Northern Oil and Gas Inc
NYSE:NOG
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Northern Oil and Gas Inc
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Greetings, and welcome to the Northern Oil and Gas Third Quarter 2019 Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded.
It's now my pleasure to introduce your host Brandon Elliott. Please go ahead, sir.
Thanks, Kevin. Good morning, everyone. We're happy to welcome you to Northern's Third Quarter 2019 Earnings Call. Before we get to the results, let me cover our Safe Harbor language. 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 may discuss 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 this morning.
All right, during our call today, I will make a few summary comments before turning the call over to Nick O'Grady for his remarks; Northern's Chairman, Bahram Akradi is going to comment on the ongoing consent solicitation, our exchange and strategy moving forward. And finally, we'll open it up for the Q&A portion of the call. In addition to those I mentioned, we also have Chad Allen, our Chief Accounting Officer; Adam Dirlam, our EVP of Land; and Jim Evans, our VP of Engineering in the room with us as well.
Northern had a solid quarter with production up 17% sequentially and 53% year-over-year to 3.75 million barrels of oil equivalent, averaging 40,786 barrels of oil equivalent per day. This production is despite continued curtailment and shut-ins that we have estimate reduced our production by approximately 4,500 barrels oil equivalent per day during the quarter. This was almost 2,000 BOE per day worse than our initial forecast.
Offsetting those headwinds has been the success we have had over the last six to 12 months in our ground game acquisitions. These acquisitions have helped offset the curtailed production as some of the net well additions from prior ground game acquisitions have outperformed both our estimates and initial production and have come online slightly ahead of our initial plan. Also, the VEN Bakken acquisition that we closed early in the third quarter has been slightly outperforming our initial forecast.
Our hedging program continued to perform as designed and help to protect us from recent volatility in the oil markets. Natural gas and NGL prices were particularly weak during the quarter. As we mentioned last quarter we think infrastructure expansions planned for late this year and into 2020 will bring welcome relief both on the oil volumes we continue to see affected by the constraints, but also in the ability to move and get better pricing on the natural gas and NGL side.
Lease operating expenses were up 5% sequentially to $8.62 per BOE. Some of this increase was expected as we had indicated the VEN Bakken assets do have a slightly higher LOE than our previous corporate average. But there was also some negative effects on fixed costs due to the curtailments and shut-ins. Net-net we still expect our guidance of $8 to $8.50 per BOE for the year to be a reasonable expectation.
Again this quarter we tried to focus our capital expenditures on the highest return opportunities. We consented to about 80 gross wells during the quarter and non-consented six. The wells we non-consented did not meet our investment hurdles, mainly as a result of one operator targeting a Three Forks formation that did not meet our hurdle rate. In this instance, we were able to consent to the middle Bakken wells and retain our optionality in future well proposals to each formation.
Our proactive capital allocation decisions should augment our returns and cash flows moving forward. The positive cash flow we have generated after organic drilling and development capital expenditures continues to be focused on generating the best possible returns, and importantly focused on increasing our cash flow as we look to the culmination of this next step in our process to position Northern to begin returning capital to shareholders in 2020. Bahram will cover this in his remarks momentarily.
Now let me turn the call over to Nick to cover some of the financial highlights and our updated guidance.
Thanks, Brandon and good morning from an icy Minneapolis. I have a few highlights to go over this quarter starting with a quick summary on Northern's financial performance. Adjusted EBITDA for the quarter was 124.4 million, up sequentially from the second quarter. This is driven by higher production primarily from our VEN Bakken acquisition, offsets as prior mentioned, the production curtailments and very poor realized gas prices, and the carrying costs of fixed LOE from wells that have yet to return to sales.
The fog of war and the basin driven by curtailment has been frustrating. However, the end game remains the same, the significant processing capacity coming online, a huge swath of wells turning to sales and improvements in NGL takeaway that should lead to improve pricing in the long run.
Cash G&A came in at $1.15 per BOE this quarter slightly higher than the second quarter, the main driver was over 1.3 million in transaction expenses associated with the VEN Bakken acquisition. Excluding these onetime items, G&A was actually lower quarter-over-quarter. Oil differentials are around the midpoint of our guidance this quarter at around $5.5 per barrel. This is in spite of significantly narrowing Gulf Coast differentials.
