Goodrich Petroleum Corporation
Q4 2014 Earnings Call Transcript

Published: 28 Feb 2015

[Operator:]

Welcome to the Goodrich Petroleum Corporation Fourth Quarter 2014 Earnings Conference Call. All participants will be in listen only mode. [Operator Instructions] Please note this call is being recorded. I would now like to turn the conference over to your Daniel Jenkins, Director of Investor Relations. Please go ahead.

[Daniel Jenkins:]

Good morning, everyone. And welcome to our fourth quarter earnings conference call. I'd like to begin with the introduction of the management team on the call with us this morning. Mr. Patrick Malloy, the Chairman of the Board; Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer; Mr. Robert Turnham, President and Chief Operating Officer; Mr. Mark Ferchau, Executive Vice President of Engineering and Operations; Mr. Mike Killelea, Senior Vice President and General Counsel; and Mrs. Jan Schott, Senior Vice President and Chief Financial Officer. And myself Director of Corporate Planning and Investor Relations. As is our practice, we'd like to make everyone aware the comments and answers to questions made during this teleconference may be considered forward-looking statements, which involve risks and uncertainties as have been detailed in our SEC filings. We will begin with our prepared remarks and then conduct a question-and-answer session. Finally, I'd like to remind everyone that we posted an updated slide presentation that we will reference throughout this conference call. You can access those slides to our website at www.goodrichpetroleum.com through the Investor Relations tab in the events and presentations section. Below the fourth quarter conference call announcement you can click on the more information link and the slide deck will appear. Now I'll turn the call over to Mr. Gil Goodrich, our Vice Chairman and Chief Executive Officer.

[Gil Goodrich:]

Thank you, Dan. And good morning, everyone. As we enter 2014, one of our primary objectives for the year was to transition the Tuscaloosa Marine Shale play from delineation to development mode, and to do so by shaving days of real time continue to refine completion designs to deliver maximum production performance at the lowest completion cost. And to broaden geographic area of consistent repeatable well results. By any measure we accomplished each of these objectives in 2014. By continuous experimentation with new bids, mud systems and reality, tweaks of numerous drilling procedures and rigorous analysis, our drilling payments made tremendous progress through 2014 and into 2015 sadly reducing average drilling days per well. Our completion team work diligently in conjunction with our industry partners to tweak our frac intervals spacing cluster design, fluid and profit mix to deliver best in class results at the lowest possible cost with great success. Our geologic and technical team carefully analyzed and pursued well site selection which is led to a well defined emerging tier 1 core of the play in which Goodrich Petroleum controls approximately 150,000 net acres. Our land team has done a terrific job expanding our footprint during 2014, adding over 20,000 net acres in the core and has a well designed plan to ensure the preservation of the majority of our overall position in all of the 150,000 acres in the Tier 1 core. These efforts will also successfully supported by the rest of our engineering, financial and support staff resulting in the accomplishment of all of our operation objectives in the TMS. The entire Goodrich team is and should be proud what have accomplished in 2014. To update you on our results in recent activities, we have prepared a slide presentation as Daniel mentioned. For those of who you wish to follow along, we invite you to review the presentation now. On Slide 3, which is entitled company profile, you will see our current acreage positions for three core properties where we control on industry leading position in the TMS of approximately 325,000 acres and importantly as I said 150,000 net acres in the delineated core. In addition, we maintained our 30,000 net acre position in the oil window of the Eagle Ford Shale in South Texas and natural gas optionality with our legacy Haynesville Shale position of approximately 36,000 net acres. From a company whose reserves and production will comprise of 98% natural gas in 2010, we worked extremely hard to change the reserve mix over these past four years and the chart on the upper left hand highlight the progress we've made. SEC approved reserves grew to a present value at 10% of $650 million. And importantly, our reserve mix at yearend 2014 was approximately 61% crude oil and 49% natural gas. We also believe it is important to point the robust reserve growth in the TMS during 2014. And as you will see in purple on the chart in the lower left hand corner, we added over $300 million of present value in almost 15 million barrels of crude oil reserves in the TMS last year. During 2014, we spent $273 million of adjusted net growing and completion capital adding just over 100 bcf equivalents or 16.7 million barrels equivalent resulting in an adjusted organic finding and development cost of $16.30 per Boe. Moving to Slide 4. You will see our crude reserve mix in the pie chart on the left where the TMS now makes up just over 40% of crude reserve and more importantly in our view, the huge upside the TMS provide on a 3P basis which only include our TMS acreage inside delineated core uses our low case high curve EUR of approximately of 600,000 Boe and equates approximately 700 million barrels of resources. On Slide 5, you will see the quarterly crude oil production growth achieved during the past year. And in particular the robust growth in the fourth quarter driven by the TMS production growth which equated to approximately 60% of crude oil production in the fourth quarter. This morning we announced a very important transaction for the company with the establishment of a secured Second Lien Notes facility. We view this transaction as a true win-win for the company and the investor as it provide important incremental liquidity and flexibility for the company and tremendous upside to the investor as well as the current shareholders of Goodrich Petroleum as crude oil market heal and we are able to maintain our footprint and continue the development of our core assets in the TMS in particular. Jan will now walk you through the details of the financing on Slide 9.

