Evolution Petroleum Corporation (EPM) Q4 2016 Earnings Report, Transcript and Summary

Welcome to the Evolution Petroleum Corporation Call to discuss Full Year Financial and Operating Results for Fiscal Year 2016 Conference Call. [Operator Instructions] I would now like to turn the conference over to David Joe, Chief Financial Officer. Please go ahead.

Good morning and thank you for listening to Evolution Petroleum's conference call to discuss operating and financial results for our fiscal year and fourth quarter ended June 30, 2016. I'm David Joe, CFO for Evolution. And on the call with me today is Randy Keys, our President and CEO. If you wish to listen to a replay of today's call, it will be available shortly via recorded replay until September 15, 2016. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today will contain forward-looking statements of management's beliefs and assumptions based on currently available information. These forward-looking statements are subject to risk and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. Since detailed numbers are readily available to everyone in yesterday's press release, this call will focus key overall results, operations and an update on our reserves. I'm going to turn the call over to Randy Keys, President and CEO.

Thank you, David. We've got some very positive information to report today. We've had a great year, great quarter and have a very positive outlook going forward. Net income for the year was $24 million, $0.73 per share on EPS level. The quarter was $20.7 million of net income and $0.63 per share. Both these numbers include the financial settlement with Denbury regarding the Delhi litigation. We had 27.5 million in cash and other good consideration including an interest in the Mengel Sand within the Delhi Field and other clarification of our long term costs under the contract. Revenues for the year were $26 million and we saw an increasing trend very positive trend during the year with production which was up about 600 barrels a day over the course of the 12 month period. We began the year about 6,200 barrels an increase that to about 6,800 average. And in fact we're pushing 7,000 on a run rate basis right now. We also - if we roll back to the reversion we were actually in the 5,800 barrel a day range. So we’ve seen production come up easily a thousand barrels a day over the last year and a half. Now what a difference a quarter makes, last quarter we were talking about $30 oil as our average price, this quarter we're talking about $43 and we had an average for the year of about $40 a barrel. So we started the year a little higher 47, came down to $40 for the second fiscal quarter as you had a very, very decade low quarter in the first quarter versus the calendar quarter and then as I said finished better at 43. One thing we have noticed is that our differentials are shrinking. Our crude trades at a positive - it trades as Light Louisiana Sweet crude that trades at generally at a premium to WTI. But we have seen that premium shrink somewhat over this declining price environment. As we look at lifting costs, the trend is also very positive there. We started the first quarter with about $16.50 per barrel lifting cost and we ended the year at a little under $12 a barrel of lifting cost for the Delhi Field. Our purchased CO2 volumes trended down now the recycle volumes have remained fairly constant but Denbury has been able to use less new CO2 and then frankly has been able to increase production. So this is a very positive trend. It shows a greater efficiency in the way they are using CO2 in the field. As we mentioned in the press release, CO2 is priced based on crude oil. It's got a direct relationship. So it serves as a partial natural hedge against oil prices as oil prices decline our costs go down and if oil prices recover we will see our costs go up and our margins should expand at a greater rate than that. And then approximately half our costs are normal recurring things such as power chemicals and labor field labor and repairs and maintenance. Those have remained fairly steady at about 1.2 million per quarter. As we move to the G&A line, our G&A costs for the fourth quarter in the year were very high. The primary driver for that was litigation costs we were accelerating toward a trial date and our costs head to head increased dramatically. We also about two years ago shifted from our compensation approach from one based primarily on service to one that includes performance-based metrics including comparison of our stock to the total return of other peer companies and also because we are dividend paying company some of those are based on net income as well. So I think it's unfortunate that these costs spiked up because they obscure some very significant efforts that we've been taking to try to focus on operating costs on the G&A cost and try to bring them down. We’ve reduced our headcount significantly over the past two years. We took the difficult decision to restructure our artificial lift operations at the end of last calendar year. We felt that that technology still shows promise but we felt that we could no longer afford the overhead associated with it in this difficult period. So we’ve restructured that saves quite a bit on G&A. We also move the company to a smaller office and that's generating some significant savings as well. It was fortunate for us that our lease our old lease was up in the summer this year. So it gives us an opportunity to drive those costs down and we’ve taken a whole manner of other steps to try to reduce those costs. And I think we'll see the benefit of that going forward. We've set a $5 million budget for next year and that includes all non-cash costs, stock based compensation and everything in that number. One other point I want to make on the income statement is our tax line, we do show tax expense on the income statement it’s about $9.6 million for the year. However substantially all of that is non-cash. We have a somewhat unusual quirk in our accounting that requires us to treat the benefit of that cost savings and cash savings as a financing activity. So it shows up as a direct entry to our equity instead of reducing the amount that we pay on the income statement. So a large part of the settlement for litigation was sheltered from tax by both carryover NOLs and also percentage depletion. And even looking forward to next year, we should receive a substantial bonus depreciation for the plant the NGL plant when it's put in service. So that's going to also shelter a lot of our taxable