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Edited Transcript of NOG earnings conference call or presentation 2-Mar-17 4:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Northern Oil and Gas Inc Earnings Call

WAYZATA Mar 2, 2017 (Thomson StreetEvents) -- Edited Transcript of Northern Oil and Gas Inc earnings conference call or presentation Thursday, March 2, 2017 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Brandon Elliott

Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy

* Tom Stoelk

Northern Oil & Gas, Inc. - CFO

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Conference Call Participants

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* Scott Hanold

RBC Capital Markets - Analyst

* Neal Dingmann

SunTrust Robinson Humphrey - Analyst

* Sean Sneeden

Oppenheimer & Co. - Analyst

* Owen Douglas

Robert W. Baird & Company, Inc. - Analyst

* Jason Wangler

Wunderlich Securities, Inc. - Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Northern Oil & Gas fourth-quarter 2016 conference call. (Operator Instructions). As a reminder, this conference is being recorded.

I would now like to hand the floor over to Brandon Elliott. Please go ahead, sir.

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [2]

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Thanks, Karen. Good morning, everyone. We are happy to welcome you to Northern's fourth-quarter 2016 earnings call. I will read our Safe Harbor language and then turn the call over to Tom Stoelk for his opening comments and discussion of the financial results for the quarter, and then we'll take your Q&A.

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 measure 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 Tom.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [3]

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Thanks, Brandon. Good morning and thank you for joining the call today. I'd like to begin the call with a few operational and financial comments to provide some color as you review our earnings release, and then get to your questions.

Our production in the fourth quarter increased 2% sequentially over the third quarter, despite some severe weather in December that held us back a bit. Fourth-quarter production averaged 13,688 BOE per day and full-year production averaged 13,653 BOE per day. On a year-over-year basis, our total 2016 production declined just under 16%, which was driven by a reduction in capital spending over the last few years as we continue our strategy of disciplined spending and balance-sheet management as we seek to maximize the value of our asset base.

Drilling activity in the basin has picked up some, with approximately 40 active rigs in North Dakota. Our inventory of wells in process at the end of the year grew to 13.4 net wells, which is up 3.7 net wells from 2015 year-end and is reflective of operators continuing to push out completions. Approximately half of our uncompleted wells are operated by Continental Resources, who have recently indicated their intent to aggressively begin completing their in-process inventory during 2017. So as the weather improves, we expect to see a drop in our uncompleted well inventory.

Overall for 2017, we expect that our total production will be fairly flat with or perhaps modestly exceed our 2016 production. For the first half of 2017, we expect production levels may trend slightly down from our fourth-quarter levels, due to weather and the estimated timing of the completion of our in-process inventory of wells, with the first quarter more impacted by weather. We believe production in the second quarter may begin to rise, given better weather and as completions begin to increase. By the second half of 2017, we expect to see production increase to our first-half levels as more completions are brought online. So at present, we expect our production growth to be more back-half weighted in 2017.

We elected to participate in the majority of well proposals we received in the fourth quarter, with all wells that we elected to planned for enhanced completions. The higher consent election rate is representative of the fact that lower development costs and improvements in well productivity are driving higher internal rates of return at existing commodity prices.

Let me provide some data points on our improved well productivity. Our wells that were elected to and completed during 2016 are tracking better than a 900,000 EUR type curve or 29% higher than wells that were elected to and completed during 2015. Well productivity measured by average 90-day initial production rates on our new wells increased 47% in 2016 as compared to 2015. These improvements are largely due to the widespread adoption of enhanced completion techniques by the operators of our wells.

Our mix of high-intensity completions as a percentage of the total number of completions has ranged between 80% and 90% during each quarter of 2016. We believe the improvements we are seeing are representative of the quality of our acreage and the performance improvements on wells using enhanced completion techniques.

Let me turn now to capital spending, where we have been living within our cash flow. Our fourth-quarter CapEx came in at $34 million, which included an $8.9 million acquisition of producing properties underlying acreage during the fourth quarter. Excluding a fourth-quarter property acquisition, our full-year CapEx spending amounted to $75.6 million, or a 41% year-over-year reduction.