While shut-ins combined with a higher LOE at VEN Bakken drove LOE up sequentially to 862 per barrel. We expect this to moderate in coming quarters as field issues normalize and newer wells turn to sales. We expect no changes to guidance.
Our organic D&C spend was approximately 80.1 million and we turned a total of 13.3 net wells to sales, 10 of which were organic and 3.3 associated with the ground game acquisitions. With respect to discretionary capital, we allocated approximately 32.9 million this quarter, made up of money 9.9 million for ground game acquisitions, and 23 million in total ground game associated development capital. The ground game investments continue to have some impact on our production levels this year. But we should start to see some significant impact or volume in cash flows as we close out 2019 and into early 2020.
Now, to guidance, we're leaving our fourth quarter production guidance intact based on the current levels of activity, and the trajectory going into 2020 remains the same subject to winter weather of course. For our LOE guidance, it remains 8 to 8.50 despite the curtailments keeping LOE elevated into the third quarter. As of now we expect modest improvements in the fourth quarter.
We are changing our tax guidance to 10% on net crude sales and $0.075 per Mcfe, which more closely approximates the actual North Dakota tax code. This should allow us to be more accurate in the future as the old percentages move around too much depending on the spread between gas and oil prices.
Cash G&A guidance has been maintained to a range with a high end of $1.15 per BOE. We may incur some costs with a recently announced consent and tender process that cannot be capitalized, but we'll make sure to call them out if it should happen.
On the hedging front, we've continued to make progress, particularly in 2021. On differentials, we expect oil differentials to be wider in the fourth quarter as production curtailments begin to roll off and gas realizations may remain weaker than normal until the large NGL takeaways complete in the first quarter of 2020.
On the capital front, we remain on track and we're still guiding to 33 to 34 organic net well additions for 2019. We do think however, given we have seen a few net well additions come online earlier than expected. We could be towards the high end of the organic spend.
The ground game has remained active, but we are trimming the top end of our 2019 acquisition spending to a maximum of $40 million as we believe here in November our spending for the year is largely complete. We're widening the ground game D&C CapEx for the same reason I just mentioned with respect to the organic D&C spend. We've continued to be surprised to see operators turning wells to sale faster and in many cases accelerating development.
With investors still focused on free cash, I want to make one thing clear; we are generating free cash flow on an organic basis. The most important question is what are we doing with it? The acquisitions we have made with this cash are purposeful and driven towards building our cash wedge. And with our consent process almost complete, we can now focus on harvesting of this. With many participants scrambling to cut capital in any way, shape or form, we are counter-cyclically investing in those capital projects, high return wells in process that will generate cash within a few quarters.
Given the choice between 20% to 100% risk adjusted returns versus paying down four and a half – 4% to 5% bank debt there's been an easy capital allocation decision for us until such time that we were in a position to return capital meaningfully to shareholders, and that time is coming in 2020. Given our success and robust levels of activity, our ground game particularly for wells and process is likely to slow and mainly to focus on projects for 2021 and beyond. 2020 will be a time to harvest all the success we've had this year both in terms of debt retirement and shareholder returns.
Thanks and let me turn it over to Bahram.
Thanks Nick. Last two years, NOG has been focused on recapitalization process, including reducing our overall debt to EBITDA. At the same time, we have been growing the company's free cash flow and reserves. This has allowed NOG to take this next step, which is to significantly grow RBL and reach an agreement with our bond holders for the consent necessary to both get this larger RBL, but also to start paying dividends to our shareholders. Our plan the next several years is to continue to reduce our more expensive debt, reduce fixed cost and preparing NOG to be as strong even in a $40 oil price environment.
The deal we are planning to close in the next couple weeks will improve our readiness for a low oil price environment. And in every step we take over the next 12 months. We will continue to move us in that direction. We're preparing for what we like to call internally the one third doctoring, just how we see capital location for our free cash flow. Our plan over the next 12 months are to one, further reduce our debt, we would allocate approximately one third of our projected free cash flow, plan two, plan up to one third of this free cash flow for dividends and share buybacks. And three, use the other third to take advantage of accretive acquisitions.
Additionally, we will work to find other creative ways to reduce more debt if the opportunity presents itself. My goal is to reduce all of our debts expense to an interest rate closer to that of our RBL. This will allow NOG to pay a sustainable and growing dividend. I want to thank NOG's executive team, our board members, Angela Gordon and the rest of our bondholders. I also want to thank our advisors, Wells Fargo, RBC and the rest of the banks which have committed and participated in our RBL. It's taken all of these people to accomplish what we have gotten done over the last 60 days.
