PetroQuest Energy's (PQ) CEO Charles Goodson on Q1 2016 Results - Earnings Call Transcript

| About: PetroQuest Energy (PQ)

PetroQuest Energy, Inc (NYSE:PQ)

Q1 2016 Earnings Conference Call

May 03, 2016 09:30 AM ET

Executives

Matt Quantz - IR

Charles Goodson - CEO

Bond Clement - CFO

Art Mixon - EVP of Operations and Production

Analysts

Ronald Mills - Johnson Rice

Richard Tullis - Capital One Securities

John White - ROTH Capital

John Aschenbeck - Seaport Global

Daniel Guffey - Stifel

Operator

Good morning and welcome to the PetroQuest Energy First Quarter Earnings Conference Call. All participants will be in a listen-only mode [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions [Operator Instructions]. Please note that this event is being recorded.

I would now like to turn the conference over to Matt Quantz, Manager of Investor Relations. Please go ahead, sir.

Matt Quantz

Thank you. Good morning, everyone. We would like to welcome you to our first quarter conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Bond Clement, CFO; and Art Mixon, EVP of Operations and Production.

Before we get started, we would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest’s business which are not historical facts are forward-looking statements that involve risks and uncertainties. For a discussion of such risks and uncertainties which could cause actual results to differ from those contained in the forward-looking statements, see Risk Factors in our annual and quarterly SEC filings and the forward-looking statements in our press release. We assume no obligation to update our forward-looking statements.

Please also note that on today’s call, we will be referring to non-GAAP financial measures, including discretionary cash flow. Historical non-GAAP financial measures are reconciled to the most directly comparable GAAP measures in our press release included in our Form 8-K filed with the SEC.

With that, Charlie will get us started with an overview of the quarter.

Charles Goodson

Thank you. Good morning. During the first quarter we produced 7.6 Bcfe or applications 84 million cubic feet of gas equivalent per day. 84 million cubic feet equivalent per day was comprised from approximately 61 million cubic feet of gas, 1,500 barrels of oil and 2,300 barrels for Ngls. Our first quarter production volumes not only exceeded our original guidance about 14% but we ultimately ended up surpassing our revised production business of 81-82 million cubic feet equivalent per day. These accomplishments are a testament to our resilient production profile primarily led by our Cotton Valley, Thunder Bayou, [indiscernible] and other stable Gulf Coast assets which continue to outperform our internal projections.

Revenues for the quarter were applications $17 million with product price realizations averaging profiting $31 per barrel of oil and $1.93 per Mcf of gas. NGL product price realizations averaged applications $11 per barrel. On April 21st we announced that we successfully closed on the sale of our remaining Woodford properties located in East Hoss field. This divestiture generated applications $18 million of supplemental liquidity and based on the first quarter’s numbers the asset was sold on Bakkan’s [ph] a cash flows. This sale has simplified our story into a two basin company with cash flow coming from the Gulf Coast basin which funds the development of our Cotton Valley trend, PetroQuest Inc’s position in the Carthage area currently stands at 55,000 gross acres and contain some or all of the seven proven Cotton Valley benches.

Having numerous perspective benches through our acreage position effectively increases our surface acreage multiple times over. Our acreage consist of our original legacy position of 49,000 gross acres and approximately 6,000 acres joining to the East. We recently sold 50% interest in the undeveloped portion of the West Eastern 6,000 gross acres for $7 million to a buyer who will remain confidential. It's a junction where the recent sales down we initiated efforts to create a joint venture for a long-term Cotton Valley development program on the sold acreage. However, we have just begun the initial schedule and have nothing further to add at this time.

Touching on the goals we set for the company at the beginning of the year, we wanted to accomplish three main objectives, we wanted to extend the security of our 2017 notes, continue to execute non-core asset sales and create a joint venture in East Texas. While we still have some work to do we certainly made a lot of progress in all of these goal during the first quarter through the exchange, the East Hoss sales and now active discussions for a joint venture in the Cotton Valley.

