Northern Oil & Gas, Inc. (NYSEMKT:NOG)
Q2 2016 Earnings Conference Call
August 05, 2016 11:00 AM ET
Brandon Elliott - EVP
Mike Reger - CEO
Tom Stoelk - CFO
Neal Dingmann - SunTrust
Scott Hanold - RBC Capital
Derrick Whitfield - GMP Securities
Shawn Smith - Oppenheimer
Owen Douglas - Baird
Good day, everyone, and welcome to Northern Oil and Gas Incorporated’s Second 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.
Thanks, Michelle. 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 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 including, 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'll 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 few highlights and accomplishments from the second quarter then turn the call over to Tom Stoelk, our CFO, to cover the financials. Throughout 2016, we have continued to focus on our 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 an 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 our strong liquidity position throughout the 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 and 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 the 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 and 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 by 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 that as 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 and spending just as quickly as it was reduced. Given how the year had 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 has 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 perceiver 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’s I am going to cover some of the financial highlights from the 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 the low price commodity environment, we’ve reduced our 2015 capital expenditure by 76% as compared to the prior year, which has lowered than number of new wells we’re 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 the new wells has improved, the effect on our production levels has been largely offset by national decline of oil and gas production due to low 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 the first quarter 2016, which drove the 3% sequentially 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 is down approximately 21% on a year-over-year basis. The decrease was due to low commodity prices and reduced hedging levels as compared to the same period a year ago. Partially offsetting the lower commodity prices was an improvement in the average oil differential to NYMEX WTI benchmark, which average $8.08 per barrel in the 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 $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 full price changes we recognized a non-cash mark to market derivative loss of $30.5 million in the second quarter of 2016 compared to $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 cost was driven by lower work over and maintenance cost and a smaller tax base for production taxes which was partially offset by lower production levels and higher number of net producing wells.
General and administrative expense was $4.6 million in the second quarter of 2016 as compared to $4.3 million in the comparable quarter last year. General and administrative expenses for the second quarter of 2016 was comprised $3 million of cash expenses and $1.6 million of non-cash expenses. Cash, general 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 the first-half of 2015. Our capital expenditures during the quarter totaled $16.5 million, the breakdown of the total is as follows; approximately $14.4 million of drilling and completion capital; we concludes capitalized work over expenses; $1.3 million on acreage and other acquisition activities; and $800,000 of capitalized interest in other capitalized costs. We continue to see cost reductions in the new well proposals being submitted which have recently ranged in the $6.5 million to $7.5 million area. We currently plan on seeking our capital spending for the year within discretionary cash flow.
Turning to liquidity, we ended the quarter with only $133 million of borrowings in our credit facility, which provides us with $218 million of available borrowing capacity. We currently have no near term maturities of our debt, maintaining a solid hedging position and remain well positioned from a liquidity perspective executed in 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 protect our balance sheet.
And concluding comments I’d like to point out that our asset base is essentially held by production and has 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 with highest rate 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’re 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 this low price environment and at the same time preparing ourselves for future opportunities and value creation.
At this time, I’d like to turn it over to the 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.
I am just looking to the difficult slide you have, it's still dictating well locations and wondering when you said you continue obviously just to go out for the high returns. Just wanted to make sure on that it shows prior years including ’15 all the way to all the Northern leasehold, I am just wondering when you look at that area, how should we think about between volumes Montreal, McKenzie, that entire map. Are there pockets there? Or again is it just -- how should we think about core areas that you’re really targeting there?
I think just generally and then I’ll get more specific if you to take the big four counties, McKenzie, Williams, Montreal and Dunn, I think those are generally going to be the core counties and then there is core areas within those four counties. One thing I’ll caveat that with is it all depends on costs. Certain operators have lower drilling cost and completion cost and other operators, certain operators are more efficient and effective than other operators.
So for us given the incredible amount of data we have and the history we have now over 10 years participating in the Williston. We know who is going to perform better and in what areas. But there is no question Southern Montreal County is core, Northern McKenzie County is core, Northern Dunn County and then Southeast Williams is going to be core. So, there was pretty simple mapping, but it all just comes down to which operators have lower costs and who is more efficient and more effective.
And then just lastly, curtailments I know couple of the privates were doing that, I don’t know if a couple of the publics’ for as well, is that still probably [indiscernible], Mike?
I think toward the end of the second quarter, we were seeing an improvement in oil prices at front month, moved up to right around $50 a barrel just our primary private operators to often 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 was so often 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 chunk increased in the first quarter and then eased a bit in the second quarter. So, we’ll continue to see as oil prices stay in this range or hopefully a little bit higher we’ll probably see those wells come back on a bit.