[Jan Schott:]

Thanks, Gil. We have included the principal terms and conditions on Slide 6. We've raised $100 million on Senior Second Lien Secured Notes at a coupon of 8% with no discount and due 2018. We have the ability to issue an additional $75 million in Second Lien Notes in the future which would not impact our borrowing base. We also issues warrants to purchase up to 4.88 million shares of common stock at an exercise price of $4.66 per share, a 10% premium to yesterday's closing price. We plan to you proceeds to pay down on our first lien credit facility and for general corporate purposes. We also closed yesterday on the 13th amendment to our first lien credit facility. Our facility has been extended one year to February 25, 2017. Our total debt to EBITDA covenant was eliminated and replaced with the maximum secured debt to EBITDA covenant of 2.5x. Maximum secured debt is defined as first and second lien debt only. Our borrowing base is reduced to $200 million and will reduce to $150 million upon the earlier of April 1, 2015 or the funding of the $100 million Senior Second Lien secured notes. Our next predetermination will be in October of 2015. Moving to Slide 7. You will see our current 2015 capital budget and production guidance which we previously released on January 30. We currently plan to invest approximately $100 million in 2015 heavily focused on the TMS where we plan to drill 11 gross and 8 net wells during 2015. In addition, we believe the allocation of approximately $10 million to leasehold and infrastructure will be more than sufficient to maintain all of our 150,000 net acres position in a delineated core of the TMS through the payment of extensions and renewals of the leases we control as well as a substantial portion of remaining block. By design, we have delayed a number of completions in the TMS, where we currently have seven wells drilled, case and waiting on completion in order to achieve even better pricing on our completion to preserve near-term capital and give the oil market an opportunity to begin to rebalance. With approximately 70% of the oil volumes we are guiding to in 2015 has at a very attractive price, we think that this is a very disciplined and prudent plan which can always be adjusted as market condition change. On Slide 8, we have highlighted the 3,500 barrels per day of oil volume hedged in 2015 at $96.11 per barrel. As the oil market begins to rebalance and with the stripping contango we will actively monitor 2016 for the right entry point to begin adding hedges for next year. Slide 9 shows the hypothetical net impact of our oil hedge position given several production volume scenarios. As we are guiding to essentially maintained production volumes around 5,000 barrels per day in 2015, we would expect our blended average price easing the current strip and our hedges to be approximately $83 per barrel this year. Now Rob will walk you through our core properties and in particular share with you our recent results performance and accomplishment in the TMS.

[Rob Turnham:]