And turning to operations in East Texas where our latest two wells continue their strong production profile and are closely tracking the shallow decline rates seen in our 2014 and 2015 wells. Just a reminder, our last 10 wells on average have realized 30, 60 and 90 day production rates that are 98%, 90% and 87% of their operating rate respectively. The strong performance was contributing factor in our first quarter production base. As we have demonstrated in the past this asset only requires a modern activity level to have a substantial impact on our production reserve growth metrics. For example, we only drilled non-gross wells during 2014 and 2015. But this limited program generated asset well production reserve growth rates of 95% and 140% respectively. The bottom line is we believe we can quickly restore our pre-outcome [ph] divestiture of corporate production and reserve levels allocating a minimum amount of capital to this premier asset.

Now turning to Gulf Coast where Thunder Bayou continues to flow at approximately 30 cubic feet equivalent per day and they’re out for producing from the bottom zones 3P reserves. The wells production profile continues to exceed our forecast and as a result we are now revising the timing of our $800,000 gross or $400,000 net recompletion into the primary upper zone. Our latest estimate calls for this recompletion to occur during the third quarter of 2016 which is expected to help offset the effects of our significantly reduced capital budget on our production profile; also incremental production is expected from our upcoming three well ship sold heavy duty inflation program which should commence towards the end of the second quarter. This lower cost program with totaled net cost of approximately $600,000 is expected to have approximately 3 million cubic feet equivalent per day in new production net to PetroQuest during the third quarter.

With that, I will turn it over to Bond to go over the financials.

Bond Clement

Okay. Thanks, Charlie. Good morning everybody. Starting off on the balance sheet, our recent exchange is now reflected in our first quarter numbers. Because in the accounting treatment for the exchange no gain or loss or no gain was recognized on the roughly 13.9 million of debt extinguish on the 2017 notes in excess of the consideration that we provided in the form of cash, new second lien notes and shares. At the end of the quarter 13.6 million of this differed gains was reflected as additional debt under the 2021 notes and will be amortized as a reduction of interest expenses over the time of the 2021 notes. On the liquidity front our March 31 cash balance of pro forma for the each East Hoss divestiture we recently announced through 18 million was approximately 71 million. In addition, we are currently going through a redetermination with our bank groups for our 42 million borrowing base based on initial discussions and due in large part to the Oklahoma sale in April we’re expecting a reduction to the borrowing base once this process is complete and we would expect a redetermination to be finalized within the next few weeks.

Turning to our first quarter results LOE totaled $8.2 million or a $1.07 per Mcfe, which was below our guidance to the $1.20 to $1.30 primarily due to the out performance on the production side that Charlie touched on earlier. We're keeping our second quarter per unit LOE guidance range roughly consistent at a $1.25 to $1.35 to account for the lower production volumes post the East Hoss.

G&A cost for the first quarter totaled $8.6 million and included about $400,000 of non-cash stock comp. More importantly though G&A also included 4.7 million associated with direct cost in issuing our 2021 notes. As much and typically these types of cost are capitalized and amortized over a life of the related debt, but the accounting guidance in this exchange required the cost to be expanse during the period incurred. Excluding such cost our overhead was in the range of our guidance of 3.6 million to 4 million.

Interest expense during the quarter totaled $8.3 million which is slightly higher than our guidance range of 7.8 to 8.2. The increase was primarily due to about $400,000 of differed financing cost that were written off during the quarter, in connection with the debt exchange. Looking at CapEx for the quarter, we invested about $6.6 million, the breakout of the capital was approximately $4.8 million of direct CapEx and about $1.8 million of capitalized overhead and interest. The majority of the direct CapEx during the quarter was associated with our two most recent Cotton Valley wells for the rest of the year we expect our CapEx spend rate to slow compared to our first quarter numbers, so we currently just have a newly completions and some P&A work planned. In total we expect to spend approximately 20 million to 25 million this year that includes capitalized interest and overhead and that number is going to be down about 70% from our capital spend last year.