Our improved well performance is being complemented by a decrease in the average AFE cost per well, which averaged $6.8 million per net well during the fourth quarter of 2016 and $7 million for the year.

Our continued focus on a return-based capital allocation process allows us significant flexibility as it relates to our capital expenditures. This non-operated capital allocation advantage has allowed us to adapt quickly to changing conditions so we can be opportunistic to attractive acquisitions, while at the same time remaining disciplined in our balance sheet and liquidity management. We believe this advantage will benefit our shareholders through the current and future commodities 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.

During 2016, our discretionary cash flow exceeded our CapEx spending and allowed us to reduce our credit facility borrowings to $144 million at December 31, 2016. With over $200 million of borrowing base availability, we remain confident that we have sufficient liquidity to execute on our development plans and pursue accretive acquisition opportunities.

On the hedging front, we continue to protect our future cash flows from downside risk due to lower oil prices. We have certainly seen the impact that hedges can make in protecting our cash flows. As a reminder, for 2017 we have 2.5 million barrels with swaps at an average price of $52.55 per barrel and an additional 300,000 barrels hedged under costless collars with a floor price of $50 and an average ceiling price of $60.06 per barrel. In 2018, we have 813,000 barrels hedged at swaps at an average price of $54.40 per barrel and an additional 360,000 barrels hedged under costless collars with a floor price of $50 and an average ceiling price of $60.25 per barrel. We'll continue to look for opportunities to layer in additional hedges.

Several derivatives during the fourth quarter of 2016 increased our average realized price by $5.62 per BOE. Crude oil differentials were $7.46 per barrel below the average NYMEX price for the fourth quarter and $8.25 per barrel below the average NYMEX price for 2016. With significant pipeline capacity additions planned for later this year, we believe the Bakken differentials will range between $7 and $9 per barrel, with the potential for further improvements once pipeline additions are brought online.

LOE for the fourth quarter came in at $9.31 per BOE and $9.14 per BOE for the full year. We believe our LOE per BOE will remain within the range of $9.00 to $9.30 per BOE during 2017.

General and administrative expense was $3.7 million for the fourth quarter of 2016, compared to $5.8 million for the fourth quarter of 2015. The increase was due to $3 million in lower compensation expense, primarily driven by a reduction in incentive compensation, which was partially offset by a $900,000 increase in legal and professional fees. Cash general and administrative expense in 2016 amounted to $11.6 million, which decreased 9% as compared to 2015. We currently believe 2017 total general and administrative expense will range between $3.25 and $3.75 per BOE.

In last evening's press release, we provided our 2016 year-end proved reserve prepared under the guidelines prescribed by the SEC that totaled 54.1 million barrels of oil equivalent. 70% of those year-end reserves are classified as proved developed reserves and 86% are from crude oil. Although year-end 2016 proved reserves were 11.2 million BOE lower than year-end 2015 proved reserves, this was primarily due to a 15.7 million BOE decrease attributable to the lower SEC 2016 price deck compared to the SEC 2015 price deck. The decrease from the lower price deck was partially offset by 3.7 million BOE of favorable performance revisions and 8.4 million BOE in discoveries, extension, and other additions during 2016.

Due to lower commodity prices and lower capital spending in 2016, the number of proved undeveloped net well locations included in the year-end proved reserves was reduced to 32.6 net wells in 2016, due to the five-year rule requirements in the SEC regulations applicable to booking proved undeveloped reserves. As a non-operator, we are more limited in booking proved undeveloped reserves than operating companies because our development plans are based more on historical development activities than current rig count.

The key point I want to make is that we believe our inventory of undeveloped properties is far greater than the 32.6 net wells contained in our Ryder Scott SEC proved reserves.

In yesterday's press release, we included a section titled undeveloped properties inventory, which presents the net number of undeveloped locations that are economic at various pricing assumptions presented. For example, using price assumptions of $35 per barrel of oil and $1.67 per MCF for natural gas that was used in preparing the proved reserves under the SEC guidelines, we believe we have 218 undeveloped locations, as compared to the 32.6 undeveloped locations contained in the year-end SEC reserves.