income next year. We would not expect to pay significant cash taxes next year. But we are moving toward being a full tax paying entity as these tax benefits run off. We also had significant hedging gains for the year. In the past Evolution has not typically hedged but as we - as we finished the reversion we got the reversion in November of 2014 and we were faced with the $25 million expenditure on the NGL plant and the desire to maintain our dividend through that spending process we felt that it was important that we put some price protection in place. I think we were fundamentally a little bearish a little more bearish than the industry when we put a lot of those in place last year. And so we saw a pretty significant benefit in hedge gains from that. At the moment I would say we have less of a need financially and we're probably more neutral overall on the direction of oil prices. So we do not currently have significant hedge volumes at this point. Balance sheet is very simple. We had 28.6 million of working capital. We received our settlement payment on the litigation right before the end of the quarter. So we had $34 million in cash part of that is offset by payables in process related to the NGL plant. And of course we finished the year with no debt. Looking at the dividend, we model our net income at - if we model our net income at $45 oil we generate sufficient net income to pay the dividend of $6.6 million a year and that also gives us about an extra $10 million of cash flow. And that assumes that we see the NGL plant coming on at midyear. If we were to see a return of a very low price environment, we have sufficient cash from operations to cover the dividend down to oil price well below $30 somewhere in the mid to high 30 - mid to high $20 oil range. So we've got sufficient cash flow to continue paying the dividend and of course we have substantial balance sheet resources as well. But I think we're focused also on sustainability of that dividend. So looking at the reserve report we updated our reserves with DeGolyer McNaughton at the end of the year. We had three PUD projects three proved undeveloped projects in the reserve report last year. We had the NGL plant and then we had two expansion projects for the Eastern part of the Delhi Field. We have Test Site 5 and Test Site 6, 5 is the one that is adjacent to the existing flood,6 is the furthest east and it's actually on the other side of the town the Delhi. So as we went through the reserve report this year, we lost one PUD project that was Test Site 6 and it had about $6 million - sorry - 1 million barrels of oil. We also of course had about $650,000 of production. So our proved reserves did go down but I think it masks an underlying positive in the reserve report in that we are seeing significant outperformance of the Delhi Field. Our production is higher than expected and all - our costs are lower and all of our trends are frankly very positive in the Delhi Field. Some of this is reflected in an increase in expected recoveries in the reserve report. On the proved side, we’ve gone from 13% expected recovery to 13.8%. On the probable side we’ve gone from 17% to 18%. These are incremental recoveries of the original oil in place that are attributable to the CO2 flood. So frankly we've seen that the old max and the big fields get bigger is definitely proving true in the Delhi Field. It is a very good long term field and it is outperforming. Some of the trends were interrupted by the spill, the incident that occurred in 2013 but we’re now getting sufficient history to show that the field is definitely outperforming the trend lines that were set up. We included in this press release some sensitivities for other price points because we were forced to do our reserve report at a very low price, it was based on $43 NYMEX crude. The overall cost on the lifting cost for the life of the field are about 16.50. The average revenues when we blend down the NGL revenues with the oil is about 35.50. So the field still has a very healthy margin, still has a 25-year life but it has a significantly lower present value under this scenario than it would under higher prices. So we’ve included a sensitivity at $50 and $60 to show the effect of purely price on our reserves. And this isn’t largely an apples-to-apples comparison but the mix of properties remains in the same in those cases so it is mostly just things that are price dependent, it does imply a slightly longer economic life because higher revenues will allow the field to produce longer with a given cost situation. As we turn to the NGL plant, we’re nearing the end of a long journey. We started this process actually three or four years ago when we started planning for this but it was authorized as an AFE in February of 2015 and we are now to the point where we can see the end, we’ve spent about 90% of the capital. They are telling us the plan is largely complete and should be online November 1. There will be a period of testing and ramp up after that point and we expect to see full production by the end of the year. This largely completes our CapEx program so we really don’t see a lot of capital expenditures requirements needed and we do have Test Site 5which is a very good project. The operator has mentioned it is one of the projects they would potentially add spending on as they had capital dollar available but we don’t know yet whether that project will make into their budget next year perhaps the year after. So that would be the next big one and it’s got about an $11.5 million CapEx associated with it. So if we did get into that project next year it would consume some of our financial resources we would still be fine and we would have more than adequate resources to do that but we don’t know yet the status of that. So as we look forward we’ve got a great asset, we’ve got solid cash flow, very economic production which is both – it's good on the upside and it’s also good on the downside. The fact that we’ve got $12 or $13 lifting cost gives us a lot of comfort, a lot of protection on the downside. We’re in what believe is a recovering price environment. It may take some time but we do see positive outlook there and as I said most of the capital expenditures are behind us so we have very healthy balance sheet, probably the best balance sheet we’ve had in maybe ever and we’re sitting here with large working capital and the ability to continue our dividend program and we have other - we have funds for other options. So with that I am going to conclude the call and open it up for questions.