Quickly touching on same quarter production guidance, we expect to produce somewhere between 61 million and 65 million equivalent per day. Several main drivers contributing to this forecast through reduce same quarter production volumes, obviously our guidance reflects the fact that we sold 10 million a day in April in connection with our East Hoss sale. In addition we are forecasting production declines to occur at Thunder Bayou throughout the second quarter as we produce at the bottom end over before moving up to the main pacing action during the third quarter. Our Thunder Bayou and [indiscernible] 72 rig completions later this quarter and in third quarter should help to meaningfully offset production declines during the third quarter.

With that, I’ll turn it back over to Charlie.

Charles Goodson

Thanks. As we move forwards utilizing a half margin cash flow from our Gulf Coast, Gulf of Mexico assets and next day until the PetroQuest store will come from our top tier Cotton Valley assets. To put to perspective the resource we are developing, the acreage position I mentioned earlier only represents a fraction of our growing 55,000 acre footprint, on the 6,000 acre position when we sold a 50% acreage in undeveloped rights, where we are working towards the joint venture we have defined over 100 low risk locations which will test 5 of the 7 benches within the Cotton Valley and it in those vertical and horizontal production and it histories [ph]. Still benches are productive vertically on our acreage and also productive horizontal either on or off setting our acreage, best categorizing [indiscernible] risk. Next we have internal goals to further lower our cost by 10% to 20% which is already $4 million.

Look at it another way, our average internal estimates of EUR for 1,000 lateral feet are 1.7 Bcfe and we've already seen EURs highest 2.3 Bcfe per laterally foot, easily 35,000 feet [ph]. Those metrics on a cost basis are well established in our last wells below $1,000 per lateral foot, with the lost average of 849 achieved on our last well and there will also be some continued decline for these number.

In summary, while I remember our shareholders are disappointed in our share price, unfortunately we will be able to walked along and [indiscernible] professionals and drive above the results. If we were are successful in putting this place the above discussed joint venture I am certain it will be extremely successful above our partner and PetroQuest. I'm also comfortable with making appropriate decisions as we continue to navigate the commodity cycle.

With that, we'll open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question today comes from Ronald Mills of Johnson Rice. Please go ahead.

Ronald Mills

Charlie, you're still in the early stages of overall JV in the Cotton Valley, but the sell down of 50% interest in that undeveloped acreage, what was some of the through process behind selling down an interest ahead of doing a more comprehensive JV over the entire position.

Charles Goodson

Ron, we're just prefer to differ any discussion on that at this point time. We know about [indiscernible] but we basically because of the numbers, we have to go ahead and talk about it but at this point in time we're going to say that we’re in the early stages of discussion a joint venture and that was part of the process, the initial part of process and we'll have to talk about ensuing the, let’s just say in ensuing months.

Ronald Mills

Got you, and then as assuming you have, you do end up closing on JV, what is your thought process in terms of getting back to work and I assume that incremental dollars would all -- any incremental CapEx at some point later at this year, would really be directed towards the Cotton Valley, is that correct?

Charles Goodson

Ron, we have always said we want to start drilling when it's appropriate. As you’ve seen the gas price showing some signs of contango we are kind of rolling off these month after months we are going to -- kind of bounce back and we make it -- if we started not in the future in the ensuing months, we already have locations, some of these signs we can move a rig a rig in relatively quick, in a period of approximately 30 days, we get out there and have a rig moving in. So it's not going to take us very long at all to get started and we have access probably to the same rig that we used that had these last two extremely low cost and very effective results in the Cotton Valley.

So we start let’s just say some time in the second quarter, you’d have, certainly have you’ll have production at third quarter and our goal is to probably to do something that allows us to start moving in and drill continuously and hopefully into a move constructive in gas market. So we are ready to go at a set of locations already, it wouldn't take us long at all. Infra-structure is in place, it's really completing the discussions, negotiations being very thoughtful of who we have some partner in and moving forward and there we’ve pretty much summarized it, we really have after this two wells defined over 100 low risk locations. So it’s going to have an extremely meaningful impact on our company.