Thanks, Jan. Everyone will turn to Slide 10. You will see our core properties map reflecting crude probably and possible reserve exposure in our three core areas. Our 36,000 net acre position in Haynesville Shale in the core of North West Louisiana and the Shelby/Trough Angelina River Trend, East Texas. Our 30,000 net acre position in the oil window of the Eagle Ford Shale located in La Salle and Frio Counties of South Texas and 325,000 net acre position in the TMS which is located in Southwest Mississippi and Southeast Louisiana. As Gil stated earlier, we are seeing tremendous progress in the TMS since our last call. With well reserves consistent and routinely over 1,000 barrels of oil per day and oil cost trending down approximately 23% to current -- of 10 million for a single well pad and approximately 9.4 million for two well pads. On Slide 11, we have discussed at length from past calls about the inherent advantages of the TMS. That it is 92% to 98% light sweet well priced at LLS minus two at the well head which is an approximate $5 premium currently to WTI. The fact that our royalty burdens average 17.4% and there is severance tax abatement in the state of Louisiana and Mississippi until payout of 0% and 1.3% respectively. While our well cost have been a last lever to pull and we are now sitting after better drill times which is averaged 21 to 29 days of late better optimized completion techniques and lower service cost. The optimized well that we and our offset operators have been drilling lately are performing very well, not just from initial rate but over time in our decline curve show. We have a map on slide 12 which spots our 24 optimized wells broken out in four areas. A 150,000 net acre position is shown within the red halo is areas one, two and three with the red stars reflecting wells that had initial production rates of 1,000 Boe per day or greater and again these well are in average of 95% oil. The core today is primary found from the depth of 11 to 13,000 feet however we now have three wells in area four that are described as core that are performing very well. Our optimized criteria is shown on slide 13 is that well land in the lower portion of the TMS. They are drilled with the minimum a 5,000 foot laterals, the fracs are at least 1,500 to 1,600 pounds per foot and you pump hybrid frac job, a combination of sleek water which creates complexity followed by gel that transports the sand out into the complex fracture network. Of the 24 wells we have identified as optimum 13 are ours and 11 are operated by other operators in the play. Slide 14 shows area one wells versus our 600,000, 700,000 and 800,000 barrels high curves. The Crosby well as everyone knows is in the poster child for the play as it has been online for 24 months and it is produced in excess of 210,000 barrels equivalent in that period. In addition, several wells have come online over the last five to six months including our CMR Foster Creek 31 which is shown in light blue which is tracked well above our Crosby well. In fact, several wells are currently flowing at our above the Crosby well over the first five months and you see that on this graph. Slide 15 shows area two wells which are also performing well. Our poorest optimized well drill to date is our Nunnery well as shown in lavender which sits on the north east edge of our property and that well result has a very good correlation with our Passey log analysis that seen in our management presentation and that when you overlay resistivity with porosity the TMS is thinner near the Nunnery thus driving the slight under performance. The slide also shows the effect of our artificial lift as both the CMR8-5 which is the 5,300 foot lateral and the CH Lewis 30-19 wells that responded very well with optimization of jet pump settings. We see the benefit of longer laterals ideally but with that said our blades well on slide 16 remains one of the top outright performers and certainly a top performer per foot over the first 10.5 half months as it is currently producing above our 800,000 barrels curve from 500,000 to lateral. We didn't put the blades on artificial lift until seven and half months and you will see how well has performed since then. Area three comprises almost a 100,000 net acres is where you likely see a high percentage of our 2015 development including numerous two well pad wells which will further drive down well cost. Area four on slide 17 although not currently identified as core continues to provide upside potential as the Beech Grove and SLC wells are performing very well, recent well from another operator brought online at north of 1,000 barrels of oil per day in the area. On Slide 18, we show all 24 wells compared to our 600,000 and 800,000 Boe curve and you can see the newer wells are getting better as completion methodology has been optimized. In fact, again several wells both operated and non operated are running ahead of our across B decline curve. When you average those wells into a composite curve as shown on slide 19, we are producing on our above our 700,000 Boe curve. When you bake in the net revenue interest of 82.6% which is again higher than most other basin net revenue interest, the higher realized price of LLS minus two at the well head which is currently as I said earlier a $5 premium to WTI versus other basins which are discount to WTI. And the lower CapEx of $10 million we are seeing now for single well pad, the rates of return at $65 to $75 oil are 22% to 33% on our low case curve and 32% to 48% on our composite curve. At 100 acre spacing, we are estimating 1,500 to 2,000 locations when high grading the acreage to our core. As mentioned earlier our drill times had continued to improve for both us and our peers and you see the gradual progression on drill times since the first quarter of 2014 on slide 20. As we said in our release, the real improvement has come lately as the last five wells have all come in less than 30 days including our very last well the B-NEZ 1 21 days. On Slide 21, we've laid out a breakdown of where we've seen the cost reductions from $13 million to our current two well pad estimate of $9.4 million which is for our 5,000 foot lateral in the Blades areas since we've seen results on or above our 800,000 barrel curve with shorter laterals in the area. As previously stated a reduction in drilling days combined with lower service cost has allowed for an approximate 23% reduction in well cost. Moving to Slide 22, if you layer in 10 million well cost estimate for our one well pad you will see a very attractive rate of return of 48% under a more normal oil price environment of $75 and the sensitivities as shown on slide 23 from $65 to $85 oil show 32% to 68% rates of return with the new well cost. In summary, the wells have been very consistent when drilling and completing them in optimal manner. The well costs are down significantly such that we will be generating very attractive and competitive rates of return when oil prices return to a more normal range which we expect in the back half of the year. I'll now turn it back over to Gil for some closing remarks.

