Northern Oil and Gas Inc (NOG) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to Northern Oil and Gas, Inc.'s first-quarter 2016 earnings results conference call. This call is being recorded. With us today from the Company is 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.

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. 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 over to Mike.

Thanks, Brandon. Good morning and thank you for joining the call today. I would like to begin the call with a few 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 a 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 this 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 well-bore opportunities, was steady in the first quarter. And with oil praises improving a bit in the second quarter we were able to increase our price deck, and sellers have been more successful with the current range of bids.

Our drill but uncompleted, also known as DUC well inventory at the end of the quarter was 7.3 net wells, as we elected two-thirds of the well proposals we received, but added three net wells of production during the quarter. We believe we are well positioned to increase production by completion and drilling activity when commodity prices improve, as we have solid acreage and drilling inventory in the core of the play to develop and build off of when we come out of the cycle.

To summarize, liquidity, free cash flow, and debt reductions 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.

Thanks, Mike. Today I'm 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 $0.5 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 these 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 the 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 that 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 in the same period a year ago. Partially offsetting all of our commodity prices was an improvement in the average oil price differential to NYMEX WTI benchmark, which averaged $9.02 per barrel in the 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 derivatives of $25.5 million compared to a $40 million gain in the first quarter of 2015. The gain on settled derivatives increased our average realized price per Boe by $20.64 this quarter. As a result of forward oil price changes, we recognized a non cash mark-to-market derivative loss of $22 million in the first quarter of 2016 compared to a $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 costs 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 a 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 non cash expense.

Our capital expenditures during the quarter totaled $18.1 million. The breakdown of that total is as follows -- approximately $15.4 million of drilling and completion capital, which includes our capitalized workover expenses; $1.6 million on acreage and other acquisition activities; and $1.1 million of capitalized interest and other capitalized costs.

We continue to see cost reductions on the new well proposals being submitted which have recently ranged in the $6.5 million to $7.5 million area. As you might expect, these wells are located in the core areas of the play where the operators are seeing 30%-plus up-lifts in estimated ultimate recoveries due to the higher intensity completions. We currently plan on keeping our capital spending for the year within discretionary cash flow.

Turning to liquidity, we ended the quarter with only $117 million of borrowings on our credit facility, which reflects a reduction in the credit facility balance of $33 million during the quarter. We recently completed our semi-annual borrowing base redetermination where our borrowing base was reduced to $350 million. We will be filing a Form 8-K which includes a copy of this credit amendment shortly after the conclusion of this call.

As of today we have $117 million drawn on the facility, which leaves us $233 million of available borrowing capacity. In connection with the borrowing base redetermination, the credit facility was amended to reduce the minimum ratio of EBITDAX to interest expense that the Company is required to maintain by stepping down over a series of quarters from the current requirement of 2.5 times coverage to a 1 times coverage requirement. We remain well within compliance on all of our credit facility covenants.

And with this recent amendment we feel confident we will remain in compliance throughout 2017. We currently have no long-term maturities under debt. We maintain a solid hedging position and remain well positioned from a liquidity perspective to execute on our 2016 development plan.

As a reminder we have a total of 450,000 barrels of oil hedged with swaps at an average price of $90 per barrel in the second quarter of 2016. After that we have an additional 900,000 barrels with swaps at an average price of $65 per barrel in the second half of 2016. That amount of hedging is valuable in the current pricing environment and helps protect our balance sheet.

In concluding my comments, I would like to point that our asset base is substantially held by production. And as a non-operator, Northern has extensive control over its capital spending because it has the ability to elect to participate on a well-by-well basis. This provides the ability to be more selective in the allocation of capital to the highest rate of return projects without the contractual burden of drilling commitments, large operational or administrative 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 certainty of how long the low-price environment will last. By reducing commitment levels and protecting our liquidity we are navigating the low-price environment and at the same time preparing ourselves for future opportunities and value creation.

At this time we'll turn the call over to the operator for Q&A. Jonathan, if you could please give the instructions for the Q&A portion.

(Operator Instructions)

Our first question comes from the line of Neal Dingmann from SunTrust. Your question, please.

Hey, Mike, obviously you're doing a good job now on liquidity and free cash flow. With those objectives you still have, do you think any differently of potentially going non-consent on some wells? Or are you just sticking to your game plan that you've had?

We just elect on a well by well basis. If it meets our acceptable rate of return threshold we'll elect. If it doesn't, we won't.

In the first quarter we elected to approximately two-thirds of the well proposals we received. That fluctuates but that's pretty decent going forward. The forward price strip has is improved in the first quarter so it makes it easier to pencil some of these wells. And, again, we're very disciplined in how we model the economics.

Got it. And I think you had 1,600 barrels or so just from curtailment. How are you seeing curtailments today? As you point out, certainly prices are improving, so I'm just wondering how you're seeing them today versus the prior quarter.

It's primarily swaps and in Continental. What we're seeing, 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 improved, Todd Slawson started to turn those wells back on. So it's on a real-time basis, which is an advantage we have with Slawson as a partner.

And then diffs, Oasis just said this morning they were thinking maybe in the $4 to $5 area. Is that something you're seeing?

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

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

We look at literally every deal that's marketed, and do a full economic evaluation. We've been fairly conservative in how we've been bidding. Price decks have improved over the last month and a half, as you know. So, it makes it easier to pencil some of these deals. Some of the sellers are starting to feel like they're getting a more acceptable bid on their assets.

Again, where we're finding success right now is not in the big marketed deals. We're finding the success from the smaller off-market deals, our standard ground game where we really do the most damage, which is picking up not only leases in the core of the play, but picking up well-bore opportunities. For example, if we have, call it, 10% work interest in a unit, and three or four other parties have anywhere from 1%, 3%, 5%, 10% working interest in the unit, we might 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'll target that interest just to back-fill in the higher return wells, and that gives us far more comfort as we non-consent low-return opportunities.

