Northern Oil and Gas, Inc. (NOG) Q1 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Northern Oil and Gas, Inc. First Quarter 2015 Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions]. As a reminder, this call is being record. 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 will turn the call over to Brandon Elliott to get things started.

Alright, 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 as 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 the earnings release that we issued last night. With the 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 navigate 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 have also 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 approximately two years with a combination of swaps and collars with floors around $90 per barrel. When oil began its precipitous drop in October of 2014, Northern had $90 swap extending out for 21 months. It is for commodity price cycles such as these that 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 seven 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 and 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 give us ample of 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 you are 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 are talking about a lower number of net wells than 2014 levels but it shows that the fields 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 continue to be in line with our prior views for flat production on a significantly reduced capital budget of a $140 million. The timing of the net well additions and magnitude of future curtailments by 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 am 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 first quarter was $67.5 million. Production was up 28% 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’ additive production over the last 12 months. As mentioned in our earnings release, during the first quarter 2015, we experienced 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 curtailment lowered our average daily production for the quarter by over 1,000 barrels of 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 the 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 the first quarter of 2015 and that compares to a $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 the quarter which was down approximately 21% on a year-over-year basis. The decrease was due to both lower NYMEX oil prices which averaged 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 per BOE during the first quarter decreased 15% compared to the first quarter of 2014. Depletion, depreciation and amortization and accretion per BOE was $29.57 this quarter that compares to a rate of $30.19 per BOE in the first quarter of 2014. Completion rate per 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 estimate crude reserves at March 31, 2015, Northern recorded a non-cash ceiling test impairment 360.4 million during the first quarter of 2015. Northern does not have any impairment of crude 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 follows: Approximately $41.3 million of drilling and completion capital which includes our capitalized work over 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 of cash on hand. The company had available liquidity on that date of $218 million at the end of the quarter. As Mike mentioned, we recently completed our semi-annual borrowing base redetermination under our revolving credit facility. The reaffirmation of our existing borrowing base which was maintained at the $550 million level demonstrates the confidence of 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 covenant with a 2.5 to 1 secured debt-to-adjusted EBITDA covenant. We are well positioned from a liquidity covenant perspective to deal with current commodity pricing environment. Given the decline in oil prices, I thought it might be helpful to provide some additional comments around how we are thinking about liquidity and capital allocation. First, we believe we are in a good liquidity position giving our existing borrowing availability and strong hedging position. As a reminder, for the last three quarters of 2015, we have hedged under fixed swap agreements approximately 3 million barrels of oil at an average price of $89.56 per barrel and for 2016, we have hedged under fixed price swap agreement approximately 1.4 million barrels at an average price of $80.64 per barrel. Additionally, we have hedged under collar arrangements 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. May be to put a final point on the impact of our hedging program. If you compare our realized price per BOE excluding hedging, it was down 59% on a year-over-year basis while EBITDA per BOE was only down 19% on a year-over-year basis. The 40% difference is largely due to the impact of our hedging program. Secondly, our asset base is substantially held by production and located in area with some of the lowest breakeven economics in the U.S. 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 administrative staffs for 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 price 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. Malorie, if you could please give the instructions for Q&A?

Thank you. [Operator Instructions]. Our first question comes from the line of Phillips Johnston with CapitalOne. Your line is open. Please go ahead.

Just a clarification for Tom on the updated. You exited the quarter with about $218 million of liquidity that was down from I think $261 million at the end of last year, so about $44 million decrease. From an op’s 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 there’s about a $55 million cash outflow from somewhere else. So, I am just wondering what’s driving that; is that 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 at the end of this quarter, we had a little over 12 net wells. But basically, it’s just -- the decline in working capital is, as we turn those into producing wells.

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 am just wondering what your expectation is for the remainder of the year for gas price to…?

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

Thank you. Our next question comes from Steve Berman with Canaccord Genuity. Your line is open. Please go ahead.