[Operator Instructions] The first question comes from Joel Musante from Euro Pacific Capital. Please go ahead.

Hi, David, hi Randy. Thanks for the thorough introduction there. You answered actually most of my questions but I still had one. In the press release you mentioned that with the settlement it's kind of clears the wave for some growth opportunity. I was just wondering if you can expand more on that and then talk about what you might be seeing out there.

Well we - I can give some color to that but frankly we’re not creating any expectations for the things that we’re looking. I was looking back, we had a long discussion about this with the Board and looking back on some of the deals that we evaluated last year and we had two deals in particular that we were frankly much more bearish than they were on terms of outlook in oil price and their asking price was around $100 million and one of those companies ended up doing a deal at about $44 million, the other one actually did not survive and largely has almost no value. So we think we were frankly early. We may still be early. We’re a little conservative in the way we view the world. We see a lot of seller optimism out there. So we’re being patient and evaluating those opportunities one by one. We do see deals, we have deal flow, we’re looking at different things but at the same time we don’t want - we’ve got a lot at stake here. We’ve got an excellent company with excellent cash flow and we want to make sure that whatever decision we do is the right one and offers us both good opportunity on the upside but also is protected if prices don’t increase as we think they may. Those are pretty generic answer Joel, so I think - I am think of running for public office next year so I am practicing my politics.

And just on the settlement how does that - getting that out of the way how does that help I guess?

Well that has actually been very positive and it even started before the settlement. We had a good dialogue with their operating group and it sort of fell apart last year. I would say we had 2014 early 2015 I thought we had a good dialogue and it kind of fell apart last year and beginning earlier this year, we started to see an improving dialogue and it has gotten quite a bit better. So they were helpful when we were going through our reserve report because they use the same engineers as we do. We’re getting much better information on the operating side. I am planning actually to take a trip to the field to see the plant here in the next probably 30 days. So it’s a lot of intangibles but it is a noticeable improvement in our relationship and it’s very helpful for me because it allow us to understand and plan and communicate what’s going in the field.

Okay. All right. And then just on the recovery rate the reserve engineer has given you more credit there. I guess how does that process work, I mean, how can you, I mean they are still part of the field where you’re not realizing a higher recovery rate. So how can you…

Well, first off, those recovery percentages are on a smaller base. So they - that is the recovery factor for the amount for the field that is under flood and expected to be under flood with the remaining proved undeveloped location. And it is oil only by the way, does not include natural gas liquids those are not modeled. So I think I would describe it the reserve engineers do a volumetric model that’s based on the amount of net pay and the oil saturation and because this was a large field with 450 wells there's a tremendous amount of data available. And so - and much of that work was done several years ago. They define the volumetric expectations and then they look at what -- and they know what the primary in this case the fields produced just under 200 million barrels in primary about 195. Originally they said 418 was original oil in place and they have not changed that but they have reduced it to the net area that is under flood and it's now about 323 million barrels. So it is on a smaller base but it's a higher percentage incremental recovery from the CO2 flood. So they’re basically approaching this from two different directions. They have a concept of how large the field is and then they have production history that shows the rate at which they were producing those reserves and they try to fit those two curves together and frankly the field is producing at a higher rate than their model would've suggested. And so that implies improving performance over the coming years.