Our next question comes from Scott Hanold of RBC Capital. Your line is open.
Can you talk about some of the wells that come in that you don’t concern 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 are going 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 cost and being more realistic with their cost. We’re willing to look at some of the subjective information as well. But however, given how much data we have in each individual operator, we generally know how the rates of return are going to come in based on certain area and based on the proposal and the proposed cost from that operator. So I would say for the most part it comes down to internal rate of return but leaves certain information we have on certain operators to makes more important decisions than just internal rate of return.
And then as you look 2017 in hedging, what is the plan? Obviously your hedges over the last year have really done you guys well, in ’17 they start come off especially in the back half of the year. What is going to be your strategy going forward here?
As you can see from the release, we added $50 swaps in the first-half of ’17 to begin the layer in swap there, so about 40% of our production is hedged our oil production is hedged at $50 a barrel in the first half of ’17. We were as oil prices were towards the end of June and very early July, which starting to get to their year highs if you will. We have additional orders in hand. So we were continuing to look to layer in additional hedges throughout 2017. So one thing that you and those on this call who know us well know that we earned capital there 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, hedges we’ve layered in. We put those $50 swaps on during the second quarter and those are in the money today obviously, but we’ll look to continue to layer in more hedges throughout the year when the opportunity arises.
Are you typically looking only the six to nine months ahead, or would you be willing to extend even beyond that?
Well, as you know when mid cycle started towards the end of 2014, we had 24 months of $90 hedges out in the future. So, we had probably a longer dated $90 hedge book than most or all of the other -- of our peers. And so, if oil prices give us the opportunity to layer in hedges and it meets and as -- and we’re able to lock in the returns from the capital decisions that we’re making. We’ll layer in -- we’ve been willing to layer in year, year and half, two years in the past, I don’t see why that would change.
Our next question comes from Derrick Whitfield of GMP Securities. Your line is open.
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's around 1,600 barrels a day. I would say that -- and I can get back to you with very specifics. So I believe about 1,000 of that came back online.
That’s exactly what I was looking for. And just from what you can see today, could you comment on expected completion cadence in the second half?
Thanks for that question. We saw few of our operators begin to mobilize for our crews here 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’re just trying to stay laser focused on when their plans are for completion. Several operators one being Whiting began to mobilize frac crews in the second quarter. And so they’ll open up a few of our drilled but uncompleted wells, our ducks in the third quarter. That’s generally good news.
If we start to see more operators mobilize frac crews for the purpose of getting ahead of the rush to get completion crews online to frac their uncompleted wells, we’ll continue to see -- we think we’ll 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 we watch our partners make these decisions. But Whiting [XPO] and others have been mobilizing frac crews so we’re watching that.
And then just one last from me Mike, with regard to the Q2 impairment, was it specific to any certain area/operator or kind of evenly spread across the board from what you can see?
This is Tom. No, it's even work for cost company it's calculations on SEC PV10 shorter reserves I think the trailing 12 month average price using that calculation was $43.12 per barrel is I got it right. And to the extent that prices remain at that level so the average doesn’t increase any further. You wouldn’t see any additional impairments but it's over the entire well inventory if you will.
Our next question comes from Shawn Smith of Oppenheimer. Your line is open.
First, I think your gas capture rates across the basin of certain improved as we gone long-term, 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 increased quite a bit. That was probably due more to the easing of curtailment as well as wells that were shutting to frac protect being returned to production. I think you’ll continue to see marginal incremental improvement in gas recapture. But I don’t think that’s going to impact our numbers as much as you saw the jump quarter-over-quarter as a net and it's curtailments and really production that was returned.
And then you guys mentioned speaking a lot about best return opportunities. How are you guys thinking about just drilling returns within the existing portfolio versus roughly 20% IRRs on your bonds at this point? How do you weigh the two?
Well, I think that when you do the math obviously there is some attractive returns there, but nothing is more important to us right now I think than maintaining adequate liquidity. We know that in our comments that we reduced our capital to maintain that liquidity and maintain financing capacity. We currently believe I think that some level of drilling is required to ensure that liquidity and position us for the upside when prices do recover.
So at present you take a look at our cash flows and market -- and projected out at present, it doesn’t leave a lot of discretionary cash flows for bond redemption. But it is something that to your point that we do continue to look at. But it's a battle if you will with maintaining adequate liquidity and then doing an adequate amount of drilling to ensure that we could position ourselves and maintain the value in the reserve base.