[Gil Goodrich:]

Thanks, Rob. Like many of our peers, the past few months have presented a number of challenges to which we have responded aggressively and decisively and I believe prudently and in the best interest of our all stakeholders. With the announcement this morning, we are now far better positioned to not only well the current downturn but also be extremely well positioned to benefit as the oil market recovers in the coming quarters and years. And there are some silver lining in the current market, which include the real cost improvement as Rob has outlined for you, which we are seeing not only across the industry but in particular with our experience in the TMS, which is included in not only reduction in build growing day but also enhance completion designs. We look forward to demonstrating the enhanced economic returns in the play in 2015 as we expand development of the TMS which we believe is developing into a premier US shale or play with prolific flow rate and excellent EUR. Also priced at LLS near the refining complex. With that concludes our prepared remarks. And now I'll turn it back over to the operator for questions.

[Operator:]

[Operator Instructions] The first question is from Neal Dingmann of SunTrust. Please go ahead.

[Neal Dingmann:]

Hey, guys, say Rob and Gil just looking at the Slide 12 that obviously shows all of your area there at least the core area. And two questions around that, one, looks like on that I see two rigs currently drilling which is one of those does refer me is that non-opt and then secondly, when you talk towards the end about this current well being drilled and I said I think you said you on pace to a $10.5 million cost on this, are you seeing that across anywhere from area one to three, I guess how different if you can comment on a couple things. One is geology, how much different is it between area one, two and three there and then as you see as you expect those cost to come down is that pretty much blank in the entire 150,000 area?

[Gil Goodrich:]

Yes, Neal. And by the way it looks like we may be missing our rig; there are three rigs running currently, two non operated rigs and then our rig which is in area three. As to drilling areas that how consistent to drilling might be, we are not seeing a tremendous difference in one area versus the other. That being said our last well that we have been drilling from the Verbane to the Kent and Williams and Painter have all been area three and we will tell you certainly that area is drilling as good if not better than any other area. So I think the geology as you know is very consistent across the play. We might have a little more fracturing in one area or the other, obviously the natural frac -- naturally occurring fractures are positive but if it is really busted up it can create a little bit more difficulty in drilling. That being said we've kind of figured out how to get through all of that and not seeing in real issues there. But certainly area three if anything where we have 100,000 acres drills very quickly and that's where we drilled our 21 day well.

[Neal Dingmann:]

Got it. And then just one last one. Rob, what or how and Gil look at it obviously now that you have done this financing liquidity certainly more than adequate now for quite some time, how do you see of that you obviously have a lot of other different alternatives, you could bring in Sinopec maybe do something else with them. You got Eagle Ford. Obviously, the gas market improves; you certainly have some Haynesville, et cetera. Just with all these options out there on the table, how do you view those today now that you have gotten this deal done?

[Gil Goodrich:]

Yes, Neal, it is Gil. Thank you. First of all, I want to think that it does for us it gives a great flexibility and that exactly right gives us the timing on exactly when we might want to launch the Eagle Ford sales process. That still within the mix and still part of the planning. We've not really change that plan but this does give us a time to be a little more flexible and see where contango in the market is and -- prices are so we are just kind of monitor that over the next few months and see when the right time to launch it.

[Neal Dingmann:]

Very good, thanks.

[Gil Goodrich:]

Neal, you may hang up but just one other point if we do exercise or certainly add another $75 million as we said we have the ability to do. We are not expecting a reduction in borrowing base from that. That's already basically baked in. And I think Jan had that in her prepared remarks.

[Operator:]

The next question is from Ron of Johnson Rice. Please go ahead.

[Ron Mills:]

Hi, good morning, guys. Good color in the presentation on the call. When you look at your capital spending, you have one rig now, what do you all think of the pace of drilling throughout the year and what's your -- the pace of your completions expected to be over the years since you have been deferring them so far?