Ronald Mills

Okay and can you just remind me of the product mix split there, in other words Ngls versus gas because in addition the gas contango are you seeing some improvement in Ngl prices and just trying to get a sense of the impact of those higher Ngl prices

Bond Clement

Ron, we're about 55 barrels per million of Ngls and I think it's probably important to understand the make up with the Ngl barrel, at Carthage it’s a little bit different than you see and some of the shale plays around the country, we’ve got more rich barrel with probably 30% of that 55 barrels per million coming from pentanes and isobutene, just C4s, C5s. So it is more valuable barrel and the fact with the lower quality components of that Ngl barrel are increasing should obviously help the economics in the [indiscernible].

Ronald Mills

Great and then last one, I know, on the debt exchange Charlie, there is still $135 million stuff out there, is there anything to do on that or is the plan just deal with that upon maturity next September?

Charles Goodson

No, we are still having active discussions with bond holders and just trying to come up with the solutions that works for all of our stakeholders of the company, the other bond holders and shareholders.

Ronald Mills

Perfect, thank you guys.

Operator

And our next question comes from Richard Tullis of Capital One Securities. Please go ahead.

Richard Tullis

Charlie or Bond could you review the drivers for the timing of this Thunder Bayou recompletion, where do you looking for pressure wise, flow rate wise, before you embark on the recomplete.

Unidentified Company Representative

Rich, we got Art here, we’re going to let him handle that one.

Art Mixon

This this is really exceeding our expectations as far as reserves coming out this bottom zone. We've been fully anticipated that we probably already recompleted to the higher, bigger, better sand and we are maintaining as we speak today 25 million gas rate and over 30 million equivalent, out of this existing zone. We’ve got very, very good pressure, we have good water support in this reservoir. So the way to look at it right now at its third quarter recompletion and we’re going to continue to monitor that. We do have a fairly high amount of water rate but we do have the facilities to manage that water and at these rates it makes sense to continue to produce this well at that kind of rate.

Bond Clement

So Rich we do have some declines obviously baked into the second quarter guidance but like we saw in the first quarter those declines don’t come to see us which are likely going to see as another beat on the production guidance side. So we’re just taking this one quarter at a time and we’re going to make the best economic decision when Art and his group think it makes sense to recomplete.

Richard Tullis

And Bond just continuing with the production outlook, what sort of range you think we could be looking at for the second half of ’16 once we get a recomplete at Thunder Bayou?

Bond Clement

We have purposely gone quarter-to-quarter on this production guidance because we have this massive well that’s still important to the Company and it's really -- we can’t predict what high degree of accuracy when that recompletion is going to occur, so I can’t answer that question outside of the guidance that we have out there, because it's all -- a lot of the back half is going to be dependent upon the timing of that recompletion. I wish I could give you more. Until we see some declines occurring that gives a little bit better picture of the timing it's just going to be difficult for us to forecast much pass three months out.

Charles Goodson

And as you know from a technical standpoint anybody who saw the original log and then bounded log, the update log had several segmented sections, the large been the 160 feet at the top and in the down well it was pretty much 500 feet of consolidated sand. And so what this is showing is that as you move away from this wellbore [indiscernible] very far before and back into a very consolidated sand section and which basically increases the reserves of the well.

So I think we had lot of stock, took a pretty appropriate and conservative approach to saying that what this look like out there, but no one understands geologically exactly what happens. And now we have a look back with production, it's doing better than we anticipated. So, it basically is a very positive aspect from us internally and then our partners about the size of this reservoir that it’s -- it appears to be bigger than we originally estimated. And it's going to be a timing issue of hopefully in the next quarter and half where we basically are able to deplete that lower section and then move on up and so I think we’re in, we’re making the appropriate decisions and it will work out pretty much like we think it does over time.

Richard Tullis

And just one more from me and I’ll hop off. PetroQuest is done well filling assets in the past, any remaining asset packages that could be monetized?