On our last earnings conference calls, I permitted to initiate these discussions to see if we could put a win-win deal together. I'm very happy, proud and grateful that we've been able to accomplish all this. I'm excited to announce in the near future where we expect to start our first regular cash dividend. My goal is to start a dividend for the first quarter payable in April. I also want to thank all of our shareholders who have been patient until we were ready to do this methodically and thoughtfully, and with the best economic terms possible.
With that, I will turn it back to Brandon.
Thanks Bahram. And with that, I will turn the call over the operator for the Q&A portion of the call. Kevin, if you could please give the instructions for the Q&A. We'll take those questions now.
Absolutely, we'll now be conducting a question-and-answer session. [Operator Instructions] Our first question today is coming from Phillips Johnston from Capital One Securities. Your line is now live.
Hey guys, thanks. First question is just on the topic of maintenance CapEx and PDP decline rates. I think on the March call you estimated PDP decline rate for 19 was somewhere around 35% or so that it was expected to moderate in 2020. Plus, you've obviously worked in the Flywheel assets as well as some new ground game assets. So just wanted to get an updated estimate of the PDP decline rate going into next year, and also just on the same topic, about how many net wells per year and how much annual D&C CapEx would be sort of required to keep production flat at your fourth quarter rate of roughly 40,000 a day.
Phillips this is Nick, given the amount of growth we probably will see in the next few quarters I would keep our decline rate, probably still in that mid 30s. And that's just because obviously we've been allocating capital towards these wells in process and then you'd expect it to moderate out. I think the answer on the sustaining portion is a little bit tricky around timing, which is that from our fourth quarter, obviously, it depends on how much growth we see in the first half of next year to where you exit. So I can give you a scenario that would certainly – I would just tell you that I think internally, we would look at it and say, certainly on an annual basis, we could make – we could match that fourth quarter with as little as $200 million.
If you wanted to exit with some growth, I think that the goalpost or something like between $200 million and probably $325 million, depending on where you want to go into 2021. But I'd also add that what's important about that in that trajectory is about how much capital do you want to allocate in late 2020 towards 2021 growth and if those projects meet our hurdle rates. And so I think the answer is to produce 44,000, 45,000 barrels a day, next year will be – we can do it with as little capital, like I said as $200 million. And if we wanted to drive a lot of growth would push through into 2021 that would head probably towards the low three hundreds.
Okay, that's good color. Thank you. And I guess you mentioned the likelihood of moderating acquisition activity next year. Obviously, it's early, but what do you think the ground game related spending will shake out at least directionally versus the kind of 70 million to 110 million or so this year?
Yeah. So I mean, I think that on the – I think that if you use the goalpost of around $200 million on the low end, that's probably almost all organic spend with little to no ground game. Obviously, what we've seen, and remember that's going to spool up all and that organic will kind of include all the capital that's already been allocated this year towards those projects. So the question will be how much money do you want to spend to both either drive additional growth and I think we're not quite there yet in terms of how much we want to do that. I mean, I think we want to watch this strip in 2021 and make sure that we're going to earn adequate returns for any capital. I mean, we don't really target a growth rate, right, we target return on capital employed. And so it really comes down to Jim and Adam and our team here of seeing whether those projects meet our hurdle rates. But I would say that let's call it 200 million to 325 million for this sort of base well plan towards what I discussed. And then something between $50 million and $75 million would be that total ground game spend and when I say 200 to 325, I'm including it all is one bucket, which would mean all organic spend, all acquisition costs and all D&C associated with that.
Okay, makes sense. Thanks Nick.
Thanks.
Thank you. Our next question today is coming from Derrick Whitfield from Stifel. Your line is now live.
Thanks.
Good morning Derrick.
Thanks. Good morning all. Perhaps for Brandon or Nick, could you speak to the degree of curtailment assumed in your Q4 guidance and how we should think about your x rate or early 2020 production rate as these curtailments are alleviated?