The take-home point we are trying to make is that we have a multi-year inventory that far exceeds the undeveloped booked reserves contained in the reserve report prepared in accordance with the SEC guidelines.

In concluding my comments, I'd like to point out that our 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 elect to participate on a well-by-well basis. We continue to protect the value of our assets and potential for long-term growth of this Company by analyzing day in and day out the allocation of our capital. We continue to see a steady flow of inbound investment opportunities, and with the recent uptick in oil prices, we're beginning to see incremental increases in activity.

Most importantly, the activity we're seeing is dominated by wells located in the core of the play that are being complemented by enhanced completions. The increases we're seeing in well productivity and EURs give us confidence for 2017 and beyond. By maintaining capital discipline and protecting our liquidity, we are navigating this low price environment, at the same time preparing ourselves for future opportunities and value creation as we begin to work our way back to a more normalized activity level.

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [4]

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All right. At this time, we will turn the call over to the operator. Karen, if you could please give the instructions for the Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions). Scott Hanold, RBC Capital Markets.

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Scott Hanold, RBC Capital Markets - Analyst [2]

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Tom, can you discuss big picture the thought about becoming a little bit more active here as you go into 2017, understanding that the well economics have certainly improved, and when you step back and look at it, it sounds like a big nonop part of your Continental is accelerating. You guys are looking at more acreage acquisitions, and how do you balance that with where you see leverage at this point in time and where optimally you'd like it to go?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [3]

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Yes, sure. Obviously, really the timing of well completions is really going to drive the level of production we have kind of quarter on quarter, and we did try to signal in the script that over half of our current inventory is Continental. They are going to be pretty aggressive. They've indicated they've got five completion rigs, looking to add a couple of more. So that may drive production completions earlier or later, depending on how those are kind of scheduled.

We continue to see really an uptick in our in-process inventory. We had 13.4 net wells at the end of the year -- at the end of February. That's up another two net wells to about a 15.4 net well level. So, our inventory kind of continues to build, and so that's probably an indication that, depending on the level of completions, weather permitting, may exceed the 12 we give in our original guidance. The 12 basically is a snapshot of as it sits now, trying to make an educated guess with respect to it.

Clearly, we have the liquidity to really ramp that up with over $218 million of liquidity at the end of the year. We'll still be looking at accretive acquisition opportunities where we can either -- you saw us in the fourth quarter add about 350 barrels a day, doing an acquisition for a little over $8.9 million. We continue to see an increase in deal flow kind of coming in in smaller package sizes like that, so we'll continue to stay aggressively in the market doing that.

With the liquidity, I think you'll see us pretty much ramp up with respect to the activity, I guess, in the Bakken. When you take a look at our large acreage position of over 154,000 net acres, it's a good acreage position located in great parts of the basin. As that activity level picks up, we will -- we're capital allocators. We look at the rate of return. So as those AFEs come in and they [pencil] given adequate liquidity, which we're in an enviable position right now, we'll continue to participate. So I think to some extent as the basin activity goes and where those wells are located, you could see an uptick certainly in activity for us.

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Scott Hanold, RBC Capital Markets - Analyst [4]

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And Tom, the crux of my question, too, was obviously this is going to take a bit of a cash flow spend, based on what I'm seeing through 2017 and maybe 2018. And the balance-sheet leverage is still a little bit high. How do you reconcile the view of let's grow a little bit more, instead of we still need to fix the balance sheet a little bit at this point?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [5]

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To answer your question, Scott, it's a balancing act. Effectively, we're going to be mindful of taking a look at our liquidity and not step out really too far with respect to it on our spending levels.

We think we're -- personally, I think you can see a 15-, 18-, even a 20-well program and still, given the existing liquidity we have, would actually begin to return to driving growth for us in the high single digits, low double digits type area. So I think it's going to be kind of a balancing act.

We still have the strategic alternatives process that is ongoing. Our focus there really remains the same that we're looking at solutions that either grow our cash flow or reduce our debt. The fact that we don't have any near-term debt maturities, we're drilling within cash flow, we may slightly exceed that this year, but it's left us in a really good liquidity position, so we're in a pretty envious position from that standpoint and don't have our hand forced to really do anything. But to the point of your question, we're very mindful of it, but it's more of a balancing act at this point until we can maybe have some other solutions through the strategic alternatives process.