Okay. All right. And do they just assume the decline – you’ve got higher production they don't try to make the volume the same they just use the same decline as they had before only from the higher point, is that…

Well it's actually iterative. So they don't they’re solving – they’re basically solving both equation simultaneously. So they don't just raise the rate and assume the same decline. They’re also looking at what their understanding is the total volumetric. So it’s a bit of a iterative process that’s why they get paid the big bucks. And you know so I’m not sure I can explain it in you know fully in Layman's terms. But it’s-- you know those -- so what -- something has to -- one way to say it something has to give and right now they've got the two models reconciled but if the field continues to produce at a higher rate and the decline rate is not as steep as they have modeled then that would imply a greater long-term recovery. They would reevaluate their model at that time. And there's always been a debate with how much incremental recovery. Most of the Gulf Coast sandstone fields such as Delhi tend to recover in the 17% range. And they had been fairly conservative and assumed about a 13% proved recovery initially. So the 17 is their probable it’s their 50-50 case their [P50] [ph] case so to speak. And so we're somewhere we're moving from that you know 19% confidence case of 13% to where we believe the probable case is at 17% and we expect to land closer to that 17% to 18% ultimate recovery instead of 13%.But there's an inheritive conservative bias with the reserve engineers and so they until there is plenty of data to make the case they tend to err on the side of conservatism much like accountants.

Okay. I guess I’ll leave it there. Thanks a lot. I appreciate it.

The next question comes from Jeff Grampp from Northland Capital Markets. Please go ahead.

Good morning, guys. Just wanted to kind of maybe get your thoughts Randy and as you guys kind of pointed out even if prices kind of stay where they’re at on the oil side, do you guys still and certainly could shape to pay the common dividend as it stands today maybe look at some other options so just kind of wondering I know you guys I highlighted in the press release you have the preferred still out you know the share buyback and potentially dividend increases as options and how would you maybe rank those on a relative order of preference as it stands there, can you kind of provide any color or granularity on those options ?

Well, we -- I can just say that we have not made firm decisions on that. That is a continuing dialogue with the board. As in the earlier as Joe mentioned there is the opportunity for potential other growth opportunities. So I think the challenge for the company is to decide whether we’re better served by for instance retiring the preferred or we're better served by retaining those funds for potential growth opportunities. We don't have to retire the preferred at any given point in time. So there is an ongoing dialogue between those two those two potential outcomes. And unfortunately I can't really give you a clear handicap as to what we're going to do with that. But you know we see we’ve got lots of financial flexibility with this cash that we have and you know the goal is to balance growth versus income. And we’re working through those things every day that's part of what we're trying to figure out as we manage the company.

Okay, perfect. That's understandable. And then just thinking about on the operating cost side certainly another real strong quarter, any kind of on a run rate basis our injections kind of staying where they’re at on that fourth quarter level or was that maybe an abnormally low quarter maybe we should expect to kick up on the injection site obviously oil price comes into play too but kind of excluding that variable how should we think about purchased CO2 volumes?

You know that’s a very good question and we will answer that will be answered in the 10-K.But I’ll answer it now. The volumes were a little bit below the long-term average. I think we ended up about just below 60 million a day in terms of CO2 volumes for the fourth fiscal quarter. We've been told by the operator that volume should range between 60 and 70 million a day for new purchased CO2.And frankly there may be some adjustment once the NGL plant comes online because we’re going to be pulling some liquids out of that strain and we may need to replace some volumes on a short term basis. Frankly that is just not known at this point. But there may be some one-time costs associated with when the plant comes online. But anyway I think we're not far from – we're not well way under equilibrium but we might've been a little bit lower this quarter. We're modeling you know I’d say about 65 million a day internally and you know we think that's a that's a fair target based on what we've been told from the operator. And the only wildcard is not fully understanding the long-term both the short-term and long-term effects of the NGL plant on that. But of course that’s a company by higher revenues so that’s probably a good problem.

Absolutely. That’s great color. I appreciate it Randy. Then last one for me just on cash G&A, you kind of have maybe a good number to think about going forward NGL plant on some performance-based kind of compensation numbers in there but any kind of color on a go forward that would be helpful?

Sure. I think we’ve got 5 million total of that about I think 1.2 maybe 1.3 is stock based compensation for both management and the Board of Directors. We pay Directors half of their fees in stock. So that would leave you with a cash number of about 3.7 and I think that's consistent with what we said right after the decision on GARPI think I'd projected it is about 900,000 a quarter which should be 3.6 million on an annual basis. So I think we're pretty close we’re pretty close to that as I mentioned earlier that is an area we focus a lot of attention on. We’re doing what we can to keep those costs as low as possible.