Charles Goodson

I mean at this point in time I don’t think we’d like to talk about sales of assets. I think we talked about now we’re a two basin company. We obviously have Gulf Coast, Gulf of Mexico and basically the East Texas Carthage area. I would say that over time that the focus is obviously going to be on the East Texas where we have 108 locations on the 6,000 acres which then trends into a lot of zeros behind the low cash we have. And so it really is a -- and I am trying to think of a question and turn into a logic is where we’ve been pretty obvious we’re going to basically cook it in our kitchen [ph] there and so the other areas will probably see less attention. And so that pretty much summarizes it.

Operator

And our next question comes from John White of ROTH Capital. Please go ahead.

John White

Can you talk a little bit about crude oil and natural gas basis differentials, and what was the experience during the first quarter and what to think for the rest of the year? I was a little surprised.

Bond Clement

You were surprised by what, John?

John White

I think we’re little wider than I thought.

Bond Clement

I think the biggest difference on the crude oil, I don’t think there was any real differences on the gas side. The biggest thing that’s hard to forecast and it's hard for you guys to understand is how we sell gas on a monthly basis. Obviously if you’re selling a higher percentage of gas first a month, first is the gas daily, it can affect what your realization are if you have a lot of volatility in that particular months. Now let’s say we certainly had a lot of volatility on the gas daily average during the first quarter, so that’s probably a contributing factor on the gas side if it's somewhere different than your expectation.

On the oil side, we did have some oil volumes that came to see us in the first quarter, they were actually produced in the fourth quarter. Those volumes came as a result of picking a line offshore in the Gulf of Mexico so the realized price on some of our volumes and we both during the first quarter actually correlate to fourth quarter pricing which is a little wider than we saw in the realizations in the first quarter.

John White

Okay, that helps me out. I appreciate it. Thank you.

Operator

And our next question comes from John Aschenbeck of Seaport Global. Please go ahead.

John Aschenbeck

I had a question on inventory in the Cotton Valley and also keeping in mind you guys also did just have a nice boost in the inventory over 600 locations now. I noticed that that is currently based on a 1,500 foot spacing and was curious of your thoughts on the potential to potentially push that spacing assumption lower and potentially those inventory are little bit higher.

Charles Goodson

When you look at now look at seven benches we basically kind of look at a 1,000 to 1,500 foot spacing and that number has -- we are actually working on the 3P reserve report right now and internally and externally audited. I think those numbers are probably approaching a 1,000 locations when you look at the all the seven benches that we have based on a 1,000 to 1,500 spacing. We do have a scenario where the 1,500 goes to 750 and we’d add additional. But I guess at some time in time it almost becomes silly to talk about it because we’ve only drilled 20 wells out there.

It’s safer to say you can take pretty much these rigs scenario, you want to and run through this area one, two, three or four and we could accommodate that on a relatively easy basis, but that's basically running about 10 wells a year through that and it's why we have decided to focus on this area so we have we literally in this area we have charts showing each and every location what it’s defined for and obviously in many cases not just to anywhere where there are 7 benches on top to each other, but offset operators have staggered and drilled, I think we've seen 3 benches drilling top to each other and there was no communications. So we feel very comfortable that number is way up there and it's very safe and it's a something we can accomplish and that's why we are doing that's why join the things to the company we’ve done to kind of protect that.

Bond Clement

Hey, John. This is Bond. Just to build on and then give you something as you can sort of think about extrapolating. We've obviously done the most work on the acreage position on our 100% acreage on the East side that's why we spend most of our time and most of our wells and in connection with these joint venture were working on in this acreage that we sold down we think there is just north of the 100 drilling locations in the various benches of the Cotton Valley on that position.

So if you extrapolate that to the broader acreage position if you got around a 100 drilling locations for 6,000 acres you probably got you are looking at additional 700 or 800 drilling locations as you move further west. So like Charlie said at some point it just becomes just kind of silly to talk about is your inventory 600 to 800 or 1,000 or 1,200 the point is we've got years and years and years of drilling inventory out here.

