morning and thanks for joining our call today. As Northern and the rest of our industry navigates through this cycle, I would like to start out with some comments on our non-operator business model.

As the largest non-operator in the Williston Basin, we've always made a concentrated effort to position the Company to withstand drastic swings in market cycles and commodity prices. We feel that coming into this down cycle, our non-op business model, balance sheet and hedge profile put us in a very strong position.

First, in regards to hedging. We began 2015 with nearly 5 million barrels hedged, at approximately $90 per barrel through June of 2016. These hedges will likely account for about 80% of our expected oil production in 2015. Maintaining a hedge book with two years of duration is something we have stayed disciplined at for quite a few years now.

Since late 2009, Northern has been hedged out for proximally two years, with a combination of swaps and collars, with floors around $90 per barrel. When oil began its precipitous drop in October 2014, Northern had $90 swaps extending out for 21 months. It is for commodity price cycles such as these the we have remained so disciplined over the years.

Second, we took a hard look at the returns associated with our wells in process, as oil prices began to fall. Northern exited 2014 with a significant number of wells in process. And some of those wells no longer had an acceptable rate of return at these lower oil prices.

Of the roughly 23 net wells in process at the end of the year, we were able to eliminate nearly 7 net wells by reversing our prior consent decisions or assigning the well bores back to the operator, thereby strategically capitalizing on our non-op flexibility. These specific actions, combined with our disciplined capital allocation process where we only agree to participate in the highest return wells, gives us substantial staying power in an extended down cycle.

More importantly, as we see rates of return improve an activity increase, we will be able to quickly respond and accelerate our participation rate. In addition, recently during our April revolving credit facility redetermination, we were able to maintain our borrowing base at $550 million and amend certain covenants, all of which helps us helps give us ample liquidity and flexibility. Tom will talk more about this in a few moments. Drilling costs continue to fall and the rates of return on invested capital are increasing, as almost all of the current rigs have moved into the core of the play and commodity prices have improved from recent lows.

At the field level, the North Dakota rig count is now 85, down from 190 at Thanksgiving of last year. Our operating partners have reduced their capital spending by 50% to 80% from 2014 levels, which we believe will result in a very healthy reset for the Williston basin. Average drilling and completion costs are falling and will likely settle in at, or below, $7 million to $7.5 million per well by the end of this year, a 20% or greater reduction from the cost we experienced in 2014.

As our operating partners have repositioned their rigs to the areas that generate the highest EURs, combined with the lower service costs we're seeing in recent AFEs, is allowing us to consent to a higher percent of wells. For example, as the number of inbound well proposals began to taper off in the fourth quarter of last year, we were non-consenting a high percentage of well proposals. Our non-consent percentage peaked in December at over 75%.

Recently the number of inbound AFEs has picked up, and we are committing capital to a greater number of wells that are now meeting our 25% internal rate of return thresholds. For the last two months we have started to consent over 70% of our inbound well proposals. Granted, we're talking about a lower number of net wells than 2014 levels, but it shows that, that the field and our operators are adjusting to the current environment and finding profitable areas to drill, even at today's low commodity prices.

Finally, I would like to reiterate again that our expectations and guidance for 2015 continues to be in line with our prior views for flat production on a significantly reduced capital budget of $140 million. The timing of the net well additions and magnitude of future curtailments by our operating partners, will be driving the quarter-to-quarter results.

With this, I will turn the call over to Tom Stoelk our CFO, for a rundown of the financials.

Thanks, Mike. Today I'm going to cover some of the financial highlights for the first quarter and provide some commentary on our liquidity and capital expenditures. Adjusted net income for the first quarter of 2015 was $6 million, or $0.10 per diluted share.

Adjusted net income was negatively impacted during the quarter by the significant deterioration of oil, natural gas and NGL prices. Adjusted EBITDA for the first quarter was $67.5 million.

