Northern Oil and Gas Inc (NOG) 2016 Q2 法說會逐字稿

Good day everyone, and welcome to Northern Oil and Gas Incorporated second 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 Michele. Good morning everyone. We are happy to welcome you to Northern's second quarter 2016 earnings call. I will read our Safe Harbor language and then turn the call over to Michael Reger, Chief Executive Officer for his opening comments, and then Tom Stoelk, Chief Financial Office, will walk you through our 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 results to be materially different from the expectations contemplated by these forward-looking statements. Those risks including among others, matters that we have described in our earnings release, as well as in 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 nonGAAP 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 over the call 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 second quarter, and then turn the call over to Tom Stoelk, our CFO, to cover the financials. Throughout 2016 we have continued to focus on non-operated capital allocation advantage. We take a disciplined approach with our spending, as we leverage our incredible database of wells in the Basin, and the flexibility as it relates to our capital expenditures. This capital allocation advantage has allowed us to protect our balance sheet and liquidity position, to further withstand lower commodity prices for longer. 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 appropriate rate of return in the current commodity price environment.

Our capital discipline and hedging over the last 24 months has allowed us to maintain a strong liquidity position throughout this cycle. We were well-hedged with $90 swaps through the first half of 2016, we have $65 swaps in place through the second half of this year, and $50 swaps in place in the first half of 2017. With our borrowing base of $350 million and cash on hand, we have available liquidity of over $220 million. With no liquidity issues or covenant pressure, we can stay focused on the execution of our business model, and continue to think opportunistically regarding acquisitions.

As far as acquisitions are concerned, we have remained conservative and very disciplined on how we bid for Williston Basin non op assets and acreage. We acquire acreage using the same capital discipline we apply to well proposals, looking only for the highest rate of return drilling inventory, we evaluate every non op asset in Basin, and we have been successful on several smaller off market deals.

Turning to operations, we continue to see moderate drilling activity in the Basin, with the North Dakota rig count at 34. Our current inventory of wells in process at the end of the quarter was approximately nine net wells. We elected to 75% of the well proposals we received in the second quarter, which was an increase from the beginning of the year as oil prices improved. We believe we are well-positioned to grow via completions and new drilling inventory, as commodity prices continue to improve due to our high quality acreage and drilling inventory in the core of the play.

Despite reducing our second quarter capital spending by 50% year-over-year, we were still able to grow production by 3% sequentially. I believe it is important to note that the flexibility of our non op model allowed us to reduce spending more quickly than our peers at the beginning of this cycle. This same flexibility will allow us to ramp up activity in spending, just as quickly as it was reduced. Given how the year has progressed and our inventory of high quality wells in process in the core of the play, we are comfortable with the current production guidance, CapEx, and operating expenses we laid out in the earnings release last night.

In summary, liquidity and capital discipline have been our focus over the past 24 months. We entered this cycle with a strong hedge book and a strategically advantaged business model. I believe we are in a great position to persevere in a low commodity price environment, and have the ability to quickly return to efficient and profitable growth as commodity prices improve. With that, I will turn the call over to our CFO, Tom Stoelk.

Thanks Mike. Today I am going to cover some of the financial highlights from second quarter, and provide some commentary on our liquidity. Adjusted net income from second quarter was $6.5 million, or $0.10 per diluted share, adjusted EBITDA for the second quarter was $44.3 million, up 22% from last quarter. Second quarter production averaged 13,933 barrels of oil equivalent per day, with approximately 86% of that production coming from crude oil. In light of low price commodity environment, we reduced our 2015 capital expenditures by 76% as compared to the prior year, which has lowered the number of new wells we are adding to production, and in 2016 our capital expenditure budget was further reduced to provide a better matching of discretionary cash flow with capital spending.

Although the per well productivity of the new wells has improved, the effect on our production levels has been largely offset by natural decline of oil and gas production, due to lower number of wells placed into production over the last 12 months. In the second quarter of 2016 we saw an easing of production curtailments experienced during first quarter 2016 which drove a 3% sequential quarterly increase in production volumes.