We got about 2000 barrels a day forecast in Q4, right? I'm looking at our engineer to make sure I'm not lying. But so about 2,000 barrels a day, obviously, what's tending to happens, we've been turning a lot of wells to sales, the fourth quarter will be similarly pretty robust. And you're getting to the point in which the new well bores are going to really overwhelm any curtailments that we see. I mean, I'd say that in any given quarter, we always have some shut-ins offset fracks, things like that and we always model this. I think in the third quarter, there were a handful of a higher working interest units that were pretty acute and did take us by surprise a little bit. But we're kind of getting towards the tipping point Derek, where the amount of activity coming online should overwhelm any particularly acute shut-ins that we see.
Sure. Here is my follow up for you, Nick, could you speak to the average rate of return in plot in your Q3 ground game acquisitions and just give us a sense as to how that opportunity set looks at present?
I'll let the true expert Adam here answer that.
Yeah, anywhere from 20% to 50% is kind of what we're looking at. And I mean, the opportunities sets continue to persist since late 2018. And so we've been busy this year, picking off certain opportunities that we like, allocating it towards the operators in the areas that we like, and frankly, haven't necessarily seen it slow down. So we're certainly excited about what we've been able to accomplish in 2019 in order to kind of spool up 2020 and going into 2020. Like we said, we'll probably lay off the gas in that regard, but continue to kind of keep our ears at the ground for opportunities.
Helpful, thanks for your responses.
Thank you. Our next question is coming from Neal Dingmann from SunTrust. Your line is now live.
Good morning all. Nick, my question for you or Brandon, can you talk a little bit you mentioned Nick about the cash wedge and product question when you kind of talking about the PDP. So I'm wondering when you're kind of positioned, essentially starting next year, even as you look into 2021, could you give us a little more color on the benefits of having that cash wedge or that PDP wedge as I look at it, and what benefits that that's going to be?
Yeah, I mean, like, so let me start and then let Nick will add. I think as you've heard us talk as we've come into this year, and through the end of this year, the big focus was on getting the rifi and the to the second lien stuff dealt with and so having the biggest possible cash wedge exiting this year was kind of our goal. So I think you've seen our spend do that. And as Nick mentioned in his in his remarks, it was really that or pay down the bank line and we felt like the returns and the opportunities that you heard Adam mention is – remain robust enough that we felt like that was the best use of that capital.
And I think the benefits are, it really does when we finalize this process, we're in the middle of – it'll reduce take off those handcuffs for being able to return capital to shareholders. And so that PDP wedge that cash flow wedge, will really be as large as we could make it as we come into 2020. And then as I think, as Nick mentioned and Adam mentioned we'll kind of throttle that down a little bit and get more into more even weighted cash flow allocation between debt reduction, additional acquisitions and returning capital shareholders, those three legged stool will be more – we'll be able to align the legs a little bit more in 2020.
Yeah, and Neal maybe just speaking of this that I think that – I think it was, I can't remember who was Phillips or Derrick that asked about the decline rate, which is that the danger that you can get into is that if we chased volume growth, and we were going to get a lot of volumes out of this capital we've spent, but what really matters is the cash you're generating within there. But if you're whole goal was just to sustain those volumes, and keep growing them in an ever growing fashion, that cash is never going to come. And importantly, you're not really doing it for the sake of making money, you're doing it just to grow volumes and that's not really the way we think about things here. And so these opportunities will come like they have in which we can get a huge cash windfall.
And certainly we didn't want our production to – it's not helpful either for the productions to fall off a cliff at any point in time, either. But the main goal is to earn a return on capital that is appropriate for our cost of capital on those assets and to sweep it down. And if the opportunities present themselves overtime we can redeploy that cash flow. I do think that we also though – we're smart enough to know that you can't have too much capital working at any given one point in time, and so that we will spread some of that risk. Obviously, I think anyone who's on this phone call today knows what E&Ps are doing, which is that they're trying to show capital discipline this year.
So what people may not always understand is that the capital that's being spent in the third quarter and the fourth quarter of 2019 is largely for production that's going to come online in early 2020. And so it's very easy for an E&P company to say, look, I beat on CapEx, and my production was in line and it will have very little effect on this year. But you will see that effect eventually in their decline rates and in their future production levels. We've taken the opposite approach, which is that we already really had that cash wedge. And as people are trying to shed that capital, we're taking those obligations and we'll get the benefit from that within a few short months.
Great details and then just one follow up on maybe Brandon that – your comment on the non-consent on that Three Forks, was there something, I'm just kind of curious what you all saw there? Was it just purely when you ran the numbers that the economics didn't stack up? Or was there something else there? And I want to make sure I'm clear that just by going non-consent there, you were still able to keep the Bakken? Maybe you could just mention what you were talking about there.