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Scott Hanold, RBC Capital Markets - Analyst [6]

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Okay. And you've already addressed my follow-up and that was, is there any update to the strategic alternatives, or maybe I'll just orientate the question to, when could we expect maybe some progress there?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [7]

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I can't really comment on that. Outside of what I've really said, that's about all I'm really comfortable kind of commenting on. Sorry about that.

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Scott Hanold, RBC Capital Markets - Analyst [8]

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No worries. Appreciate it. Thank you.

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Operator [9]

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Neal Dingmann, SunTrust.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [10]

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Everybody asks on the general sort of cost question. I guess my question on the Bakken is when you look at capacity out there, I see on the frack or completion side, it appears to me it's starting to get a little bit of tight. With Continental, I think it's running nine spreads and [sells] and [then or not], I guess, my question would be for you, how do you see that playing out for the remainder of the year? Is there still from what you all see adequate capacity? Are there partners of you all that do a little more -- you don't have to name them -- that you're concerned about more than others about that or not necessarily?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [11]

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I don't think we have a real burning concern at the moment, but to your point, I mean, I think service crew availability in the fracking -- and that's why you see us kind of signal in the script that we think that sequentially we may be down first quarter to second quarter. There were a number of completions that were originally scheduled in first quarter; you've seen those slide to Q2 and that's really being driven by, I think, access -- a little bit of weather, but most of it, I think, access to service crews and things like that.

I think it's something that the operators that we're dealing with, with Continental, Whiting, and Burlington, I think they are in good shape. They make up the bulk of -- or the clear majority of our in-process list, so at this point we're watchful of it, but I'm not hearing a lot of dialogue. I've seen a little bit of slippage from Q1 to Q2, but nothing other than that, Neal.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [12]

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Great news. And then, just lastly, when you're looking at sort of partnering with these companies, I know some of the AFEs that you're (technical difficulty), are you mostly seeing that, and you talked a little bit in your prepared remarks, [how are you necessarily] to participate with a little bit bigger interest or you're still staying the same overall?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [13]

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That's a great question. What we do with that acreage position a lot of times is kind of data mine the wells that we're in and we look for opportunities to roll up other interests, and some of those opportunities come where a lot of the AFEs that are coming in right now are in big unit sizes. So you'll get AFE for 16 wells, you get AFE for 12 wells, and some of the smaller owners out there just don't want to take that type of capital commitment.

We kind of data mine who the other owners are. We'll reach out, and on wells that we like, we actively try to roll up those interests. I think our average working interest overall is around -- a little over 7%, but you saw it decline this year to about 5.8%, just depending on where the drilling occurred within the core. But we continually kind of look for those type of opportunities because they are usually much lower cost for us to kind of get into a property that really we like the looks of it and the return of it.

So, it's kind of a function and timing of AFEs, to a large extent, but what's driving our ability to do that is the way some of the operators are really AFE-ing large numbers, groups of wells at one point in time, and you've got some smaller players that just don't have the capital capacity or desire to participate on that big of a basis. So, incrementally I think we have some opportunity to pick up interest as well as -- go ahead.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [14]

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No, that's what I was going to ask you. Go ahead and finish; I'm sorry.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [15]

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All I was saying, as well as taking a look at some opportunities like you saw us do in the fourth quarter, where we picked up 350 producing barrels, added probably about 10 net wells to our undeveloped inventory, most of that being unbooked at year-end. But just kind of mining the acreage that we hold and looking out for opportunities to pick up some additional accretive acquisitions like that.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [16]

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That's great news. Thanks for the details, Tom.

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Operator [17]

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Sean Sneeden, Oppenheimer.