Production was up 20% year over year, with first-quarter production averaging approximately 17,000 barrels of oil equivalent per day, the year-over-year production growth was primarily driven by improved economics and recoveries on the 41.5 net wells and of the production over the last 12 months. As mentioned in our earnings release, during the first quarter of 2015 we experience production curtailments as certain operators chose to flow back wells at reduced rates, given the low commodity price environment. While production curtailments were not widespread across all of our operators, we did have an instance where one operator's curtailments lowered our average daily production for the quarter by over 1,000 barrels oil equivalent per day.

Oil and natural gas sales for the first quarter of 2015, when you include settled derivatives were up 1% as compared to same quarter last year, and reached $90.4 million. Our average oil price differential to the NYMEX WTI benchmark was $12.45 per barrel in first quarter of 2015, and that compares to $13.42 per barrel in the first quarter of 2014.

Realized price per barrel oil equivalent after reflecting our settled derivative transactions, was $59.16 per Boe for the first quarter, which was down approximately 21% on a year-over-year basis. The decrease was due to both lower NYMEX oil prices, which average 51% lower than the same period a year ago. And lower realized natural gas NGL prices, which averaged 71% lower than the same period last year.

During the first quarter of 2015, we had a non-cash mark-to-market derivative loss of $14.3 million, compared to a non-cash loss of $7.9 million in the first quarter of 2014. On a per-unit basis, during the first quarter of 2015, production expenses decreased $0.47 or 5%, compared to the same period last year and reached $9.29 per Boe. The lower cost on a per-unit basis in 2015 is primarily due to better weather conditions, as well as lower water hauling and disposal expenses, and a larger production base in 2015, over which to spread the fixed cost components over.

Production taxes totaled $5.4 million during the quarter, or approximately 10.7% as a percentage of oil and gas sales, this compares to a 10.1% in the same quarter last year. Our production tax expense is tied directly to the net realized price received at the wellhead and scales up and down with commodity prices. On a per-unit basis production taxes per Boe decreased 57% in the first quarter of 2015, as compared to the same period last year, due to the decline in oil prices.

General and administrative expenses was $4.4 million for the first quarter of 2015, compared to $4 million in the first quarter of 2014. On a per-unit basis, our G&A expense for Boe during the first quarter decreased 15% compared to the first quarter of 2014.

Depletion, depreciation and amortization and accretion for Boe was $29.57 this quarter, that compares to a rate of $30.19 per Boe in the first quarter of 2014. Depletion rate for Boe, which accounts for almost all of our DD&A rate, decreased due to more oil and gas reserves in our 2014 year-end reserve report.

As a result of low commodity prices and their impact on our estimated proved reserves at March 31, 2015, Northern recorded a non-cash ceiling test impairment of $360.4 million during the first quarter of 2015. Northern did not have any impairment as proved oil and gas properties for the three-month period ended March 31, 2014. The impairment charge affected reported net income, but did not reduce cash flow.

Our cash expenditures during the quarter totaled $44.6 million, the breakdown of that total is as a follows. Actually $41.3 million of drilling and completion capital, which includes our capitalized workover expenses. $2 million on acreage and other acquisition activities and $1.3 million of capitalized interest and other capitalized costs.

Turning a second to liquidity. We had $338 million of borrowings on our credit facility at the end of the quarter. Leaving us with $212 million of borrowing availability, with another $5.7 million in cash on hand, the Company had available liquidity in that date of $218 million at the end of the quarter.

As Mike mentioned, we recently completed our semiannual borrowing base redetermination under our revolving credit facility. The reaffirmation of our existing borrowing base, which was maintained at the $550 million level, demonstrates a confidence of -- that the banking group has in the value of our producing assets and our long-term growth prospects.

In connection with this redetermination, Northern and its lenders also replaced a 4 to 1 total debt to adjusted EBITDA covenant with a 2.5 to 1 secured debt to adjusted EBITDA covenant. We're well-positioned from a liquidity covenant perspective to deal with current commodity pricing environment.

