Northern Oil and Gas, Inc.
Q1 2016 Earnings Call Transcript

Published: 10 May 2016

[Operator:]

Good day, everyone, and welcome to Northern Oil and Gas Incorporated’s First Quarter 2016 Earnings Results Conference Call. This call is being recorded. With us today from the company is the Northern’s Chief Executive Officer Mike Reger; Chief Financial Officer, Tom Stoelk; and Executive Vice President Brandon Elliott. At this time, I will turn the call over to Brandon. Please go ahead, sir.

[Brandon Elliott:]

Thanks, Jonathan. Good morning everyone and welcome to Northern's first quarter 2016 earnings call. I will read our Safe Harbor language and then turn the call over to Mike Reger, our Chief Executive Officer 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. Reconciliation 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'll turn the call over to Mike.

[Mike Reger:]

Thanks, Brandon. Good morning and thank you for joining the call today. I would like to begin the call with highlights and accomplishments from the first quarter and then turn the call over to Tom Stoelk, our CFO to cover the financials. Over the last several quarters we have talked about our non-operated capital allocation advantage and the disciplined approach we take with our capital spending. We have incredible flexibility as it relates to our capital expenditures. This capital allocation advantage has allowed us to protect our balance sheet and liquidity position and continue to pay down our credit facility over the last several quarters. We believe this advantage will benefit our shareholders through this and future commodity cycles as we continue to consent only to those wells that we believe will generate solid rate of return in the current commodity price environment. Due to our capital allocation advantage and discipline, we were able to pay down $33 million on our revolving credit facility in the first quarter and $71 million over the past few quarters. While others have talked about reaching cash flow neutrality or set a goal of getting to some measure of free cash flow, we have done it and we did it quickly. Our capital discipline and hedging over the last 24 months has allowed us to maintain a strong liquidity position throughout the cycle. We still have $90 swaps in place through June 30 of this year and $65 swaps in place through December 31 of this year. With our new borrowing base of $350 million and cash on hand, we have a liquidity position of over $237 million. In connection with the borrowing base redetermination, we also amended the EBITDAX to interest expense ratio in our credit facility agreement to give us plenty of room to stay in compliance even if low oil prices persist through 2017. With no liquidity issues or covenant pressure, we can stay focused on the execution of our business plan and continue to think opportunistically regarding acquisitions. Turning to operations, we continue to see a slowdown in the drilling activity in the basin while the North Dakota rig count is under 30. This coupled with production curtailments by certain operators in the first quarter that we estimate totaled approximately 1,600 BOE per day caused production for the quarter to be down 19% year-over-year and 15% sequentially. Those production curtailments have eased a bit since March as oil prices have improved but we still expect to see a certain level of curtailment persist depending on oil prices. With that being said, we still feel comfortable with our prior guidance that 2016 total production will be down approximately 15% compared to 2015 and our 2016 CapEx guidance remains unchanged as well. As far as acquisitions are concerned, we have remained conservative on how we are bidding on the larger non-op packages that are being actively marketed. We evaluate every non-op asset sale in the basin and we have been relatively successful on the smaller off-market deals. Our basic acquisition ground game acquiring core acreage and wellbore opportunities was steady in the first quarter and with oil prices improving a bit in the second quarter, we were able to increase our price decks and sellers have been more successful with the current range of bids. Our drilled but uncompleted also known as duct well inventory at the end of the quarter was 7.3 net wells as we elected the two-thirds of the well proposals we received but added three net wells to production during the quarter. We believe we are well-positioned to increase production by completions and drilling activity when commodity prices improve as we have solid acreage in drilling inventory in the core of the play to develop and build off of when we come out of this cycle. To summarize, liquidity, free cash flow and debt reduction have been our focus over the past year. We entered this cycle with a strong hedge book and a strategically advantaged business model. I believe we are in a great position to grow efficiently and quickly as commodity prices improve. With that I will turn the call over to our CFO, Tom Stoelk.