Okay. So 5 million total G&A annual 3.7 of which is cash, have I those numbers down right?

Yes. That’s correct.

Perfect. I appreciate the color and great quarter guys, thanks.

The next question comes from John White with Roth Capital. Please go ahead.

Good morning. Congratulations on such nice results to able to say you balance sheet is in better shape in a long time at this point in a dreadful part of the cycle that we’re in is really an accomplishment. So I heard your comments and read your text regarding Test Site 6. Is that – are those just reserves that came off the books, are those wells still producing or have been shut in. Can you give some more detail there?

Well, those were undeveloped. So we have - they’re basically six phases, or we refer them to as Test Site's and we’ve developed the first four of those. So that’s what currently producing right now. And Test Site 5 and 6 were the continuation of the field to the eastern - down the eastern part of the field. Test Site 5 is immediately adjacent to Test Site 4 which is the edge of the exiting flood. Test Site 6 is on the far eastern edge of the field and it’s actually on the other side of the Town of Delhi which is going to be excluded at least for the foreseeable future from the flood. So the answer is those were not producing, they were just proved and developed and they are not gone but they do have a higher, significantly higher economic threshold than the Test Site 5 does. So as you go to east the rock quality gets a little poor, it’s a little more expensive to get the infrastructure all the way over to that test site and so it needs a higher price. And I think that price is probably north of 60. We don’t, I mean it’s not - we can’t tell exactly but it’s even at 60 that project did not come back in when I ran the sensitivities. So it’s still, those reserves are still there, they - but just to be clear Test Site 6 is not in the reserve report, in the proved reserves going forward. In fact, it’s not even in the probable's right now.

Okay, thanks. I appreciate that. And thanks for the sensitivities, that’s very helpful because of the SEC price scheme you’re kind of disadvantaged by the luck of the draw there and also your comments regarding the engineering report that's rare to see but I really appreciate it, it’s very helpful and as was mentioned by an earlier participant your press release was very thorough and your comments today and I don’t have any more questions at this point so thanks for taking my call.

Thanks John. And by the way one other small point. All of that data that I just discussed about the projected recoveries, that is included in the letter that the reserve engineers produced and it is filed as an exhibit to our 10-K so this is all basically public information. But happy to give that color.

The next question comes from John Fox with Fenimore Asset Management. Please go ahead.

Okay, thank you. Hello everyone. I just want to conform on the reserve report about 3.7 million of NGLs going to over three categories, is that basically the NGL plant that’s going to start up this year?

That is.

Okay, great. And then you used a phrase pushing 7,000 a day in terms of the Delhi production. Is that a ceiling, do you think that production can grow, what will be your outlook on that?

We again - I am glad you asked that because I did neglect to mention one thing. We have a project that was initiated back in the fourth fiscal quarter to put some ES, some high rate water production wells, move some water that we think will have about 10% oil cut. So we’re looking, we’re still looking for about 250 to 300 barrels per day gross of incremental production from that project. We spent the capital and it just recently came on line. We don’t have any results yet but we do see an increase there. We also see an increase in oil based on the efficiency of the NGL plan. We haven’t really quantified that. In the past we’ve talked about a potential 500 barrel per day increase in gross production. At this point we’re just waiting to see what the actual results are. We do think there will be positive effects on the oil rate from NGL plant but frankly it’s a difficult exercise to try to quantify those accurately but no. And then of course, if we and when we add Test Site 5 then we’re going to add production from that. I think the bigger thing is that we see that remaining flat for the near term which is a good thing. In other words we’re not going to be faced with a decline in our near term production. We do have some, a couple of projects which should potentially increase that rate and then of course we’ve got Test Site 5 coming on. And back to your earlier point about the natural gas liquids, there is a very small component of that that is associated with Test Site 5 but the vast majority of those liquids that are projected in the report are going to come online immediately. They come online all at the same time and the only thing that as you add a little bit more production and CO2 recycle from Test Site 5, you either increase NGL recoveries, you maybe don’t increase the rate but you slowed the decline and add some production down the road.

Okay. So the 7,000 is solid with a very low decline and as a potential for these the 250 to 300 from this group of wells, plus the NGL all of that could be upward pressure over time on the daily rate?

Correct. Now I got to always hedge that nothing is certain about the future but that’s what we’re looking forward right now that’s what we see. And I got to say we were also a little bit surprised at how well the field has performed this year, I mean it has exceeded our expectations and at the moment all indications remain positive that it will continue to do so.