Yeah, I guess first, I'll first – I'll let Adam answer the question. Yeah, I think what I mentioned in the comments was as you know and hopefully people know by now we get to consent or non-consent on a well by well – gross well by well decision, so we can pick and choose like that. So that's kind of why we included that in our comments was our ability to choose. Yeah, we think the middle Bakken wells and that unit, we're going to be – meet hurdle rate and we didn't think the other, so we chose one or the other. And I think I'll let Adam comment on maybe what we thought we saw in there.
Yeah, we've mentioned it before. I mean, as much as it's for us [ph] it's the operator, right. And in this particular situation Jim and his team are taking a look at this particular operator in this particular area, and they're generating great rates of return in the middle Bakken and just subpar returns in the Three Forks, and so it's a pretty easy decision for us, especially when you have the optionality. So in this particular situation, it was the operator who was a different operator right next door, it might have been a consent situation.
Thanks, guys.
Thanks Neal.
Thank you. Our next question today is coming from Dun Macintosh from Johnson Rice. Your line is now live.
Good morning. I believe some of the issues tied with the curtailments was some of your partners coming up on their maximum flaring capacity for the year. As we move out of this year and into next year? Do you think that – can you expect that production to kind of come on at the beginning of the year or – and how are you thinking about that?
We're going to let Jim speak up on that one.
Yeah, it's Jim. So what we've seen is some of the operators as they've gotten kind of towards the end of the year they start reaching some of their flare limits, so they have to start shutting in some of their wells and those limits reset in February and March and so depending on the relief that they see from the gas plants – new plans coming online, either we'll start to see some of those curtailments ease as we go into the end of the year early in the quarter or at the latest we'll see them towards the end of the first quarter when those restrictions are coming off.
Okay, great. That's it for me. All my other questions were asked.
Thanks Dun.
Thank you. Our next question is coming from Jason Wangler from Imperial Capital. Your line is alive.
Good morning. Nick, you mentioned on the CapEx budget a bit, just curious kind of how you guys are seeing it kind of set up as you start to look at next year. I think you mentioned kind of – you have a pretty good handle for what the rest of this year looks like. But with all the conversations of folks slowing down and things, how do you see that proposal schedule looking as you look in the early next year in kind of how you think about that when you're kind of taking this whole plan together?
Yeah, I mean, I would just say we have not seen a slowdown in activity overall. We've certainly seen operators trying to share their non-operated obligations as a way to manage their budget. But frankly, we haven't – we've actually seen an acceleration, it is an election year, we all know that there are lots of things being said in the press and things like that that can bring up nerves and so we've definitely actually seen some activity being brought forward. Overall, I think that our AFE activity has been flat to up frankly and remember the AFEs were receiving here in November and December for wells that are likely in the middle of 2020. And so, to be honest with you, we haven't really seen that at all.
Remember, Jason, we got – and I think we put in the press release, wells – the D&C list at the end of the end of the quarter was 24, so we're seeing that pretty stable to up and I think I'm looking at Adam, I think the election activity that we've seen so far after the quarter.
Yeah, it certainly picked up in October. I mean, we consented to 80 wells in Q3. We consented to 55 in October alone. So a lot of that's coming from some of the acquisitions that we made last year was like the W Energy. So we're seeing some pretty encouraging development on those properties.
So no slow down that we can see at least from inbound AFEs and again, it should bode well for 2020.
And just remember one thing, Jason, a typical operator 10% to 20% of their budget is non-op and other operators, so they can cut their budget 20% by shedding they're non-op, but they're not necessarily slowing down their own active drilling campaign right.
Sure. No, that's a great point. I appreciate the color. And as you guys kind of go toward this – a third plan for the free cash flow and you talked about initiating the dividend, obviously, which has been a focus, but also the share repurchase. I mean, can you talk about kind of the allocation that you guys see there, as far as how to be opportunistic and also kind of how to set the dividend up as you go forward to kind of have that part of that plan fit in?