[Tom Stoelk:]

Thanks, Mike. Today I am going to cover some of the financial results for the first quarter and provide some commentary on our liquidity. Adjusted net income for the first quarter of 2016 was $1.5 million or $0.01 per diluted share. Adjusted EBITDA for the first quarter was $36.2 million. Both of these amounts were impacted by low oil and natural gas prices during the quarter. First quarter production averaged 13,552 barrels of oil equivalent per day with approximately 90% of the production coming from crude oil. In light of the low commodity price environment we reduced our 2015 capital expenditures by 76% as compared to the prior year which lowered the number of new wells placed into production. Although the per well productivity in the new wells has improved that was more than offset by the natural decline of oil and gas production in the first quarter of 2016 due to lower number of new wells placed in production over the last 12 months. In addition, as Mike mentioned, certain operators curtailed production during the first quarter as they await higher pricing. We estimate the curtailments reduced our production in the first quarter by approximately 1,600 barrels of oil equivalent per day. As a result, the first quarter 2016 production volumes decreased 19% as compared to the first quarter of 2015. Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $43.64 per BOE for the first quarter which was down approximately 26% on a year-over-year basis. This decrease was due to lower commodity prices than the same period a year ago, partially offsetting the lower commodity prices was an improvement in the average oil price differential to NYMEX WTI benchmark which averaged $9.02 per barrel in first quarter of 2016 as compared to $ $12.45 per barrel in the first quarter of 2015. Oil, natural gas and NGL sales when you include our cash derivative settlements totaled $53.8 million in the first quarter, approximately 41% of our crude oil production was hedged at $90 per barrel which helped mitigate the current low oil price environment. For the first quarter of 2016 we realized a gain on settled derivative of $25.5 million compared to $40 million gain in the first quarter of 2015, again our settled derivatives increased our average realized price per BOE by $20.64 this quarter. As a result of forward oil price changes we've recognized a non-cash mark to market derivate loss of $22 million in the first quarter of 2016 compared to $14.3 million loss in the first quarter of 2015. Looking at expenses, our combined per unit production expenses and production taxes for the first quarter of 2016 declined by 7% when compared to the first quarter of 2015. The decrease in per unit operating cost was driven by lower workover and maintenance costs and a smaller taxable base for production taxes which was partially offset by lower production levels and the higher number of net producing wells. General and administrative expense was $4.3 million for the first quarter of 2016 compared to $4.4 million in the first quarter of 2015. General and administrative expenses for the first quarter of 2016 were comprised of $2.9 million of cash expense and $1.4 million of noncash expense. Our capital expenditures during the quarter totaled $18.1 million. The breakdown of that total is as follows

[Operator:]

[Operator Instructions] Our first question comes from the line of Neal Dingmann from SunTrust. Your question please.

[Neal Dingmann:]

Hey, Mike, obviously you’re doing a good job now in liquidity and free cash flow. So with those kind of objectives you still have, do you think any differently of potentially going non-consent on some wells or you kind of just stick onto your game plan that you have had?

[Mike Reger:]

I think we just select on a well-by-well basis. If it meets our acceptable rate of return thresholds, we will elect. If it doesn’t, we won’t. So I think in the first quarter, we elected to approximately two-thirds of the wells – well proposals we received and that fluctuates, but that’s pretty decent going forward. The forward price strip has improved in the first quarter. So it makes it easier to pencil some of these wells and again, we are very disciplined on how we model the economics.

[Neal Dingmann:]

Got it. And I think you had 1,600 barrels or so just from curtailment, how are you seeing curtailments today? I mean, as you pointed out certainly prices are improving, so I guess I am just wondering how you’re seeing them today versus the prior quarter?

[Mike Reger:]

Right. I think, it was primarily Slawson and Continental and what we are seeing is, as prices started to improve in March, and differentials started to improve a bit as well, we started to see Slawson, especially turn a little bit of production back on, obviously nowhere near full blast. But as prices improve, Slawson started turn those wells back on. So it’s on a real-time basis, which is an advantage we have with Slawson as a partner.

[Neal Dingmann:]

And then [indiscernible] this morning, they were thinking, maybe in that $4 to $5 area, is that something you are seeing?