Okay, great. And can you just remind us on the hedge position going forward from say June 30 forward?

We have almost no hedges, we have some 45 and 55 collars on really only about a third of our production and so those will - it appears most likely will fall in the money with no settlement in either direction and that ends September 30, so the end of this month. We didn’t have a settlement on either July or August and while we could have a settlement potentially in either direction for September, I think we’re squarely in the middle of the range right now so unlikely. And as I said we’re not really looking to add hedge volumes right now. We don't have a compelling financial need to do that and so - and frankly our views are little uncertain, I would say neutral. We have kind of a bearish view and a bullish view and right now those two are somewhat in balance.

Okay. Thank you so much.

The next question comes from Brian Grefe working with Raymond James. Please go ahead.

Thank you. I was just wondering if you could comment on if there is a preferred size of deals that you are looking at, I know you made some reference earlier but if there is any level of a deal from a growth perspective what kind of range may that be in.

Sure, first off if we do a transaction we - because have shrunk the company dramatically in terms of our operating people where we would have to add new operating people which may or may not come with the asset that we would acquire. So I think that leads you to the conclusion that a deal needs to be big enough to matter and it needs to be big enough to cover the incremental G&A that you’d have to add. So I think there is bottom threshold that below which we really wouldn't look at a deal on that. You know we've debated as to whether that's 25 million or 50 million but it's somewhere in that range is sort of a hard floor. We're looking for something with production rather than just looking for upside so we're really not able or interested in competing in a lot of the things that are going on in the Permian basin right now. You know aside from valuation that's just not what - that's not what we're looking for. We want a solid base of production and we want some upside that we can develop from there. So I think that establishes the lower end. The upper end is frankly just undetermined at this point. We've got an excellent public company here with good history, good solid cash flow. You know we think there are opportunities both for merger potential and also for potential cash transactions because we do have we’ve got a nice cash position, we’ve got a reserve-based lender that we have a good relationship with and we don't have anything drawn on that right now. But we are positioned with dry powder to do a transaction. And so I don’t even want to put enough for cap on it. It’s just we evaluate each of those transactions you know from a - from the standpoint of value to our shareholders.

Great. Are you seeing more deals in the current oil price environment than you were when things were lower?

You know it’s funny, I would say yes, we are and I would say they're much more - many of them are much more rational except for the ones in the either the Permian or the SCOOP stock. We are seeing a much more rational view on pricing from our standpoint and deal flow is still less than we would like to see. I think people are still stubbornly hanging on because they think if they hold on a little longer they will get a better price and they may be right. So you know it's improved but it's still not - I wouldn’t call it robust and there’s plenty of competition. There is a ton of private equity money out there in the market that is looking for opportunities. So we - there's lots of competitions on most of the deals that had solid strong economics.

Great. Thank you.

[Operator Instructions] The next question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.

Hi, guys. Just have one more kind of housekeeping follow-up on the income tax front, Randy I think you said that with this NGL plant coming online you still expect a good amount of any income taxes to be deferred in nature, just kind of wondering can you put any kind of upper and lower bound on what percentage of your income taxes would be deferred, do you have any kind of sense of that prior to the NGL plant coming online?

I will make you a deal Colombo by the way just one more thing but I will make you a deal you tell me what price and I will tell you the taxes. No, I'm just saying I don't know what the cash flow is you know so it will shield a substantial part of it. Of course if we get $55 or $60 oil then it's not going to shield nearly as much than if we remain kind of in this 40s in the mid to high 40s range. But I think you can look at it this way, we have $25 million of investment in the NGL plant. It can't be - you can't take a deduction for until the plant is put in service which will be in this next fiscal year. And I think a substantial part of that and I’m looking across the table do we have a percentage of this deductible in the first year or is there a cap…

I will give you a number but…

Yes.

It ended about 50%.

Yes, I think we - that’s my recollection to it. I think we can deduct about 15% - 50% of that so 12.5 million as bonus depreciation in the current in the year that you put it in service. So that’s a meaningful shield we also have some carryover depletion percentage depletion that we can deduct. But it’s not going to shield all of it unless prices are very low. But we should see a meaningful - and frankly I just can't - I don’t have a way to quantify much beyond that.

Certainly, that's helpful enough details to get me started. So I appreciate it.

This concludes the question-and-answer session. I would like to turn the conference back over to Randy Keys for any closing remarks.

Well, thank everybody for good questions this morning and if there’s any follow-up questions feel free to call management here at the office. Thank you again for listening and have a great day.

This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.