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Sean Sneeden, Oppenheimer & Co. - Analyst [18]

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Tom, maybe just on your 2017 guidance, the 12 net wells you guys are talking about, can you give us a sense of what percentage of those are going to be those high-intensity completions that are still going to be consistent with that 80% to 90% or is it actually going to be higher?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [19]

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I think it's probably going to be more closer to 90% to 95%. I don't think they will all be enhanced completions, but clearly they'll uptick to probably 90% to 95%, virtually all, but not totally, I guess.

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Sean Sneeden, Oppenheimer & Co. - Analyst [20]

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Okay. And the guidance that you guys have put out there, is that based on still that 900,000 BOE type curve (multiple speakers)

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [21]

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No, we haven't baked in -- yes, we haven't totally baked in the impact of the enhanced completions. And you saw -- as part of the script, we basically told you that we had about a 29% increase in the average EUR. We talked about the increase in the IP rates of about 47%. We baked in about half of that increase in there, just trying to be a little conservative out of the gate.

Based on the way our well inventory ended up at the end of the year, we felt pretty good with 12. We're starting to see a little bit of a build in that and we have operators with a lot of dialogue. Virtually -- almost all of our operators are indicating their intent to aggressively start to complete and work down those in-process inventories. So, once we have a better line of sight with respect to where our completions and the timing of them look like, you'll see us update guidance with respect to that.

But to answer your question specifically, we baked in about half of that increase when we did our plan.

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Sean Sneeden, Oppenheimer & Co. - Analyst [22]

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Okay (multiple speakers). That's helpful. And then, just to make sure I'm thinking about kind of somewhat of an apples-to-apples comparison, can you give us a sense of, Q4 in particular, how many of those wells that you guys completed actually had a 900,000 BOE type curve or better?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [23]

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I think the average for 2015 was about -- let me look here real quick -- about 944,000, on average. I don't have the Q4 in front of me right now, but I would suspect that it's probably close to that range, and Brandon may be able to mine that information when you give him a call.

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [24]

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We can get back to you on that, Sean. Remember of the net wells that we showed you that we added in Q4, some of those were related to the acquisition that we talked about and the rest would have been what you are probably looking for as far as just D&C net well adds.

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Sean Sneeden, Oppenheimer & Co. - Analyst [25]

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Okay. I'll follow up with you off-line.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [26]

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Perfect.

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Sean Sneeden, Oppenheimer & Co. - Analyst [27]

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And then maybe just one last one, from a big-picture perspective. I think Scott had been asking about this, but if you look at the inventory that you guys have and put out in the release, on that $55 case, that's almost a 40-year drilling inventory at a 12 net well per year program. How would you guys think about -- and I know, Tom, you kind of talked a little about this, but how are you thinking about, big picture, trying to monetize that or pull forward some of the value that is embedded within that?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [28]

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I think as a non-operator we're going to really be driven by the drilling activity in the basin that occurs over our acreage position. So it's hard to kind of give you a specific answer to it.

I do think personally that with the uptick in oil prices, the build that you are certainly seeing in our in-process, the number of active rigs now is around 40 working in North Dakota, I think that you are going to see that, and the rigs are more efficient so they are basically drilling more wells with the same number of rigs, I think you're going to -- I don't think over the long term you are going to see us drilling 12 net wells per year. I think that my expectation is that as the basin activity grows you are going to see our development activity grow.

Back in 2014, I think we were on about a 40-well pace, and 2015, we were about a 18- or 19-well pace. This year, about an 11-well pace, so I think directionally it isn't going to be at a 12-well program. I think you are going to start to see Northern return more to a growth sort of situation with respect to it.

But the primary driver for us, at least initially, is going to be basin activity. It's going to be where that activity is occurring over our acreage, and then we are going to do what we do day in and day out and that's basically look at the AFEs, look at the rate of returns, and elect in if we have adequate liquidity.

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [29]

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Sean, this is Brandon. Just to follow up, and since you opened the door, I'll make a couple points here, the wells on 16 as far as the reserve report goes, those are probably being carried on the reserve report at about an 830,000 barrel EUR. Those wells are tracking about 15%, 16% over a 900,000 barrel type curve, so tracking about 1 million barrels.

So the good news is, yes, as Tom mentioned, we have not factored necessarily all that in. We hope the wells come on and perform that way. Certainly, the ones that we have done so far in 2016 have been pretty outstanding.