[Mike Reger:]

We are hopeful that June contracts that the operators sign will be better than they have been, primarily because of the Canadian wildfires and other pressures and demand on light, sweet. I think we are going to hold our guidance where it is right now, but fingers crossed that there is strong demand for gasoline this summer and then events such as the Canadian wildfires can help differentials in North Dakota for sure.

[Neal Dingmann:]

All right. And then lastly, just M&A in this environment, any thought for yourselves given that liquidity objective you have?

[Mike Reger:]

We look at literally every deal that’s marketed and do a full economic evaluation. We have been fairly conservative on how we have been bidding. Price tax have improved over the last month and half, as you know, and so it makes it easier to pencil some of these deals and some of that sellers are starting to feel like they are getting a more acceptable bid on their assets. Again, we are finding success right now as not in the big marketed deals, we are finding the success from the smaller off-market deals, our standard ground game that we really – where we really do the most damage, which is picking up, not only leaves us in the core of the play, but picking up well bore opportunities. For example, if we have call it 10% working interest in a unit, and three or four other parties have anywhere from 1%, 3%, 5%, 10% working interest in the unit, we like to be able to buy their acreage, we might also be able to pick up their well bore interest in that well. Assuming it pencils, we will target that interest just a backfill in the higher return wells and that gives us far more comfort as we non-consent lower churn opportunities.

[Neal Dingmann:]

Thank you.

[Mike Reger:]

Thanks a lot.

[Operator:]

Thank you. Our next question comes from the line of Scott Hanold from Royal Bank of Canada. Your question please.

[Scott Hanold:]

Thanks. Hey guys. Your plan through 2016 seems to be very well thought out and in place. As you all look forward to 2017, obviously the hedge position isn’t as strong. How do you think of navigating 2017 when you think about leverage levels and I don’t know where you all feel at this stage in cycle is comfortable in activity levels, because at some point time does it come important to stabilize production a little bit more and would you be willing to take on leverage at an appropriate price to do that?

[Mike Reger:]

Scott, I think the way we are going to look at it is as a non-operator, we have again tremendous flexibility when it comes to how we deploy our capital. If oil prices remain low through 2017, you can obviously expect continued erosion of the rig count in the field, that’s not necessarily a bad thing or a good thing, because our capital deployed will be to the higher rate of return projects whether they are small, medium or larger acquisitions or whether it comes down to just drilling in the core of the play. We will deploy the capital that meets our economic returns and then as you know, we have always been very proactive when it comes to hedging. If there are any meaningful acquisitions we are going to follow on and backup that with those cash flows and lock in those cash flows with hedging. If we see a pickup in drilling activity which would likely be correlated with improving commodity prices, we’d start layering in as well. So it's pretty simple for us as a non-operator, we don't have to make long-term significant decisions on bringing rigs in, making big capital commitments, we can basically be nimble and deploy our capital efficiently as we go.

[Scott Hanold:]

With that point of hedging and as you look on the curve and you made a prior comment that the strip obviously improved -- has helped make a lot of those proposals more economic, when you're making these decisions, where is the consideration of okay, we’ve elected to save three net wells here, let’s lock in the production because they meet a threshold or there are different processes you go through with hedge book.

[Mike Reger:]

It all comes down to scale, so when we look at it two ways, we look at potential acquisitions, if it were a meaningful acquisitions, we would certainly lock in those returns with hedging if it comes to what our model currently predicts as number of wells we’re going to elect that purchase paid in, we’re going to be thoughtful in how we layer in hedging as we go. As we look at our liquidity position, we are very comfortable with our liquidity position, primarily because we have the ability to adjust our CapEx as needed depending on oil prices and depending on the environment. And so, you started to see last week that the current 17th strip got right about $50, you could imagine we are modeling that as it relates to wells we are electing to participate in, we’re monitoring the rig count in North Dakota, because of that will there be a pickup in development activities. So this is something we look at every day in real time and we’ll be thoughtful and how we layer in our hedges.

[Scott Hanold:]

And one last line of questioning, of the I guess the three wells you did elect to participate in or actually participated in this quarter, can you just generally describe or give us a sense of how productivity is of these wells relatively to say you’re average well back in 2015 and last there is a question, the one third of the wells you didn’t elect to in the quarter, those just not meet the economic threshold?