Given the decline in oil prices thought it might be coupled to provide some additional comments around how we're thinking about liquidity and capital allocation. First, we believe we are in a good liquidity position given our existing borrowing availability and strong hedging position.

As a reminder, for the last three quarters of 2015 we've hedged under fixed price swap agreements approximately 3 million barrels of oil at an average price of $89.56 per barrel. And for 2016, we've hedged under fixed price swap agreements approximately 1.4 million barrels, at an average price of $80.64 per barrel.

Additionally, we have a hedge on a collar arrangement, 450,000 barrels in both the second half of 2016 and the first half of 2017, at an average floor price of $60 per barrel, and a ceiling price of $70 per barrel. That significant amount of hedging is extremely valuable in the current pricing environment, it helps protect our balance sheet.

Maybe to put a finer point on the impact our hedging program, if you compare our realized price for Boe, excluding hedging, it was down 59% on a year-over-year basis. While EBITDA for Boe was only down 19% on a year-over-year basis, a 40% difference is largely due to the impact of our hedging program.

Secondly, our asset base is substantially held by production and located in an area with the some of the lowest break-even economics in the US. As a non-operator, Northern has extensive control over its capital spending because we have the ability to elect to participate on a well by well basis. This provides us the ability to be more selective in the allocation of capital, to the highest rate of return projects, without the burden of contractual drilling commitments, large operational administration staffs or other infrastructure concerns.

Given the uncertainty around future oil prices, we are continuing to take aggressive steps to protect our balance sheet by maintaining capital discipline, we continue to work hard to build resilience given the uncertainty of how long the low price environment will last. Through these methods and additional steps to reduce commitment levels, we are navigating this low environment and at the same time, preparing ourselves for future opportunities and value creation.

At this time, we will turn the call back over to the operator. If you could please give the instructions for Q&A.

(Operator Instructions)

Phillips Johnston, Capital One

Thank you, just a clarification for Tom. You exited the quarter with about $218 million of liquidity, that was down from $261 million at the end of last year. So about a $44 million decrease.

From an ops perspective, it looks like you generated about $55 million in cash in the quarter and your CapEx is $45 million, so about $10 million of free cash flow. So it seems like it was about a $55 million cash outflow from somewhere else. I'm just wondering what's driving that. Is that a working capital outflow or were there timing differences?

Yes, exactly, it's working capital outflow. If you take a look at the end of the year, we had almost 23 net wells that were drilling and completing. And so, and at the end of this quarter we had a little over 12 net wells. But basically it's just the decline in working capital as we turn those into producing wells.

Okay. Makes sense. And then just in terms of gas realizations.

They swung from about a 35% premium to Henry Hub to about a 30% discount. That's clearly a function of weaker NGL prices, as I think you mentioned. I'm just wondering what your expectation is for the remainder of the year for gas price?

I actually think it will be closer to the Hub price. During this quarter, we had a number of operators who changed their estimates on NGLs during the -- due to the softening, they provided us a little bit of higher numbers coming into the quarter. And so the realized price reflects some perspective adjustments for that. But I think on a go-forward basis, I think if you're closer to Henry Hub you're going to be pretty close.

Okay, thank you Tom.

Steve Berman, Canaccord Genuity.

Thanks and good morning. Mike, there is a big backlog of drilled but uncompleted wells in the Williston Basin in which Northern is participating in a bunch I'm sure. Can you give us your thoughts on how you see that backlog being worked off as we move through the rest of the year, especially given oil's rallied here to close to $60 in the last two months.

Sure. In our conversations with our operating partners, EOG and others, they were looking for $65 a barrel in order to turn things back on. If you're hearing the same things we're hearing.

So the other issue is that there is very favorable severance tax treatment here as we move our way through the year. That'll probably induce some completions as well.