John Aschenbeck

Yes, makes sense it's very helpful. And then just the point of clarification on Q2 guidance for flat LOEs just guided slightly higher on that per unit basis and was curious how much of that is related to the East Hoss sale and how much of that's in relation to just expecting lower volumes, Thunder Bayou or just any type of thoughts you can provide there?

Bond Clement

Yes it's a combination of both obviously we take the volumes out from the East Hoss sale you are going to have the higher per unit costs. Those were fairly low LOE producing properties that we sold. So it's a combination not having those assets in the fold in the lower production volume so as you look at projected declines during the second quarter your LOE per unit kicks up a little bit.

John Aschenbeck

Perfect, that's it from me. Thanks guys.

Operator

And our next question comes from Daniel Guffey of Stifel. Please go ahead.

Daniel Guffey

Just curious starting up from last questions. How does the outperformance of the lower inter rolling Thunder Bayou change your expectations for the thicker upper interval, I guess in terms of both EUR and maybe productive capacity and decline?

Charles Goodson

Certainly Daniel, it doesn’t mean that it will definitely be bigger, but it certainly makes us feel very good about the fact that we have a certain amount booked as per SEC guidelines and that the 3P numbers could be significantly higher in that upper zone. So we feel very good that the lower zone has outperformed what our original booking list.

Daniel Guffey

And then I guess just following up on that. I guess what is -- do you guys have in explanation or is it clear cut to why the lower benches out performed so significantly?

Charles Goodson

As like we said as we move away from the well board down depth, where sands are more consolidating and we know that down, fully down there at the end of our reservoir we have a fully consolidated 500 foot solid sand section. So as you move away from our wellbore, you're getting into a -- which has a basically a production path right for a wellbore. There is just a thicker sand section, I'm not saying it's look like the upper section, but it's certainly more consolidated and it just, it's very formal permeable and very pours and so all that gas is simply flowing into our wellbore system, the perforations in the sand against our wellbore and so it means that, we have a thicker sand section down there

Daniel Guffey

Okay, thanks moving to that Cotton Valley, it looks like I mean, you're talking five to seven benches, you're targeting with the JV, and am I right to say that you only landed laterals in two of those seven benches to date

Charles Goodson

That's correct, we have vertical wells that have penetrated and produced and probably six year rates wells in all the benches. So, we know rightly that every bench has been perforated in [indiscernible] long production histories. Secondly, two of those benches have been horizontally drilled on acreage and the other five have been horizontally drilled off our acreage, but very near our acreage. So we have direct lines from a vertical well directly to horizontal well, either one or meaningfully offsetting our acreage.

Daniel Guffey

Okay I guess in those two benches you tested, how many benches do you think can contribute in the production as your 20 year so well that are online. Or said another way, are you getting contribution from multiple benches up and down the column?

Charles Goodson

No we feel like our fracture beam contains within those benches and very comfortable with that and so when we see, like I said earlier, we've seen other operators near us drilled multiple benches that were relatively close together that did not see the interference between the two, there is some good such shale section in between and as you look at this is a sand and a still stone those -- the fracs are basically just, is not a shale where it’s gets into a fracture and can travel hundreds and hundreds of feet. You're just basically fracing into that sand, so still stone right above and below that well, so there might be say 50 to 100 foot travelling up and down, but it's not like is going thousand feet.

Daniel Guffey

Okay, right thanks for the color, I guess last one for me on the completions in Cotton Valley, obviously the last 11 wells that you drilled or completed, since 2014 significantly outperformed your early time results, I guess, what have you learned on the completion side and any tweaks that you may possibly use going forward on that completion and/or landing zone?

Charles Goodson

I think, tweak is the right word, we tried to stay fairly close to our designs and not get too far out of balance with it. There are something I think as we go on that we're going to attempt to learn even further, so the things that we were able to learn in the [indiscernible], through the use of microseismic and those type of tools, and over time we'll be able to apply some of that technology as well as varying sand concentrations and pump it right through them and those kind of things, I think we'll eventually be able to optimize even better our production there. And those are some of the few things that we've done in the last ten wells versus the first 10 although, we do not have any microseismic to date, we’ve had access to some offset microseismic that we got to use qualitatively but we don't like any on our acreage itself.