Realized price per barrel of oil equivalent after reflecting our settled derivative transactions was $49.30 per boe for the second quarter, which was down approximately 21% on year-over-year basis. The decrease was due to low commodity prices and reduced hedging levels as compared to same period a year ago. Partially offsetting the lower commodity prices was an improvement in the average oil differential to NYMEX WTI benchmark, which averaged $8.08 per barrel in second quarter of 2016, as compared to $11.50 per barrel in the second quarter of 2015. Oil, natural gas and NGL sales when you include our cash derivative settlements totaled $62.5 million in the second quarter. Approximately 41% of our crude oil production was hedged at $90 per barrel, which helped mitigate the current low price environment. For the second quarter of 2016, we realized a gain on settled derivatives of $20 million, compared to a $31 million gain for the second quarter of 2015. A gain on settled derivatives increased our average realized price per boe by $15.76 this quarter. As a result of the forward oil price changes we recognized a non cash mark to market derivative loss of $30.5 million in the second quarter 2016, compared to a $53.2 million loss in the second quarter of 2015. Looking at expenses, our combined per unit production expenses and production taxes for the second quarter of 2016 declined by 11%, when compared to the second quarter of 2015. The decrease in per unit operating costs was driven by lower workover and maintenance costs, and a smaller tax 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 $4.6 million in second quarter of 2016, as compared to $4.3 million in the comparable quarter last year. General and Administrative expenses for second quarter of 2016 was comprised of $3 million of cash expenses, and $1.6 million of noncash expenses. Cash general and administrative expense in the first quarter of 2016 decreased 8%, as compared to the same period last year, and for the first half of 2016 is down 10%, as compared to first half of 2015.

Our capital expenditures during the quarter total $16.5 million, the breakdown of that total is as follows, approximately $14.4 million of drilling and completion capital, which includes capitalized workover expense, $1.3 million on acreage and other acquisition activities, and $800,000 of capitalized interest and other capitalized costs. We continue to see cost reductions in the new well proposals being submitted, which have recently ranged from the $6.5 to $7.5 million area. We currently plan on keeping capital spending for the year within discretionary cash flow.

Turning to liquidity, we ended the quarter with only $132 million of borrowings on our credit facility, which provides us with $218 million of available borrowing capacity. We currently have no near term maturities of our debt, 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 900,000 barrels of oil hedged at an average price of $65 per barrel in the second half of 2016, and 720,000 barrels of oil hedged, at an average price of $50 in the first half of 2017. That amount of hedging is valuable in the current pricing environment, and helps to protect our balance sheet.

In concluding my comments, I would like to point out that asset base is substantially held by production, and as a non-operator, Northern has extensive control over its capital spending, because we have the ability 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 burden of contractual 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 uncertainty of how long the low price environment will last. By reducing commitment levels and protecting our liquidity, we are navigating a slow price environment, and at the same time preparing ourselves for future opportunities and value creation.

At this time, I would like to turn it over to operator for Q&A, if you could please open up the lines.

(Operator Instructions). Our first question comes from Neal Dingmann of SunTrust, your line is open.

Good morning, Neal.

My question looking to typical slide that you have that shows [participating] well locations, and wondering when you said you continue to obviously just go after the higher returns, I just wanted to make sure that on that it shows, prior years, including 2015 all of the way all of the Northern leaseholds. I am wondering when you look at that area, how should we think about between Williams Mountrail McKenzie, that entire map, are there pockets there, again how should we think sort of core areas that you are really targeting there?

Generally and more specific. If you just take big four counties, McKenzie, Williams, Mountrail, and Dunn, I think those are generally going to be the core counties, and then there are core areas within those four countries. One thing I will caveat that with, is it all depends on costs, certain operators have lower drilling costs and completion costs than other operators. Certain operators are more efficient and effective than other operators. For us, given the incredible amount of data we have and the history that we have now over 10 years of participating in the Williston, we know who is going to perform better, and in what areas. But there is no question southern Mountrail county is core, northern McKenzie county is core, northern Dunn county, and then southeast Williams is going to be core. There are pretty simple mapping, but it all just comes down to which operators have lower costs, and who is more efficient and more effective.