Mike, there is a big backlog of drilled but uncompleted wells in the Williston Basin which Northern is participating in a bunch, I am sure. Can you just give us your thoughts on how you see that backlog being worked off, as we move through the rest of the year, especially given oils rallied here of course to 60 bucks in the last two months?

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 are hearing the same things we are hearing. So, the other issue is that there is very favorable severance tax treatment here as we move away through the year. That will 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 decisions 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 is that we mentioned we had several operators who are curtailing wells. As the severance tax, the small trigger that’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 a 1,000 barrels a day. And 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. And I look forward to seeing how this plays out throughout the rest of the year.

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’ve put out before as kind of year-end number?

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

Thank you. Our next question comes from Scott Hanold with RBC Capital Markets. Your line is open, please go ahead.

If I could just stay on that subject on AFEs you are 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 costs going down versus well productivity improvements based on obviously what you’re operators are doing. And I guess the other third component is, is there any fundamental change in the oil price you are using to make that consent decision?

Really, it’s turning into a perfect storm here for us in a positive way; we’re 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 cost really is just -- it’s simple math as these wells are going to pencil to greater than a 25% internal rate of return for the most part. And as we were exiting March and into April, we were consenting to approximately 80% of the well proposals we are seeing. So really a positive, so there is no real -- there is just a combination of, I don’t know how you break it 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 our operators.

So then what I am hearing because when I listen to calls on some of the other Bakken operators who obviously you guys are partnered with, introducing to moving in core areas -- in the core areas, they are seeing substantial improvement based on recent completion techniques. So, would you consider that potential upside if it actually works that way throughout the -- I guess this year and into the balance of ‘16 and beyond?

Yes. I have been saying that this is generally across the board, just a very healthy reset. And one of 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 the 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 and the core utilizing this new technique and the lower cost in 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 that $50 or better in the core of the play with the new completion design and these lower costs. So really exciting.

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 I think of 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? So, what I am getting at is if 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 are targeting?

Yes, it’s a combination. So, when 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 -- a combination of both of those things, we are comfortable with our guidance of flat production at this point.

And one last one, on the production, the gas percentage went up a little bit or a better to think that your gas production went up a little bit more in this quarter relative to oil. Is that in part due to less flaring and is it all also part due to drilling in more of the center of the basin which is deeper and will have a slightly higher gas cut?

You just asked and answered your question. Actually, 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 up in the 90.10, it’s more 88.12 87.13 in that area.

Thank you. Our next question comes from the line of Andrew Smith with Global Hunter Securities. Your line is open. Please go ahead.

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

Yes, 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 are going to be looking at commodity prices; what it means for the operators as they make their decisions to complete some wells that are awaiting completion in the third and fourth quarter; combination of your typical or your normal field level activities that are around weather in the fourth quarter and others. So, I think we feel good with 20 right now. And if everything improves pricing wise across the board, I think we’re going to be seeing may be an increase in activity but that’s going to be driven by commodity prices. So, we are comfortable with the 20.

Great. And any thoughts on oil price differentials going forward?

I think the biggest issue you are going to be seeing assuming that 50% of the oil is going to be going out by rail is going to be that spread between WTI and Brent that’s been in $6 to $8 range here lately. And that’s decent. As you know last summer, last fall that got to parity there for a couple of days. That spread if it remains in the kind of 8 or wider area, we are going to see differentials compress. The other issue is that production, generally speaking is going to be following in the Williston Basin and all other basins. So, from a pricing standpoint, you are going to see, hopefully we will see that improve. From a modeling standpoint, we are still hopeful that we are going to land the year in that 10 to 12 range. If you are going to model for the next quarter or so, I would model 12 and then hopefully in the back half we’re in that 10 to 12 or better range.

Our next question comes from Adam Leight with RBC Capital Markets. Your line is open. Please go ahead.

Just can I start with following up on Scott’s question, I am not sure if I got it all. But understanding the economics look a lot better in the core, how far does that extend for you, just on the rest of your acreage; do you think there is more wells that would work under your modeling hurdles?