Yeah, this is Bahram. Let me jump in here. Our number one goal here is to stay focused and serve the entity first, as we have done the last couple of years, which means the number one focus, as these guys have been trying to kind of express, is that we want to grow our free cash flow. And I believe the way an entity should be measured is truly measured by their free cash flow growth or lack thereof. So we're going to focus on all of our activities to grow the cash flow, free cash flow from our operations. We need to reduce our most expensive debts. When I showed up in here, we we're spending significantly more per barrel in just interest charges. We have dramatically reduced that. I will not be satisfied with my accomplishments until we have completely and entirely have retired the 8.5% coupon debt. I like to have this company enjoy interest rates that match that of what we can get from our commercial banks and RBL group.
So, as we think ahead number one focus is to generate significant amounts of cash flow, free cash flow, take a big chunk of that and make transactions to reduce the 8.5% coupon bonds. Beyond that we have made a commitment that by 2021 we would launch a dividend program. For 2020 we would launch a dividend program. And I think we can start that within the next 2, 3, 4 weeks, five weeks and we just want to take the chance to go through close the transaction, go through the mathematics and we will announce where are we going to start that dividend at. For the first quarter they're payable in April. And then finally, we want to have enough capital free cash flow left to take advantage of opportunistic, incredibly accretive acquisitions that will help this company to continue to grow its PDP and therefore its free cash flow.
So we have reduced as Nick and Brandon pointed out our G&A substantially per barrel, we're going to continue to work on that to make sure that we don't increase G&A here as we grow the production of the company or the barrels. So all of our goal is to set this company up, so that whether there's a oil 40, 45, we can be completely viable. We thrive at 50. And of course, we will make lots of money at 60. But we're not going to bank on $60 oil. We're going to bank on having to be viable in a much tougher environment. So hopefully that gives you – this one third of our cash flow, rough and tough going into share buybacks and dividends, one third reducing our most expensive debt and one third of our free cash flow going into additional acquisitions. That is basically the sort of a thumbnail direction that we want to go with some latitude to make the best decisions for the best interest of the entity. Hopefully, that gives you the answer you need.
It does. Thank you for the color.
Thank you. [Operator Instructions] Our next question is coming from Jeff Grampp from Northland Capital Markets. Your line is now live.
Good morning guys. I was curious I noticed well cost took a little step down here in 3Q, I was just hoping you guys could talk on that? Is that a maybe mix of operator or for geographic concentration within the basin? Or did you guys see kind of more across the board cost reductions and just kind of your sense for how we should be thinking about that trended into year end and 2020?
Yeah. Jeff this is Adam. It's a mix between operator and completion methodology. So I think depending on the mix of AFCs that we're seeing at any given time, you're going to see that kind of fluctuate a little bit. In October again, we saw 7.7 kind of as our average. That being said, I think it's probably got kind of bounced between kind of 7.7 and 8.
Okay, great helpful and my follow up. I was curious that how you guys see kind of oil mix trending here as the basin kind of catches up with gas processing. Do you guys anticipate a meaningful change if at all, in regards to your sales oil mix, or do you guys kind of feel that both the oil and gas is being constrained kind of ratably?
Yeah, Jeff its Nick, I did a little bit of work on this. I went through the step downs and flaring restrictions in North Dakota and that alone should theoretically add about 350 basis points to the gas mix in general and even though we feel like our oil production is probably been constrained a little bit here by the curtailments relative to the gas, it would foot was sort of where our trend is gone. I think it should stay relatively stable as we go forward. That's certainly how we internally forecast it and the engineering systems do, but we will see another small step down in Flaring at the end of next year. And so it's possible as these systems come online, that we see a little bit more gas turned to sales. Now, I say that, but we – I said this on the last call and I'll repeat it which is that candidly, we have a lot of wells that are producing that may well on the oil percentage are being held back by constraints. So they're producing, but they still maybe, be constrained to some degree. So again, the long winded way of saying I don't think that it's going to change materially for us at a corporate level. But I do think it'll be interesting to see as these constraints ease how it manifests itself.
Got you, I appreciate the detail. Thanks.
Thank you. We've reached the end of our question-and-answer session. I'd like to turn the floor back over to management for any further or closing comments.
Alright, thanks Kevin. And thanks everyone, for your participation in the call and your interest in Northern Oil and Gas. Please take note that we have a busy schedule the next several months, attending various conferences around the country and some of those details are included in our press release. So we look forward to seeing some of you on our travels and plan on talking with you again next quarter. Kevin, you can give the replay information. Thanks, everybody.
Certainly, that does conclude today's teleconference. To access to replay please dial 877-660-6853 or 201-612-7415 and enter access ID number 13696040. We thank you for your participation.