[Gil Goodrich:]

Yes, great point. In fact had we said decided to complete the well timely, our guidance for the year certainly would be at a higher rate. In fact, we've often talk about what is our maintenance CapEx, the whole production flat for example we average above 5,800 barrels a day in the fourth quarter. And we completed our wells timely, spent $100 million, in 2015 we think well volumes would have been basically flat to that, maybe perhaps up slightly. But it is the delays that causing volumes to be down slightly from fourth quarter. Currently in the modeling, we have one well set to be completed in March, we have three wells in the second quarter, four wells in the third quarter and one well in the fourth quarter with two deferred into 2016. So it is -- I think Jan said it is a combination of pushing capital while we continue to reduce our service cost. And it is to wait and to sell those barrels hopefully in an improving oil market and certainly the contango in the strip as we sit here.

[Ron Mills:]

Then Rob, in terms of the pace of drilling, you plan on, how do you plan on managing the drilling rig that you have right now just trying to reconcile overall drilling and the completion CapEx?

[Rob Turnham:]

Yes. Good point. So really our current plan is too led-- is to go down drop the last rig, call it 30 to 45 days and then pick it back up, call it in the third quarter. And in the mean time that will allow us to go ahead and complete the backlog of wells as we just lay out. So the CapEx spent from second quarter and third quarter and particular the second quarter is going to down a good bit as we wait to begin completion of the well that are currently deferred and shut in. So a little bit more front end loaded CapEx in the first quarter because we entered the year with three rigs running, now down to one. And then as we layer in the completion, obviously spending money at a lot much slower pace. And we will pick that back up later in the year when we pick the rig back up.

[Ron Mills:]

And then probably last for me, when you look at area three it is core or is the focus of your drilling activity is two parts, how many of your 11 gross a net wells are going to be in area three and is this one of those instances where at least looking at your well production charts, is it somewhat driven by lease maintenance where you have more held area one and two but despite that your activity of isn't an area that looks like it is turning in some of the best results?

[Rob Turnham:]

Yes, I think that's a pretty good assessment. As to the number of wells, I'll just give a kind of broad estimate call it maybe 2/3 in area three, 1/3 in area one. Area three as I said has about 100,000 net acres. Area one is not as big and a good portion of area one is Crosby, minerals, foster Creek acres which has kind of a continuous development provisions built in, foster Creek in particular. Crosby is still in the primary term. So it is very easy to manage the acreage commitment in area one. As Gil and Jan both said and we have the ability with our 10 million leasehold budget to maintain our core acreage position. We would have a little bit more leasing in area three than any of the other areas. So therefore it kind of make sense we are making it good if not better wells in area three. We have Sinopec as the partner in area three and it is capturing some acreage that we would have to be extensions or renewals on.

[Operator:]

The next question is Leo Mariani of RBC. Please go ahead.

[Leo Mariani:]

Hey, guys, I was hoping you can speak a little bit longer term to sort of protecting the acreage obviously you guys laid out plan for 2015, but how does that start to unfold in terms of what you need to do as you get into 2016 and 2017?

[Gil Goodrich:]

Yes. Leo, it is Gil. So we've taken a real hard look at that and we think about another $10 million allocated in 2016 continues to preserve all of the 150,000 acres in the core. And we will continue to maintain a fair amount of acreage that is still in primary term even out end of 2017. So we certainly don't think we will maintain the entire 325,000 acres if you say in the exact position we are today without incremental capital and or partner coming in. But all those thing will be unfolding in 2015, so we think we are in a good shape to hold what we delineated and that would stretch all the way through 2016 as well.

[Leo Mariani:]

Okay. I guess does that assume any drilling ramp in 2016 or would that also assume the one rig plus the $10 million and then I guess can you maybe just also comment on what you guys think you are in the JV process and how a JV could change the plans as you get into 2016?

[Gil Goodrich:]

Sure. We would assume, Leo, a similar type budget in 2016 to what we have today plus a little bit more drilling in 2016 than in 2015 but not materially as well as say another $10 million allocated to extensions and renewals. Obviously JV process is on going, oil prices have not been help on that, and so we just are taking a bit of pause here but the process will go on and as we see oil market start to heal which we hope will happen in second half of this year, we will continue to uptick that back up and time look for partners that might be interested in joining us in this play.

[Leo Mariani:]

Okay, that's helpful for sure. I guess just in terms of your cost, so I noticed that G&A was down a fair bit here in the fourth quarter. LOE was down a little bit as well. I guess you guys are pursuing some potential aggressive cost reduction initiatives here in 2015 and if so, can you speak to that?