Got it, great. Good color. Then just lastly, curtailments, I know a couple of the privates were doing that, I don't know if a couple of the publics were as well, is that prevalent at all, Mike?

I think toward the end of the second quarter we were seeing an improvement in oil prices, as front months moved up to right around $50 a barrel, just over. Our primary private operators is Slawson, had curtailed some production in the very low oil price environment in the first quarter, and then we mentioned on our conference call last quarter, that our communications with Slawson indicated that those curtailments would ease a bit in the second quarter, and so as oil prices started to improve, especially toward the end of the second quarter, those wells were brought back online, but not fully back online. Just the choke was increased in the first quarter, and then just eased a bit in the second quarter. So we will continue to see as oil prices stay in this range, or hopefully a little bit higher, we will probably see those wells come back on a bit.

Great details, thanks buddy.

Thanks Neal.

Thanks Neal.

(Operator Instructions). Our next question from Scott Hanold of RBC Capital, your line is open.

Good morning guys.

Hey Scott.

Can you talk about some f the wells that come in that you don't take, and the ones that you pass on. Do those all not meet your threshold, or are you doing some high grading, considering where oil prices are, and/or maybe just looking to preserve liquidity for 2017?

The general answer is both, however, we really look towards internal rates of return, and the amount of data we have on which operators have been more effective and more consistent with their costs. And being more realistic with their costs, we are willing to look at some of the subjective information as well, but however, given how much data we have on each individual operator, we generally know how the rates of return are going to come in based on the certain area and based on the proposal and the proposed costs from that operator. So I would say for the most part it comes down to internal rate of return, but we will use certain information we have on certain operators to make even more informed decisions than just internal rate of return.

Okay. Understood. And as you look to 2017 and hedging, what is the plan? Obviously your hedges over the last say year have really done you guys well, in 2017 they start coming off, especially in the back half of the year, what is going to be your strategy going forward here?

Well as you can see from the release, we have added $50 swaps in first half of 2017, so we began to layer in swaps there, so about 40% of our production is hedged at, or oil production is hedged at $50 per barrel in the first half of 2017. We were as oil prices were towards the end of June, and very early July we are starting to get to their year highs, if you will. We had additional orders in, so we were continuing to look, to layer in additional hedges throughout 2017. One thing that you and those on this call who know us well, know that we are not cavalier with oil prices. When there is an opportunity to layer in hedges we do, and we usually do fairly aggressively, so we feel good about the hedges that we have layered in. We put those $50 swaps on during the second quarter, and those are in the money today obviously, but we will look to continue to layer in more hedges throughout the year, when the opportunity arises.

Are you typically looking only, say 6 to 9 months ahead, or would you be willing to extend even beyond that?

Well, as you know, when this cycle started towards the end of 2014, we had 24 months of $90 hedges out in the futures. So we had probably a longer dated $90 hedge book than most or all of the other of our peers. So if oil prices give us the opportunity to layer in hedges, and it meets, and we are able to lock in the returns from the capital decisions that we are making, we will layer in, we have been willing to layer in a year, 1.5 years, 2 years in the past. I don't see why that would change.

Okay. Thanks.

Thanks Scott.

Next question comes from Derrick Whitfield of GMP Securities, your line is open.

Good morning guys.

Good morning.

Following up on Neal's curtailment question, do you have a rough estimate on how much is still offline?

I would say that of the production that was offline in the first quarter, I believe it was around 1,600 barrels per day. I would say that, and I can get back to you with specifics, but I believe about 1,000 of that came back online.

That is exactly what I was looking for. And just from what you can see today, could you comment on the expected completion cadence in the second half?

Thanks for that question. We saw a few of our operators begin to mobilize frack crews in the second quarter as oil prices started to peak above $50. We just want to remain conservative with our guidance, as we look towards the end of the year because a handful of our operators, where we have wells that are in the drilled but uncompleted status, we are just trying to stay laser focused on when their plans are for completion. Several operators, one being Whiting, began to mobilize frack crews in the second quarter. And so they will open up a few of our drilled but uncompleted wells. Our DUCs in the third quarter. That is generally good news.