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Sean Sneeden, Oppenheimer & Co. - Analyst [30]

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Okay. That's helpful. I appreciate the follow-up. And then, Tom, if you don't mind just kind of following up on your inventory question, is there anything that would preclude you -- or have you guys considered looking at JVs to try to help monetize and perhaps bring in additional capital to expedite and pull forward some of that inventory?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [31]

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We've certainly considered it, but when you look at -- we're consenting because most of the activity, at least in 2016 and certainly in the fourth quarter of 2016, was in the core and we virtually consented to everything that came in the door.

So what that's saying is based on the existing acreage position that we had, everything penciled. Everything had a -- I think we had a high $6 million, $6.8 million, I think, cost. They penciled a little over a 30% IRR at existing well prices and existing strip. So it would -- we are not really having difficulty financing the opportunities we see.

And what we're looking for is more opportunities like we saw in the fourth quarter where we're picking up some producing acreage, some additional underlying acreage, which got us in some additional wells in process, increasing that inventory. And I think it's going to be the singles and doubles that we do like that that's really going to drive a lot of the growth.

And hopefully, we'll see some accretive acquisitions that are out there for us to be opportunistic and capitalize on, but we're pretty much electing everything that's coming in the door because they are penciling over a 30% IRR, at least right now.

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Sean Sneeden, Oppenheimer & Co. - Analyst [32]

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Okay. That's helpful. And then just lastly since, Brandon, you kind of jogged my memory on some of the well performance, but assuming that the 2016 outperformance versus the 900 type curve you guys were talking about continues in 2017, can you give us a sense of how we should think about that potentially playing through from a production standpoint? Meaning that should we actually be thinking towards the higher end or a better exit-to-exit rate growth. Any kind of sensitivity around that would be helpful.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [33]

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I think that we're kind of starting out with 12. We're implying to you, I guess a little bit, that as that inventory grows, that may move that 12 up to basically 15, 18 sort of levels.

If you get to like a 15 to 18 sort of level, you're going to be probably high single-digit 4Q-to-4Q sort of exit rates. If you go much north of that, you're going to be into double-digit growth. I think 4Q to 4Q, we are intentionally trying to come out conservative because we've seen some of the completion schedules slide a little bit from Q1 to Q2 and don't want to tell you guys, hey, we think we're going to have a blowout year and come with a large number of completions, and then they slide and then we're trying to explain to you what happened.

So we're trying to come out. We had a little bit of weather in the first couple weeks of January that also impacts kind of our thinking on it, but if basin activity continues to pick up overall acreage and our consent ratios stay the same, I think you are going to start to see what we termed a much more normalized sort of drilling and development schedule, and that isn't in the 12 range. That's probably closer to the 15 to 20 range. But without a clear picture right now of -- and Neal had asked it on his last question, about access to servicing crews, stimulation crews, and things like that, we're cautiously optimistic at this point, but don't want to step out too far.

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Sean Sneeden, Oppenheimer & Co. - Analyst [34]

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Great. And just a point of clarification, that high single-digit growth rate that you said on a 15 to 18 net well, that's based on the lower type curve, not a million (multiple speakers)

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [35]

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Exactly. That's based on -- you have stated it correctly.

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Sean Sneeden, Oppenheimer & Co. - Analyst [36]

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Okay. I appreciate the help, guys. Thank you.

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Operator [37]

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Owen Douglas, Baird.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [38]

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I wanted to ask a couple of quick ones here. So just as you guys think about the pacing of -- and I know it's out of your control a bit, some of this completion activity from Continental and the like, how are you guys expecting your borrowing base on that ABL facility to look as we progress through the year?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [39]

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We haven't received the bank price decks to fully evaluate where we think we'll be in the spring redetermination, but I would say that generally NYMEX pricing is up about 20% from the fall redetermination. When you couple that with the positive performance provisions we've seen in our reserves, it leads us to believe that we're in pretty good shape with respect to it. The banking market from the fall to now I think generally is in a lot better shape with respect to that, so I think there's more of a positive momentum there.