[Gil Goodrich:]

Absolutely. We are targeting a minimum of 20% reduction across the board that will include G&A. We don't have a specific number to give you this morning on the LOE but we are working very, very hard on getting those costs down and we are confident as they will, not sure the exact extent but making good progress really across the board.

[Ron Mills:]

Okay, that's helpful and I guess sounds as though the TMS has been much more consistent for you guys. Just try to get a sense of when was the last time you actually had a mechanical issue on a well? Hasn't been pretty clean for a while now?

[Gil Goodrich:]

Yes. I would say the last issue was probably about this time a year ago. That's the point on which we move to drilling lower target only wells and had a little bit steeper pitch to avoid problems rubble [ph] zone. Since then everything has gone quite well.

[Operator:]

The next question is from Michael Scialla of Stifel. Please go ahead.

[Michael Scialla:]

Good morning, guys. Maybe follow-up on Rob, you did a pretty thorough job of answering Ron's question on the timing of completion but I'm just wondering if what would it take to change that timing have you -- say you see the 15% to 20% cost savings you are anticipating? And would that be enough alone or would you need to see an improvement in oil prices as well?

[Rob Turnham:]

I think some combination of both of those things would be ideal but we do maintain that flexibility to accelerate when we see a maybe little bit of improvement in oil and further reduction in service cost and by the way we think we will continue to see service cost come down. In fact as recently as this morning, we got word that said potentially something on the completion side to the lower, so haven't pegged number exactly, I mean obviously 12 months forward looking strip at $65 generates pretty good rates of return and that's kind of $7.5 to $10 movement from here. We will see but you are right the same percentage decrease further in service cost creates the same rate of return because we are in margin business and it is combination of oil price and revenue versus what the well cost. We will maintain, we will continue to watch the market and adjust accordingly.

[Michael Scialla:]

Okay. And the 3P estimate of $693 million in the TMS, can you talk about the assumptions behind that?

[Rob Turnham:]

Yes. You will see in our normal management presentation that we have on our website, we've taken the core so 150,000 net acres and plugged in 600,000 Boe per well which is below case curve, plugged in, there is a little less 1,500 net locations after you back up and prove and that's basically at our blended average royalty burden or blended average net revenue interest, times and number of net locations at the low curve get you that number.

[Michael Scialla:]

So given that number locations you're really just looking at the core area? The 150,000 net acres?

[Rob Turnham:]

Yes. And as we kind of walk people through area four is getting more and more interesting but all of our capital this year is going into the halo low areas one, two and three. And we just felt it is prudent to just include that in the inventory chart.

[Michael Scialla:]

And my next question actually you were headed in that direction sounds like the well that you mentioned that look interesting in area four, could you speak to those at all?

[Rob Turnham:]

Yes. We were always a little bit confused as to why the initial rates were quite as high as what we saw in areas one, two, three. But when you look at core data, when you look at the capacity analysis on the log, we only see subtle difference if any. But yes the currents have been flatter so as we pointed out initially, initial rates were quite as high but within 45 days, we had intersected the curves and you can see they are continuing to kind of ride at least somewhere between the low to mid case or optimize composite curves. So still very pleased with it. It was to set to see how it plays out and by virtue of all of our activity being in areas one, two and three will have more to this kind of monitor the decline curves but obviously very encouraged by those three wells. And the new wells that was recently added.

[Michael Scialla:]

Was that new one a non-opt well?

[Rob Turnham:]

Yes. It was.

[Operator:]

The next question is from Kim Pacanovsky of Imperial Capital. Please go ahead.

[Kim Pacanovsky:]

Hey, good morning, everyone. I'm looking at your area two slide I guess it is Slide 15 and the two non-op wells that have been online for three months I assume those are in Canada wells that are outperforming the curve? Any ideas on what's contributing to that outperformance? Was a lateral length or --

[Gil Goodrich:]

Hi, Kim, this is Gil. I would say mainly it is refined, tweaking of the completion. Those are little bit bigger proper amounts core foot. Rob talked about 1,500 to 1,600. They are up a little bit higher than that. I think that's probably is, well located within kind of the western part of the area two. And I think that's really is. One of them maybe slightly longer and lateral but most of these are 6,000 to 7,000 feet and occasionally few of them are between 5,000 to 6,000 feet.