Bond Clement

One thing about the two is, when we came into, the fact that these thing with work force [indiscernible], we saw that all the early wells that didn't have stage fracking and to be fraced all the frac went into one interval and so you didn't have -- you usually have a communication up and down in wellbore and so these well consistently made about 7/10 of a Bcf, these new wells, we're making 12 times that much because you're able to frac that entire interval, but you’re not travelling very far above those, you’re simply able to frac the whole thing. So that leads into understanding that you didn't have lot of travelling up and down the wellbore on a vertical and we're certainly not seeing it in a horizontal.

Daniel Guffey

Okay, thanks for all that color, just one more for me, the paths that you guys have built throughout the field I guess, what lateral lengths should we expect from those paths that are already built. And I guess if you can walk through your 100% working interest acreage, what's the average lateral link across that high working interest acreage?

Charles Goodson

Most of those probably are around 5,500 feet, is generally about our average

Bond Clement

But Dan, you have to remember that we're going to be limited to unit sized in more cases out there and so you‘re going to have variant degrees of lateral length, there is some of the acreage that we've put together over the last 12 to 18 months that should afford us the opportunity to drill longer laterals, as we’ve got some bigger units to the north.

Charles Goodson

And we've also basically -- you can’t apply for it in working and get support from your land owners to drill multi-unit laterals and I think a little bit more time. We expect really seeing at this stage we’re seeing some operations in Louisiana and offset operators drilling from much longer laterals and it's going to do with a lot of information, but we’ve always been a company that we’re professional and a 100% solution for us and where we can lower our cost and get the best EURs. And I am sure that we’re going to drill some 10,000 foot laterals over time, but right now we’re doing so well that we haven’t lowered the cost structure to maximum level. That’s where we’re going to make the biggest achievement increased EURs, lower the lateral cost per foot, the overall well cost, the efficiencies and so when we finally get that down to its threshold then we’re going to look at drilling longer laterals.

Operator

And our next question is a follow up from Ron Mills with Johnson Rice. Please go ahead.

Ron Mills

Can you guys just remind me the capacity at Thunder Bayou, maybe a different way to at Richard’s question I think the well had at some point gotten up to like 70 million or 75 million equivalence a today. Is that where you become capacity constrained?

Bond Clement

Yes, right now we have about 70 million gas rate, so that’s probably about 90 million equivalent. If you though being equivalent if we were to wrap it up to that rate, Ron.

Ron Mills

And then you just answered the average lateral length is plus or minus 5,500 feet based on the 1.7 to 2.3 Bcf per thousand lateral feet that you mentioned earlier. But looks like in addition to another 10% or 20% well cost savings off of $4 million, it looks like there is also upward bias on that 8.5 Bcf EUR. Am I reading into those numbers correct?

Bond Clement

That’s correct Ron.

Charles Goodson

We were basically drill 20 wells and if you look at the -- we show a dramatic decrease in cost and increase efficiency per lateral foot or $1,000 a foot and we can have every field like now taken this legacy fourth generation, I don’t know how you determine what generation the rig is, but the last books in our efficient rig that’s all of those things are going to continue increasing and really it was only the last probably five or six wells that we were able to really stay in section 100% of the time and we now have that time and so it’s saying that’s it’s a continuing improvement and it's been done over 20 wells and we now feel that we could go out and drill wells with a 30 foot of section and frac still stones above [indiscernible]. We just go out there and there is still a significant amount of improvement over time that we could achieve on all those metrics as we start the program back up and go consistently with rig for multi-years.

Operator

And land gentlemen, this concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks.

Matt Quantz

We like to thank everybody for their time this morning and please follow up if you have any additional questions.

Operator

And ladies and gentlemen, the conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

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