[Mike Reger:]

Any well that we’re going to non-consent and didn't meet our economic threshold for one reason or another and it's typically be in the neighborhood of sort of geology and geography. Costs are coming down across the board with every operator but given the current strip, we are using a real-time strip and how we analyze the well proposals that we receive, we will - if they meet our economic threshold and they’re in good areas and the costs are realistic then we are going to participate. So, two-thirds or 75% is kind of where we’ve been, I'm looking at through April, if 75% of the wells we’ve elected to participate that we’ve received, so we feel pretty good about that. And then to get back to your previous question, the three net wells that we completed in the first quarter were primarily McKenzie and Williams with Whiting and Continental and about half of those wells came on in March and so we feel like the productivity of the wells and by the way not just those two operators almost every operator is utilizing primarily the higher intensity completions. And if you look at, anyway you slice it, you’ve seen a pretty material uplift in EURs from previous years, especially over the last year and half, you’ve seen a pretty material uplift in EURs. And commodity prices aside just the wells are better, they’re cheaper and they’re higher EURs, so we’ll see more and more wells we believe meet our economic thresholds as we go.

[Operator:]

Thank you. Our next question comes from the line of Derrick Whitfield from GMP Securities. Your question please.

[Derrick Whitfield:]

With regard to Slawson’s curtailed volumes, do you have a view on what price it is targeting before restoring production to full levels?

[Mike Reger:]

We've got a full breakdown of through first quarter, we’re really January through May and differentials are really their number one concern, differentials have started to improve a little bit, everybody is hopeful that differentials will be a little better in June given the two issues I mentioned earlier both strong demand for Light Suite and then also potential outages in Canada. And oil prices have obviously gone from call it from February to April, they went from 26 to 46, so there was a pretty material improvement and as oil improved and as differentials began to tighten a little bit, just lost some turn production back on but not full blast, just to kind of give you a hand wave, they’ve cut their production materially in February and then started to bring it back on in March and then a bit more in April as well and then the idea is to keep ramping it up into the demand season here. So, although still quite curtailed just speaking Slawson alone, they’re turning production back on.

[Derrick Whitfield:]

And then on your AFEs on [indiscernible] wells, they were down meaningfully from 78 in Q4 to 71 in Q1; do you have a view of how much that decrease was market versus mix given that you're just looking at two operators?

[Mike Reger:]

It is a couple of things, so I'm looking at coverage from 30,000 feet, what that represent, you could you basket of the wells that we elected to participate and you get a basket on basically the weighted average of the well in process, call it our docks, and we continue to see them come down, you’ve got higher incentive completions and bigger wells in some of the bigger longer lateral units that we’re drilling with Continental in the core of the play, we just elected the 17 gross wells in a unit with Continental in there, it’s 2560 unit, every wells is going to be high intensity completions, so you're going to have a basket of that which is really ideal just the way they’ve been completing the wells, proceeding wells that are in 6.3 range and lower. So it’s really just a mix of more efficient drilling and completion and then higher intensity completion across the board, it's all kind of working in our favor because you're seeing the uplift from the EURs was and then generally, the AFEs have trended down. It's the completion costs, what are the best data points that we've seen over the last couple of weeks is our operating partners are starting to reference during this earnings season, what completion costs look like and that's the biggest mover as far as total D&C costs coming down is completion costs. So very encouraging across-the-board, our operating partners, if you think about who they are, the Continentals, Whitings, Slawsons, EOGs, others and it is, I mean in real time, they are working really hard to make this efficient and it also helps that we’re constantly coming down, and we’re drilling in the core of the play, and we've got substantial inventory in the core of the play. So we’re seeing the benefits of all of these efficiencies.

[Derrick Whitfield:]

That's great. Mike, it sounds like there is definitely some downside from here in costs, just based on one other operators you're referencing and largely what you describe in your comments as well. Next part, I wanted to step out a bit on the M&A front, just to test waters with you guys, but would you consider an opportunistic acquisition of an operated position, assuming PDPs are in place and you can bring over part of the staff to operate that position?