But I think with a 20% uptick in pricing in the last six months, the performance revisions that we're saying, they see the impact on our production, we're feeling pretty good about the borrowing base at the current time.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [40]

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So you guys think it could actually move upwards in that next redetermination is the right way to think about it?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [41]

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I think the way the banks are now, I'm not sure I'd say I think it is going to move upward. I think we're in good shape with where it is at the $350 million level.

Lots of times, you take a look at the total debt load that we have, banks, I think, are comfortable with maintaining commitment levels. Increasing commitment levels with debt metrics that are challenged probably is a little bit of a stretch.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [42]

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Okay. Understood. And perhaps that gets to sort of another thing, so as far as looking at the opportunity set out there, I guess it's really a bit of a two-part question. One is, what do you think -- based on your kind of views in terms of your minimum liquidity level and that near-term outlook and obviously you guys have a decent bit of downside protection with the hedge book as well, how should we be thinking about the parameters for any sort of acquisition which you [again] talked about? How big an elephant can you hunt down?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [43]

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And let me kind of come at it maybe from the other direction to tell you where I'm more comfortable with minimum liquidity levels, and then you can kind of do the math in between.

But I think given the existing level of our lower historical CapEx spending, I'd probably be comfortable with about $40 million to $50 million of available liquidity on our balance sheet. You know that we have about $218 million as of year-end, so maybe somewhere in between that. Obviously, our current CapEx program could have us a slight outspend of $20 million to $25 million.

But that's not really factoring in a lot of other factors. There's a lot of moving parts with that. You've got Dakota Access coming online; that's anticipated to probably add a couple bucks to the [raj] price, probably at least in the second half of this year. Where WTI is going to go, it's been kind of stabilized in Clearlake flat right now at about a $54 level, unchanged.

But maybe the answer to your question is kind of where I would start to get uncomfortable if we had less than $40 million to $50 million of available liquidity there. And you have seen us be fairly proactive with respect to the banks and our approach with that. We are not going to wait until we have an issue to basically approach them and things like that. If we have an acquisition like that, it's likely going to be more producing property and we'll be working with the banks, kind of managing, okay, how much credit are you going to give or advance on us on this acquisition?

If it was of any size, they would certainly be involved. I would want to know what kind of borrowing base I was going to get. We'd have a special redetermination and kind of [amp] that.

But to answer your question, I kind of answered it backwards, but I think my comfort level on liquidity is having about $40 million to $50 million, given the current activity level that we have, if that's helpful.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [44]

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Okay. Yes, that's some helpful information there and it actually gets me now to another question, which is I want to get your sense for how that AMD market looks, both as far as talking about your regular acreage style acquisitions, as well as to, I guess, now the assets with PDP?

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [45]

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Owen, this is Brandon. I think the good news is you are seeing a kind of a pickup in activity probably a little bit caused by a little bit stability in the oil price environment, so I think that is going to help the A&D market on a go-forward basis, so we're definitely seeing more stuff. Obviously, the big caveat is seller expectations and the ability for us to do a good accretive acquisition. I'll go back to what Tom said earlier (inaudible); we're hopefully optimistic there.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [46]

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We've seen an uptick in deal flow, especially with the uptick in oil prices, you've got a number of smaller players that hold between 300 and 1,500 barrels a day that have some interest in kind of testing the market. They may be looking to trade dollars because they've got an opportunity for some more of these enhanced completions, and so it's something -- those opportunities we continue to kind of aggressively mine.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [47]

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Okay. I remember a few quarters ago, I think it was, maybe it's even stretching back to about a year now, when asked the question, you indicated that their sticking point seemed to be that sellers were holding out for some pretty high prices. They wanted to pay for a full recovery in oil prices. Is your sense now that the level of competition from the bid side has increased and that's what's sort of getting the deal flow going? Or do you still think that the market is still available for buyers?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [48]

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I think it's a combination of things. I think that, yes, the uptick in price and they can maybe get a little bit better pricing or are willing to do.