For the most part it's going to be a function of commodity prices, on how lumpy or how flat the backlog gets worked off. And we -- but basically every one of our operating partners is in a strong financial position and I believe that they are making the right decision from a delay or a completion standpoint. So I think we're in a really healthy environment here. And I think our operating partners are making the right decisions.

One other note that -- we mentioned we had several operators who were curtailing wells, as the severance tax, the small trigger as it's known, came on in February. We had a few of our operators complete a few wells into that environment. And then curtail the wells back to basically 50 to 100 barrels a day. As Tom mentioned.

We believe that, that curtailment affected our production in the first quarter by about 1,000 barrels a day. We think again, looking back at that decision, here we are $15 to $20 higher in realized pricing, so I think the operators' are making the right decisions. I look forward to seeing how this plays out throughout the rest of the year.

Okay, and then one more. The inbounds that you are consenting on, recently, what would you say the average AFE is on that relative to the $7 million to $7.5 million number you put out before as kind of year-end number.

I think were starting to see, especially in March, we started to see meaningfully lower AFEs, as I think the -- specifically the completion component of the AFEs started to drop materially. We are starting to see wells in that $7.5 million range as we were in March and entering April. We are hopeful that as we go through the remainder of the year, we think that the bulk of the AFEs we are going to see are going to be in that $7 million to $7.5 million range, so again, really encouraging as it relates to costs.

Okay thanks, appreciate it.

Thanks

Scott Hanold, RBC Capital Markets.

If I could just stay on that subject, on the AFEs you're consenting to. When you step back and look at whether you guys are electing to consent now versus non-consenting. How much of that is related to actual AFE cost going down versus well productivity improvements, based on obviously what your operators are doing? And then I guess the other third component is, is there any fundamental change in the oil prices you're using to make that consent decision?

Yes thanks. Really it's turning into a perfect storm here for us in a positive way.

We are seeing the rigs, if you look at the NDIC website that shows where the rigs are located, you can see all of the remaining 85 rigs or so sitting right in that pocket. Of the core of the play. That, combined with 10% to 20% decrease in AFE costs, really is just simple math. These wells are going to pencil to greater than a 25% internal rate of return for the most part.

As we were exiting March and into April, we were consenting to approximately 80% of the well proposals we were seeing. So really a positive. So there is no real -- there is just a combination of, I don't know how you would break out half-and-half, it's just the EURs are bigger because the rigs are in the core of the play and the costs are down. 10% to 20% across our set of operators.

Okay. So then what I'm hearing, because when I listen to your calls and some of the other Bakken operators who obviously you guys are partnered with, in addition to moving in core areas, in the core areas you are seeing substantial improvement based on recent completion techniques. Would you consider that potential upside if it actually works that way throughout this year, into the balance of 2016 and beyond?

Yes, I've been saying that this is generally across-the-board just a very healthy reset. And one of the things that we have going for us is, last summer as oil prices were still in the $90 to $100 barrel range, the hot topic or the subject of the day was the completion designs. And how with these slick water completions and additional profit, we were starting to see real data on how good this new completion design really is.

That, coupled with this new cycle and the rigs in the core utilizing this new technique and the lower cost and general across-the-board, especially on completion costs, I think it's really ideal and all of this is going to be a good reset. That's going to be a big mover for the field, is that these wells actually pencil at $50 or better in the core of the play, with the new completion design and these lower costs. So really exciting.

Okay. And then a question on your budget. Obviously you didn't move it at all.

But when you look at -- you are getting the reversal of, I think it was seven wells that you consented to, did you assume that in budget and was the move to $7 million to $7.5 million assumed in budget or -- so what I'm getting at is, is there some potential downside in the budget or could you guys, as the economics improve just consent to a greater number of wells to get back to the 140 you're targeting.

Yes, it's a combination. So when we had our year end conference call in late February a lot of our deals had been done to reverse our consent.