[Mike Reger:]

The answer is maybe and -- but really the answer is probably not. The reason I’d say it like that is, we've actually analyzed certain operated assets, but we would bid on those assets or have bid on those assets with an operating partner, if that makes sense. Our strategic non-operated advantage, especially in this environment, is really critical in our success and we’re going to continue to build on our non-op franchise. We've got some really great partners out there that we have long-standing relationships with that -- if we find an opportunity that is primarily an operated asset or really strong acreage position in several specific units, or high percentage in several units, we’ll bring in one of our partners.

[Derrick Whitfield:]

Very good. Thanks for your time and thanks for taking my call.

[Operator:]

[Operator Instructions] Our next question comes from the line of John Aschenbeck from Seaport Global. Your question, please.

[John Aschenbeck:]

Hi, good morning. Thanks for taking my question. Just curious how we should think about 2016th CapEx trajectory going forward. Q1 came in at 18 million. It seems like you may be just slightly a bit -- ahead of your original schedule, with about a quarter of 2016 budget spent in Q1. As I recall, I believe the budget was originally thought to be back-end loaded, I think ballpark figures, we thought about 70% was going to be spent in the second half, but I also understand there is a bit of a carry-in phenomena from prior quarters when ramping down activity. I was just hoping you could provide some clarification on cash CapEx trajectory for the remainder of the year?

[Tom Stoelk:]

Yes. I actually think we're pretty solid with respect to kind of the low-70s guidance I think that we've given before. I think that you’ll probably see it a little bit later in the second quarter and then a little bit heavier really in the second half, but we’re not significantly ahead of kind of where we are at. It's kind of a timing thing with us, but the short course is, I think, low-70s is where we expect to land. I don't think, at this point, we're looking at much more than 10 net wells being added to production and that's implied, and that's not changing the guidance. So I think we're still comfortable with the low-70s.

[John Aschenbeck:]

Got it. That's very helpful. And in similar regard with 2016th production profile, Q1 did come in a little wide because of the shut-in activity, but you were able to keep full-year guidance intact. So reading between the lines, I guess that would imply that you’re expecting a lower decline in the back half of the year, I would suppose, either from lower base declines or expecting better results from enhanced completions and things of that nature. I believe the number that we’ve mentioned on last call was approximately a 14% decline in Q4, 16, versus Q4, 15. I'm just curious if that number is -- that declined a little bit lower now to make up for the loss in Q1 volumes, but still keep the full year intact?

[Tom Stoelk:]

Yes. I think there are a number of factors that are probably impacting us to leave the guidance really unchanged and those probably include, as we mentioned, production curtailments are starting to ease a little bit in the second quarter versus the first quarter. I think our original guidance had assumed 10 wells. We're a little bit ahead as you referenced in your first question, with about three net wells added to production, most of those in March, but being slightly ahead, that's going to probably favorably impact our production estimates kind of going forward. And then also something Mike referenced in his comments, just the impact that the newer completion methods are having on the initial production rates is meaningful. That means that the newer well appear to be performing better than we’ve originally modelled. So all those factors have kind of let us to not change it. I think that in our comments last quarter kind of coming into it, we thought that there would be a decline sequentially in the first quarter, a little bit of a decline in the second quarter and then relatively flat. I think that profile just based on the changes is probably a modest decline sequentially quarter-over-quarter and when I say modest, I would say low-single-digits. And then I think you’ll probably see third and fourth start to trend up, third probably a small sequential increase followed by a similar sequential increase in the fourth quarter, but will probably still get you into about the 14%, 15% sequential decline year-over-year, if that helps.

[John Aschenbeck:]

It does. Very helpful. Thank you for that.

[Operator:]

Thank you. And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Brandon Elliott for any further remarks.

[Brandon Elliott:]

All right. Thanks, everybody for the participation in our call today and for your interest in Northern Oil & Gas. Jonathan will give you the replay information and we look forward to working with you all again soon. Hope everybody has a good rest of the week.

[Operator:]

Thank you, ladies and gentlemen, for your participation in today's conference. You may access the replay, dialing 1-800-585-8367, entering the pass code 1179256. Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.