The second thing is you are starting to see oil, at least recently, kind of stabilize, and so it gives us a little more confidence that we can go in. You saw us layer in some additional hedging in the fourth quarter where we layered in some additional 2017, as well as 2018, hedging in. We look at transactions like that as return based, so if they really pencil to an appropriate rate of return, we can go in and hedge those dollars.

And where before, I think, you had a little bit of the volatility, so you had a lot of uncertainty of where prices were at, sometimes it takes a few weeks to basically kind of come to terms, get agreements penciled, and you had certainly oil prices kind of moving up in large swings during that period, and I think that uncertainty caused a little loss in traction. I think now that it's at least stabilizing for the moment and headed in the right direction, we have more confidence in our ability to kind of hedge and close that transaction in just a little better pricing environment for the sellers as well. So I think that's probably more on the smaller transactional size that's really driving it.

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Owen Douglas, Robert W. Baird & Company, Inc. - Analyst [49]

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Okay. And finally here before I kind of pass it off to somebody else, just want to go back to some comments you made when I asked about the max deal size, et cetera. You talked about going to the banks, and I guess if you are acquiring producing properties here, you can get some ABL-eligible financing here. But talk to me about how you think about rounding out that capital. Could you see the high-yield market? Could you also see equity issuance? Can you sort of talk to me about some of these?

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [50]

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It's hard to talk speculatively about how we would do some things. There's -- given the RBL and the low rate of interest on that, that would be the optimum way for us to do that. Kind of given where our stock price is now, we've had some interest where people have made inquiries with our ability to basically -- they would like to trade in and take a position in our stock because they think it's fairly well priced and has a lot of upsides, so we'd look at it.

From a high-yield standpoint, I don't know. We'd have to look at the transaction. It would have to be awfully attractive for us to maybe go there, I think. But it's hard, other than the comments I've made, to really speculate on something that really hasn't happened. But we've got adequate liquidity, so we would probably take it out. If it was of some size, we'd have to look at it, I guess. Sorry I can't give you any more clarity than that on it.

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Operator [51]

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Jason Wangler, Wunderlich.

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Jason Wangler, Wunderlich Securities, Inc. - Analyst [52]

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I was just curious -- and you talked about the bumping of enhanced completions. Those ones that aren't enhanced completions, whether it's the idea from the operator, which you may not be able to speak to, of why not to use it or, on your side, why to move forward, obviously rate of return is the focus. Just kind of the thought of is it a certain area or a certain operator that's not necessarily moving to that side yet and just where you think that's going (technical difficulty) it keeps moving higher.

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Tom Stoelk, Northern Oil & Gas, Inc. - CFO [53]

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I think it's a combination of a couple things. Sometimes it's operator is probably the primary, and then I think just the geology, the composition of the rock. They just don't see the perceived benefit with respect to that.

You are beginning to see some commentary, at least in the calls I listen to, the term being thrown around, extended core, and so you are starting to see some people prospect a little bit around some of the edges, using some of the bigger fracks, more sand, to see if they can get core type EURs there, and we are watching that very closely. If it pencils, we'll participate. Usually, our participation in those areas may be at a lower level, 1% or 2%. What it does is it allows us to get a little bit of intelligence, have access to the data as we kind of evaluate other opportunities and things like that.

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Jason Wangler, Wunderlich Securities, Inc. - Analyst [54]

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Great. That's all I had. I'll turn it back. Thank you.

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Operator [55]

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Thank you. And that concludes our question-and-answer session for today. I'd like to turn the conference back over to Brandon Elliott for any closing comments.

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Brandon Elliott, Northern Oil & Gas, Inc. - EVP Corporate Development & Strategy [56]

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All right. Thanks, Karen, and thanks, everyone, for their participation and their interest in Northern Oil & Gas.

Just as a quick reminder, as we mentioned in our press release we will be at a couple upcoming conferences at the end of March and the first of April, so make note of that that we will be on the road then. Karen, with that, you can give the replay information and we look forward to talking to everybody next quarter, if not sooner. Thanks.

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Operator [57]

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Certainly. Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program and you may now disconnect. If you would like to access the replay of the conference, you may dial 855-859-2056 and enter the access code 73314817. Thank you.