[Kim Pacanovsky:]

Okay. Then on the well cost I think I might have misunderstood something as you are talking about the $10 million or $10.5 million AFC and then on slide 22 you have an $11.5 million. What's the difference between those two numbers?

[Rob Turnham:]

Basically when we last did slide that was our AFC, good catch. That number is now down by another $1.5 million so which totally miss that, current estimated cost right below it was changed but we didn't just adjust single well pad. And that's mainly just driven by the days, as I said this last wells drilling quicker and the service cost reductions that we've already seeing the good bid of.

[Kim Pacanovsky:]

Great. Okay. So then is the $10 million, so the current cost now, the current AFC is $10.5 million?

[Rob Turnham:]

It is actually $10 million. So that last well again the service costs are coming down. I mean every few days we have a new estimate. So as of yesterday our estimate is $10 million, when we drill the recent well in 41 days, that's the B-NEZ 1, we have drill this to 4.1 and then we had still factored in some additional cost based on the last set of bids and now we have new bids that have come in recently. So again this slide needs a little work and we will make sure we correct it.

[Kim Pacanovsky:]

Okay, great. Then just pure curiosity here on your map with your areas one through four. I'm wondering why your area two is extending into I guess the 13,000 foot line when I don't see a lot of red dots on the map there, so I don't know what kind of data has you grouping that area and with very two rather than area four?

[Rob Turnham:]

Yes. I can see what you are talking about. We have a lot of core data, that's the warehouse area where it kind of been back around, little bit south of that and if you look at that data, a lot of the wells were not 1,000 barrels a day wells but they were very much under stimulated and even the best well up -- there was a 1,000 barrel a day well but it wasn't optimized. So it wasn't completed properly and therefore we kind of bend that curve in and then back around to include some additional acreage. So there was a method to the madness, it was based on geology and core data that suggested plus some well data that we already had but may be didn't hit the 1,000 but it was a still -- obviously good enough to bend that curve.

[Kim Pacanovsky:]

Okay. Then finally just on the hedging side, you mentioned you are looking for the right entry point to pull some 2016 hedges. Just making an assumption of well costs coming down, just say another 5%; let's say 5% or 10% by the end of the year. Where is that entry point for you for 2016?

[Gil Goodrich:]

Yes. Kim, it is Gil. Little difficult to say exactly 70-ish looks like a place where we might like to start laying in some, we have to be very careful however that if the market really starts to heal and prices start moving up, so will our cost and we want to make sure we don't lock ourselves in on something where we start getting compression from the downside by cost inflation and yet we are locked in. So but 70 maybe high 60 to 70 could be an entry point startup and begin layering a little bit. And just kind of take it as we the market healing over time.

[Kim Pacanovsky:]

Great. I do want to ask one other thing. Can you just comment on the preferred payment? I'm not a big lover of the message boards, but there had been some chatter about the preferred, and, of course, that was prior to the second lien that you announced this morning. But could you just comment on the preferred?

[Rob Turnham:]

Very simple answer. We have a board meeting schedule for I believe it is next Tuesday. Second I believe it is March 2nd, and the preferred payment is part of the agenda for that meeting.

[Operator:]

The next question is from Joe Allman of JP Morgan.

[Joseph Allman:]

Thank you, operator. Hi, everybody. So assuming NYMEX futures -- my model is indicating that you will need more capital late in 2015 or into 2016. I understand you have capacity on your revolver, but you don't want to get too tight on that revolver. So could you confirm that if you do assume NYMEX futures that you will be looking for some more capital either later this year or at some point in 2016, again assuming NYMEX futures and if so what are the options? It seems to me that the first option might be the $75 million extension on the second lien term debt, but could you go over the other options, the Eagle Ford sale, TMS JV, TMS, just sell part of the property and some other options?

[Rob Turnham:]

Yes. Joe, this is Rob. I probably would not agree with your argument that we do need more capital but however we are setting ourselves up so that we have plenty of liquidity with $75 million kind of second tranche f you will. We haven't decided to do that but it gives us that flexibility to do that. Also as we pointed out the borrowing base doesn't go down with the addition of $75 million. So if you do math there that gives you $325 million call it $150 million borrowing base plus $175 million of senior secured notes and that's obviously plenty to get you frankly well through 2016. That being said one of the reasons we decided to go ahead and term up some debt is to bridge until we see better oil prices so that we can either sell the Eagle Ford or do a TMS JV, but we didn't want to do it until oil prices recovered somewhat. So we want -- we are going to sell that property, we preferred to sell into a good take and in a good market versus trying to jam it through when oil prices are still challenge. I'd say those kind of as we sit here right now are two of several items that we could -- several levers that we could pull.