Thank you.

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

Your plan through 2016 seems to be very well thought out and in place. As you 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?

I don't know where you all feel at this stage in the cycle is comfortable in activity levels. At some point in time does it become important to stabilize production a little bit more? And would you be willing to take on leverage at an appropriate price to do that?

Scott, I think the way we're 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 a 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're small, medium, or larger acquisitions, or whether it comes down to just drilling in the core of the play.

We'll deploy the capital if it meets our economic returns. And then, as you know, we've always been very proactive when it comes to hedging. If there are any meaningful acquisitions we're going to follow on and back up 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 would start layering in, as well.

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.

That's great. With that point on 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 our threshold? Or is there different processes that you go through with the hedge book?

It all comes down to scale. We look at it two ways. We look at potential acquisitions. If it were a meaningful acquisition 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 to participate in, we're going to be thoughtful in how we layer in hedging as we go.

As we look at our liquidity position, we're 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.

So, you started to see last week the Cal 17 strip got right about the $50. You can imagine we were modeling that as it relates to the wells we're electing to participate in. We're monitoring the rig count in North Dakota -- because of that, will there be a pickup in development activity? This is something we look at every day in real time, and we'll be thoughtful on how we layer in our hedges.

Okay. And one last line of questioning here. 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 relative to, say, your average well back in 2015? And, lastly, the one third of the wells you didn't elect to in the quarter, did those just not meet the economic threshold?

Yes, any well that we're going to non consent in didn't meet our economic threshold for one reason or another. It's typically going to be in the neighborhood of geology and geography. Costs are coming down across the board with every operator. But given the current strip -- we're just using a real-time strip in how we analyze the well proposals that we receive -- if they meet our economic threshold and they're in good areas, and the costs are realistic, then we're going to participate.

So, two-thirds to 75% is where we've been. I'm looking at April through April. It's 75% of the wells we've elected to participate that we've received. So, we feel pretty good about that.

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. 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 it, any way you slice it you've seen a pretty material uplift in EURs from previous years. Especially over the last year and a 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 threshold as we go.

Appreciate the time, Mike. Thanks.

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

Good morning, Mike and team. Thanks for taking my call. With regard to Slawson's curtailed volumes, do you have a view on what price Todd is targeting before restoring production to full levels?

We got a full breakdown through first quarter, really January through May. 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 sweet and then also potential outages in Canada.

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, Slawson turned production back on, but not full blast.

Just to give you a hand wave, they 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.

Extremely helpful. And then on your AFEs on consented wells, they were down meaningfully from $7.8 million in Q4 to $7.1 million 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 in Q1?

It's a couple of things. I'll cover it from 30,000 feet. What that represents, you've got a basket of the wells that we elected to participate, and then you've got a basket, basically the weighted average of the wells in process, call it our DUCs. We continue to see them come down.

You've got higher intensity 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. It's a 25/60 unit. Every well is going to be high intensity completion, so that you're going to have a basket of that, which is really ideal, just the way they've been completing the wells. We're seeing wells that are in the 6.3 range, and lower.

So, it's really just a mix of more efficient drilling and completion and then higher intensity completions across the board. It's all working in our favor because you're seeing the uplift from the EURs, and then generally the AFEs have trended down.

It's the completion costs. One of 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 cost. So very encouraging across the board.

Our operating partners, if you think about who they are -- the Continentals, Whiting, Slawson, EOG, and others -- in real time they're working really hard to make this efficient. And it also helps that costs are 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 benefit of all of these efficiencies.

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

The answer is, maybe. But really the answer is probably not. The reason I 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've longstanding relationships with. If we find an opportunity that is primarily an operated asset or really strong acreage position in several specific units, a high percentage in several units, we'll bring in one of our partners.

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

(Operator Instructions)

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

Good morning. Thanks for taking my questions. I had a question, just curious how we should think about 2016's CapEx trajectory going forward. Q1 came in at $18 million. It seems like you may be just slightly ahead of your original schedule with about a quarter of 2016's budget spent in Q1.

As I recall, I believe the budget was originally thought to be back-end loaded. I think ballpark figures, you thought about 70% was going to be spent in the second half. But I also understand there's a bit of a carry-in phenomenon 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.

Yes. I actually think we're pretty solid with respect to the low $70 millions guidance, I think, that we've given before. I think that you will probably see it a little bit lighter in the second quarter and then a little bit heavier, really, in the second half. We're not significantly ahead of where we're at. It's a timing thing with us.

The short course is I think low $70 millions 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 in us not changing the guidance. I think we're still comfortable with the low $70 millions.

Got it. That's very helpful. In a similar regard with 2016's production profile, Q1 did come in a little light because of the shut-in activity, but you were able to keep full-year guidance intact. So, reading between the lines, 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 completion, things of that nature.

I believe the number that was mentioned on last call was approximately a 14% decline, Q4 2016 versus Q4 2015. I'm just curious if that decline is a little bit lower now to make up for the lost Q1 volume but still keep the full year intact.

I think there are a number of factors that are probably impacting us to leave the guidance, really, unchanged. 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 going forward.

And then also something Mike referenced in his comments, just the impact of the newer completion methods are having on the initial production rates is meaningful. That means that the newer wells appear to be performing better than we've originally modeled. So, all those factors have led us to not change it.

I think in that our comments last quarter, 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 will you 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 we'll probably still get you into about the 14%, 15% sequential decline year over year, if that helps.

It does. Very helpful. Thank you for that.

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

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

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