On that thought and I realized it's pretty early. But how are you guys conceptually thinking about your fall redetermination in the sense that how are you thinking about reserves through mid-year presumably prices have probably been somewhat benefit versus year-end. But how you guys are thinking about that as it relates to it?
As you mentioned, it is little bit early. But we continue to have discussions with our banks. It's a little early because they obvious haven’t set their price tags. I think our bank group has been complementary with the quick actions that we took to reduce the capital spending and the efforts that we’ve accomplished with respect to reducing the outstanding amount on the secured side.
During the last redetermination, we really didn’t get a whole lot of credit for our hedging portfolio, because most banks roll of for six months of hedging up to the date of redetermination. I think the current commodity prices are higher than the recent low when we did the last redetermination. But I really, to be fair, I really don’t have a real good feel until we get close to October. I am not trying to dodge your question, just trying to give you a little bit of color.
I appreciate that, it does make sense. And just one last one, I guess we have seen stripe kind of plays out here for the next six 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 flows neutrality? How you guys are trying to step the business up?
I think that’s exactly right. I mean our stated goal and a lot of our public comments is we’re focused on liquidity and maintain that and for the present we less up some opportunity that changes our mind. But right now at present it's really to drill within discretionary cash flows.
Our next question comes from Owen Douglas of Baird. Your line is open.
A lot of drillings already been asked, but thing about in that pool differently. In case we were to go through another 12 months or so of the current 40 to 50 type of price environment, feels like you guys certainly have some options to live within cash flows. But how should we think about the game plan that we were to have to protracted funk for you guys funding capital spending for growth or when that rebound does appear?
I think as we’ve indicated in our public comments, we’re keenly focused on maintaining liquidity and deploying strategies, protecting and improve our financial position. And we obviously follow what’s going on day-to-day in the marketplace. And as I know you’re aware, we still have year for maturities, our secured debt coverage ratio is I think about 0.6 times, we’ve got good trailing four quarters interest coverage of 3.8 times. So that provide us some flexibility I think in the near term to evaluate the best solutions available for our shareholders. But we just redouble, we’re going to maintain our spending within discretionary cash flows and we just tried to maintain value.
One other thing I’ll add to that is 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 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’re continuing to just 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 we will if things improve we can ramp up very quickly. And if things stay lower for longer, we can stay very comfortably within cash flows for longer.
And looking a little differently now, so the market for buying acreage position, how is that looking? And if you can -- it will be helpful also if you can compare it to the prior quarter or that before?
I think one thing as we saw oil prices improve toward the end of the second quarter that actually created more activity from Northern acreage ground game scenario. July happened to be our -- 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 tightens a bit spread on everything from 10 acres in the quarter in the core of the play, or 100 acres or several million dollar asset, but the asset spread actually tightened when oil prices improved.
So we think that our ground game what we do of type of acquisition activity is fairly robust. It was in July towards the end of July oil prices start to degrade a bit, but we’ve continued to monitor the environment. And we think that our franchise as the current house for non-operators activity in the Williston Basin will allow us to really capture the opportunity to pick up.
Can you express the lines of the segments that didn’t have freight tightening, does price increase, was that a function of the bid increasing but the asset being same or both moving up?
It was a combination of two things. You see the price that improved a little bit, which improved a bit and then that’s just tightened up the whole scenario where stellar now were more comfortable partnering with certain assets. But when it comes to Northern’s ground game, it's acreage and the acquisition in the core of the play. And we’re really good at it and we saw that -- we just saw more activity in July than we did in the second quarter. So, we’re looking at every opportunity and it was fairly robust in July.
And one final one from me, this perhaps kind of goes back to my first question little bit. What you think about the possibility of perhaps partnering with a financing provider for when that rebound comes about? Because you mentioned that there is a little bit of the timing lag between when banks give you credit for the improved pricing environment, and the initial capital outlay to participate in wells?
I think if we just look at it holistically, Northern is in pretty good shape when it comes to its bank group, it's liquidity position. And if we were to see some opportunity that was very substantial in size, we obviously wouldn’t 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’re in good shape now. We’re going to continue to execute our ground game.
There are no further questions. I’d like to turn the call back over to Brandon Elliott for any closing remarks.
All right Michelle. We appreciate everyone’s participation in the call and your interest in Northern Oil & Gas. Michelle, will give you the replay informations and we look forward to talking to you guys either out on the road or again soon. Everybody have a good rest of the weekend.
Thank you. Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program and you may all disconnect. Everyone, have a great day.
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