On certain wells that didn't meet our internal rate of return threshold. Combined with the new wells that we are participating with and the balance of the wells that are in process, have dramatically higher EURs. So we are still very -- a combination of both of those things, we are very comfortable with our guidance of flat production at this point.

Okay understood. And one last one. On the production, the gas percentage went up a little bit, or a better way of saying that, your gas production and up a little bit more in this quarter relative to oil. Is that in part due to less flaring, and is also in part due to drilling in more of the center of the base which is deeper and will have a slightly higher gas pad?

You just asked and answered your question. Actually it is, it's reduced flaring and it's in areas where there is stronger infrastructure.

So that percentage will probably hold. Kind of where it's at. It's moved off of 90/10 it's 88/12, 87/13 in that area.

Okay, understood, thanks.

Andrew Smith, Global Hunter Securities

With oil prices increasing, costs coming down and returns improving, do have a preliminary idea of how many wells you would think about completing 2016?

I think right now we are going to stick with 20 net wells as we look to the remainder of the year. A lot of things will be factored in as we report future quarters.

We're going to be looking at commodity prices, what it means for the operators that they make the decisions to complete some wells that are awaiting completion, in the third and fourth quarter. Combination of your typical, or your normal field levels activities around weather in the fourth quarter and others.

So I think we feel good with 20 right now. If everything improves, pricing wise across-the-board, I think were going to be seeing a be an increase in activity but that's going to be driven by commodity prices. But we're comfortable with the 20.

Great and any thoughts on oil price differentials going forward?

Yes I think the biggest issue you're going to be seen, assuming that 50% of the oil is going out by rail, is going to be the spread between WTI and brent. That has been in the $6 to $8 here lately. And that is decent, as you know, last summer, last fall that got to parity there for a couple of days.

That spread if it remains in a $8 or wider area, we're going to see differentials compressed. The other issue is that production, generally speaking is going to be falling in the Williston basin and all other basins. So, from a pricing standpoint you're going to see, hopefully will see that improve.

From a modeling standpoint, we are still hopeful that were going to land for the year in that $10 to $12 range. If you're going to model for the next quarter or so, I would say model $12, and then hopefully in the back half we're in that $10 to $12 or better range.

Great, thanks.

Adam Leight, RBC Capital Markets

Kind of start with following up on Scott's questions, I'm not sure if I got it all. Understanding the economics look a lot better in the core, how far does that extend for you? To some of the rest of your acreage? Do you think there's more wells that would work under your modeling hurdles?

Yes, thanks. The core of the play is fairly well delineated at this point. You know, a bulk of our activity in southern Mountrail County with EOG and others. And then we've got a really good portion of our acreage in southern Williams County in northern McKenzie County and then northern Dunn County where all the rigs are positioned.

As oils move from $50 to $60, we've seen a fairly material move in percentage of wells we are electing to participate in. So if you look at the, again if you look at the rigs and where they're developing now, they're in those areas I just identified. And April it looks like we were about 80% of the well proposals we were seeing met our 25% or greater internal return threshold.

So what that's telling us is that as drilling costs continue to go down and as we start to see commodity prices improve here as we are exiting April, combined with the fact that we've been able to put some hedges on here that really lock in some of those really high-quality returns, we think that 80% number could even go up. The operators are doing really good job at making capital allocation decisions. They're drilling the best areas, they're drilling with significantly lower costs, and they're using the best techniques, as we were discussing with Scott earlier.

And so far, maybe early but your actual costs tracking the AFEs pretty closely?

Yes, yes. In an environment like this it's usually going to be going in our favor. Because costs are continuing to get better.

And sort of that lead leg time frame where we receive a well proposal, operators are continuing to get better and better costs with their service providers. In this environment we usually do better.

Okay, and for Tom I guess. With the uncompleted well inventory come down and the potential for maybe some more activity, how would you expect capital to track the rest of the year?