If we start to see more operators mobilize frack crews, for the purpose of getting ahead of the rush to get completion crews online to frack their uncompleted wells, we will continue to see, we think we will see maybe a more robust production and completion environment in the second half, however right now I think we just want to remain conservative, as we watch oil prices and watch our partners make these decisions. But Whiting, XTO and others have been mobilizing frack crews, so we are watching that. EOG as well.

Perfect and then just one last from me, Mike, with regard to Q2 impairment, was it specific to any certain area/operator, or kind of evenly spread across the board from what you can see?

Yes, this is Tom. It is even, we are a full-cost company. It is a calculation done off of SEC-PV 10 sort of reserves, I think the trailing 12 month price using that calculation was $43.12 per barrel, if I have got it right, and to the extent that the prices remain at that levels, and the average does not decrease any further you would not see any additional paramounts, but it is over the entire well inventory if you will.

Okay. Thank you. Very helpful, guys.

Thanks.

Our next question comes from Sean Sneeden of Oppenheimer, your line is open.

Hi.

Good morning, Sean.

Thanks for taking my questions. First I think gas capture rates across the Basin have certainly improved as we have gone along here. I think we saw it within your second quarter results here. How should we think about that trend for the second half of the year? Do you guys have any thoughts around that?

Well it certainly has improved. I mean in the second quarter you saw our gas production increase quite a bit. That was probably due more to the easing of curtailment, as well as wells that were shut in to frack protect kind of being returned to production. I think you will continue to see kind of marginal incremental improvement in gas recapture, but I don't think that is going to impact our numbers as much as you saw the jump quarter-over-quarter. Because as I mentioned it is really curtailments and really production that was returned.

Okay. That is fair. And then you guys kind of mentioned thinking a lot about best return opportunities, how are you guys thinking about just drilling returns within the existing portfolio, versus the roughly 20% IRRs on your bonds at this point? How do you kind of weigh the two?

Well, I think that when you do the math, obviously there are some attractive returns there, but nothing is more important to us right now I think than maintaining adequate liquidity. We noted in our comments that we have reduced our capital to kind of maintain that liquidity, and maintain the financing capacity. We currently believe I think that some level of drilling is required to ensure the liquidity and the positions for the upside when prices do recover. At present, you take a look at our cash flow and end market, and project it out at present. It does not leave a lot of discretionary cash flow for bond redemption, but it is something that to your point that we do kind of continue to look at. It is kind of a battle, if you will, with maintaining adequate liquidity, and then doing an adequate amount of drilling to ensure that we position ourselves, and maintain the value in the reserve base.

Okay. That makes sense. I guess kind of like on that thought, and i realize it is pretty early, but how are you guys conceptually thinking about your fall redetermination in the sense that how are you thinking about kind of reserves through mid-year, presumably prices have probably been somewhat of a benefit versus year-end, but how are you guys kind of thinking about that as it relates to the (indiscernible)?

Well as you mentioned, it is a little bit early, we continue to have discussions with our banks. It is early because they obviously have not set their price stacks. I think our banker has been complimentary with the quick actions that we took to reduce the capital spending, and the efforts that we have accomplished with respect to reducing the outstanding amount on the secured side. During the last redetermination. we really did not get a whole lot of credit for our hedging portfolio, because most banks roll off the first six months of hedging up to the date of redetermination.

I think that current commodity prices are higher than the recent lows, when we did the last redetermination but I really to be fair, I really don't have a real good feel until we get closer to October. I am not trying to dodge your question, I'm just trying to give you a bit of color.

No, I appreciate that. I think that makes sense. Maybe just one last one. I guess if we assume the strip plays out here for next 6 to 12 months or so, is it relatively fair to say that at a minimum your goal here is to try to maintain free cash neutrality, how you guys are trying to set the business up?