The core of the play is fairly well delineated at this point. a bulk of our activity is in Southern Mountrail County with EOG, Slawson and others. And then we’ve got a really -- we’ve got a good portion of our acreage in Southern Williams County and Northern McKenzie County and then Northern Dunn County where all the rigs are positioned. As oil has moved from 50 to 60, we’ve seen a fairly material move in percentage of wells who are electing to participate in. So, if you look at the -- again if you look at the rigs and where they are developing now, they are in those areas I just identified. And April, it looks like we are -- about 80% of the well proposals we are seeing met our 25% or greater internal rate of return threshold. So, what that’s telling us is that as drilling costs continue 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 a really good job at making capital allocation decisions; they are drilling the best areas; they are drilling with significantly lower costs; and they are using the best techniques as we were discussing with Scott earlier.

And so far, may be early but are your actual costs tracking AFEs pretty closely?

Yes. And 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 timeframe or we receive a well proposal; operators are continuing to get better and better costs with their service providers. So in this environment, we usually do better.

And for Tom I guess, with the uncompleted well inventory has come down and the potential for may be some more activity, how would you expect working capital to track rest of the year?

Actually I think what you’ll do is, as we work off the inventory of wells you will see a higher CapEx spend in the first half, a little bit of the earlier part of the third quarter and then I think our cash flow from operations is going to exceed what the CapEx spend is in the fourth quarter and working capital is going to be pretty flat at that point.

And then 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 as you can see we are 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 where we are allocating capital. If a well that meets a 25% internal rate of return at 60, if the internal rate of return is approximately 40% at 70. So, very happy to continue 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 ‘16 production that you would be comfortable with at those prices, how much 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 ‘17 as we get here through the year. But again, we feel great about the $90 swaps that we’ve got going through June of -- that go out through June of 2016 and. At $7 million well cost as opposed to $9 million plus in 2014, $65, $70 hedges really feel good to us. So, we are going to keep layering in opportunistically.

Adam, we talked in the past about we kind of use our rolling hedging program a little and as Mike referenced in his earlier comments about kind of a disciplined approach, we are about 75% to 80% hedged in 2015; in 2016, we are starting to roll in. And Mike had mentioned that we are fairly heavily hedged in the first half; and you will probably see us continue to hedge using kind of the disciplined approach that Mike spoke about. We’re very rate of return based. So, we are looking at what we’re consenting to at current strip prices and we just kind of roll into it. So, I think that you will probably see the approach that will continue.

Our next questions comes from the line of Marshall Carver with Heikkinen Energy Advisors. Your line is open. Please go ahead.

Factoring in the enhanced completions and the focus on the core and being more selective on which wells you are participating in, what do you think your average EUR is this year versus last year for the wells you are consenting to?

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

And our next question comes from the line of Neal Dingmann with SunTrust. Your line is open. Please go ahead.

Mike, just a quick question. When you all 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 acreages. If we have a well that exceeded the 25% internal rate of return last summer when oil was around $90 oil and then after Thanksgiving we re-ran everything at $65 or below and if it no longer met that 25% internal rate of return, we would proactively try to reverse our consent and then in some cases the operator’s signal problem and then we would -- in other instances, we would have assign the well bore only back to that operator which is effectively the same capital decision is 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, then just lastly around that, if you would, now with prices up a little bit, do you see obviously that circle, you see show that the core inventory in Williams and Mountrail, would you all go down as far as into billings at all yet or not necessarily?

Obviously there’s little pockets here and there as Sam has a nice little pocket of higher return drilling going up in Divide County, Whiting has really strong position down in the Northwest corner of Starr County. But I would say that if you want to draw a circle around the core, you are going to be in Northern Dunn, Southern Mountrail, and Northeastern McKenzie and Southeastern Williams, that’s your circle.

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

Actually Malorie, this is Brandon. I just want to thank everybody for their participation today and your interest in Northern Oil and Gas. And Malorie, you can go ahead and give the replay information. And we’ll look forward to talking 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.