I actually think what you'll do is, as we work off the inventory of wells you'll see a higher CapEx spend in the first half, a little bit of the early part of the third quarter. And then I think we're -- cash flow from operations is going to exceed what the CapEx spend is in the fourth quarter. And your working capital is going to be pretty flat at that point.

Okay great. And just lastly on the hedging, what are your thoughts on layering in further 2016 hedges, what kind of prices are attractive for you?

I think as we mentioned, in that $65 to $70 range our returns are really strong. And we're -- we, as you can see, we were able to layer in opportunistically here in this recent run-up, some hedges that really do lock in. Very high-quality returns for us as it relates to where we're allocating capital.

If a well that meets a 25% internal rate of return at $60, the internal rate of return is approximately 40% at $70. Very happy to continue to layer in hedges here, as we get through the remainder of the year and really lock in these high-quality returns.

Is there a percentage of your 2016 production that would be, you'd be comfortable with at those prices, how much do you want to leave open?

I think the good news is that about 50% of our production is hedged at $90 in the first half. Or just under that. And so we feel good about -- we feel really good about the first half and that gives us a lot of comfort as we begin to layer in additional hedges, as we get towards the, in the back half of 2016. And then more in the first half of 2017, as we get here through the year.

Again, we feel great about the $90 swaps that we've got going through June, they go out through June 2016. And at $7 million well costs as opposed to $9 million plus in 2014, $65, $70 hedges really feel good to us. So we're going to keep layering in opportunistically.

And we've talked in the past about we kind of use a rolling hedged program a little bit. And as Mike referenced in earlier comments, about kind of a disciplined approach. We're about 75% to 80% hedged in 2015, in 2016 we're starting to roll in that.

And Mike had mentioned that we are fairly heavily hedged in the first half. And you'll probably us continue to hedge using the disciplined approach that Mike spoke about, where we're very rate of return based, so we're looking at what we are consenting to at current strip prices. And we just roll into it. So that will probably see the approach that will continue.

Nice to have the flexibility. Thanks.

Marshall Carver, Heikkinen Energy Advisors.

Thank you for taking my question. Factoring in the enhanced completion for the focus on the core, and being more selective on which wells you're participating in, what do you think your average EUR is this year versus last year for the wells you consented to?

We just ran that number and then we -- we think this year, given this year given the nature of where the wells are, we think the average is good to be in the 750 range, based on where the current 85 rigs are located and based on the well proposals we've seen

Okay great, thank you.

Neal Damon, SunTrust

Good morning. A quick question, when you go non-consent is it just on that particular well bore, there is no other issues besides that?

No, it's just we haven't assigned out any acreage, it's just if we have a well that exceeded a 25% internal rate of return last summer when oil was around $90 oil. And then after Thanksgiving we reran everything at $65 or below, and if it no longer met that 25% internal rate of return we proactively try to reverse our consent. And then in some cases the operators said no problem and in other instances we would assign the well bore only back to that operator, which is effectively the same capital decision as going non-consent.

So we feel really good about going from roughly 23 to 16. That really makes us strong as we go into 2015.

Okay and then just lastly. Around that, if you would now, with prices a little bit you see the core inventory in Williams and Mountrail et cetera. Would you all go down as far as into billings at all, you had or, not necessarily?

Obviously there is little pockets here and there. SM has a nice little pocket of high return drilling going up in Divide County. Whiting has really strong position down in the northwest corner of Stark County.

But I would say that if you wanted to draw circle around the core, you going to be in northern Dunn, southern Mountrail and northeastern McKenzie and southeastern Williams. That is your circle.

Got it, thanks Mike.

Thanks

I am showing no further questions. I would now like to turn the call back to Mark Reger for any further remarks.

Actually, this is Brandon. I just want to thank everybody for their participation today and your interest in Northern Oil and Gas. And you can go ahead and give the replay information and we will look forward to talking to everybody on the road or on the conference call next quarter. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program and you may all disconnect. Everyone have a great day.