Yes I think that is exactly right. I mean our stated goal and a lot of our public comments is we are focused on liquidity, and maintaining that, and for the present we, unless some opportunity that changes our mind, but right now at present it is really to drill within discretionary cash flow.

Okay I appreciate it. Thank you.

Great thanks.

Our next question comes from Owen Douglas of Baird. Your line is open.

Hi, good morning. Thanks for taking the questions here. A lot of good ones have already been asked. In case we were to go through, I guess another 12 months or so of the current $40 to $50 type of price environment, it feels like you guys certainly have some options to live within cash flows, but how should we think about the game plan, and if we were to have a protracted kind of funk, for you guys funding capital spending for growth for when that rebound does appear?

Well, I think as we indicated in our public comments, we are keenly focused on maintaining liquidity, and the point strategies to protect and improve our financial position. We obviously follow kind of what is going on day-to-day in the marketplace, and as I know you're aware, we have near-term maturities, our secured debt coverage ratio is about 0.6 times, we have got good trailing four quarters interest coverage of 3.8 times, so that will provide us some flexibility I think in the near-term to kind of evaluate best solutions available for our shareholders. Just to redouble we will maintain our spending within discretionary cash flow, and just try to maintain value.

One other thing I will add to that, if you think about the wells that we are electing to participate in, in the core of the play, if we participate in a well that achieves a 25% internal rate of return, you can consider that borrowing base neutral. And so as we continue to participate only to those higher IRR wells, we are continuing to grow our reserve base, maintain our liquidity position, and then again the pure flexibility we have of dialing back, or dialing up our consent and drilling activity, is the most valuable asset here at Northern, and if things improve we can ramp up quickly, and if things stay lower for longer, we can stay very comfortably within cash flow for longer.

Okay. And looking differently now, so the market for buying acreage positions how is that looking? Be helpful if you can compare it to the prior quarter, or in that before?

I think one thing is we saw oil prices improve toward the end of the second quarter, that actually created more activity from Northern's acreage ground game scenario. July happened to be one of our better months when it came to acquiring acreage, at the beginning of the third quarter obviously, but we started to see prices improve which actually tightened the bid/ask spread on everything from 10 acres in the quarter of the play, or 100-acres, or a several million dollar asset, the bid/ask spread actually tightened when the oil prices improved. We think that our ground game, the what we do type of acquisition activity is fairly robust. It was in July, towards the end of July oil prices started to degrade a bit, but we continued to monitor the environment, and we think that our franchise as the clearing house for non-operated activity in Williston Basin, will allow us to really capture the opportunities as they come.

Sorry, can you specify this you mentioned the bid/ask spread tightened as pricing increased, was that a function of bid increasing but the asking the same, or both moving up in.

It was combination of two things. You see the price deck improved a bit which improved the bids, and then that just tightened up, that tightened up whole scenario where sellers now were more comfortable parting with certain assets. When it comes to Northern's ground game, it is acreage and AFE acquisition in the core of the play, and we are really good at it, and we just saw more activity in July than we did in second quarter, so we are looking at every opportunity, and it was fairly robust in July.

Okay. And sorry one final one from me. On this perhaps kind of goes back to my first question here a little bit. What do you think about the possibility of perhaps partnering with a financing provider for when that rebound comes about? Because I imagine that there is a bit of a timing lag between when banks give you credit for the improved pricing environment, and the initial capital outlay to participate in the wells?

I think if we just look at it holistically Northern is in good shape when it comes to bank group, and its liquidity position, and if we were to see some opportunity that was very substantial in size, we obviously would not make a commodity price bet on that asset, we would if we saw something that was very large, we would probably look to finance it off balance sheet. But generally speaking, we are in good shape now, and we are going to continue to execute our ground game.

Okay great thanks a lot, guys.

Thank you.

No further questions turn the call back over to Brandon Elliott for closing remarks.

All right Michele. We appreciate everyone's participation in the call, and your interest in Northern Oil and Gas. Michele will give you the replay information, and we look forward to talking to you guys either out on the road, or again soon. Everybody have a good weekend.

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