[Joe Allman:]

Great. Very helpful, Rob. Thank you. In terms of in your reserve report, what did you book your TMS wells at in terms of EURs, the PUDs? And then what is the EUR assumed in your proved developed TMS wells as well?

[Rob Turnham:]

Yes. I'd say we had some wells that are over 800,000 Boe and then we had some that are 500,000 Boe. It kind of depends on the haircut that they took. But I think we have a number of PUDS that we use 600 on Boe again that we can book -- one third developed two thirds undeveloped on the TMS, so in essence two PUDS for every PDP. Ironically, we are about the opposite of that in the Eagle Ford in the Haynesville. And about two third or 60% developed in both of those under areas. So we have a plenty of room to add to, our challenge and the reason we want even higher than they were just capital. How much capital doe you spend and when do you spend it is just the function of liquidity and balance sheet and desire to drill on this oil environment?

[Joe Allman:]

Okay, very helpful and then just lastly as you look forward to the October borrowing base re-determination, hedges are rolling off. Where do you get help? Do you get help on the proved developed reserve side with the completions you are doing? And talk about any other help you might get on that October re-determination?

[Rob Turnham:]

Yes. That's basically -- that's exactly right with this backlog of wells, seven wells or TMS wells that have been drilled all in the core, so the question is just when do you complete them, do they all get into the borrowing base for October. I think we have one well left to complete in the fourth quarter. And we can always accelerate that and bid into the third quarter, if we wanted to add these reserves to the October re-determination.

[Operator:]

Next question is from Jeff Campbell of Tuohy Brothers Investment Research. Please go ahead.

[Jeff Campbell:]

Good morning. First question was of the 23% total well cost reduction that you've identified to date, what percentage of that is from faster drilling and what percentage is from service price reductions?

[Rob Turnham:]

Yes. Well the way we tend to look at is your spread rate which the total cost while drilling is roughly a $100,000 per day. So we go through that analysis or we go from 40 to basically 27 days, that's a $1.3 million right there if you just want to kind of look at it. And you can see kind of matches, we are showing a $1.6 million on the total drill so you could say the million three is kind of just better drill time and then another $300,000 on the drilling side. But you could see the real savings are on the completion side. We go from $6 million all the way down to $4 million and that's primarily, there is a little bit of difference between the 5,000 foot well and the 6,000 foot lateral, but most of that is just a reduction in service costs coming on the completion side. Lot of that will include production casing because pipe prices are low and obviously fracs are lower. There has been a lot more room to cut cost on the completion side.

[Jeff Campbell:]

Right. And I assume sands and maybe even some fluids are cheaper as well, right?

[Rob Turnham:]

Yes. Exactly. We are -- an amazingly low price for our sand in the TMS and we are basically -- we have a deal which we are very happy with at less than $0.04 a pound versus some of these other plays ace are multiples of that.

[Jeff Campbell:]

That was very good color. I appreciate that. Second question was having you made any corporate structure reductions as part of overall cost control? We've been hearing about that through the industry rather than --

[Rob Turnham:]

Yes. For sure. In fact, we all kind of mentioned when asked about G&A we are kind of projecting across the board 20% reductions. And lot of there -- first guys you lose and therefore reduce cost is really with consultants, less activity means less guys in the field, less guys in house that are helping you drill with more activity. That’s the easy part. We are drilling not late any more to date. And hopefully can continue to do that. We think that we will-- first you got to be mumble and you got be able to monitor that.

[Jeff Campbell:]

Okay. And last I'm going to ask -- this is almost like mumbling out loud, but I'm actually surprised, considering that the peer E&Ps and the TMS have either significantly slowed or ceased drilling in 2015. I'm surprised that landowners are even demanding extensions. Is there still an active TMS leasing market that you have to try to protect yourself from with the extensions that you've talked about?

[Rob Turnham:]

Yes. I mean the question is if you are not going to drill on a lease when you due to oil prices then you have two options. Let a lease go, go try to renegotiate a new term. And we are in the area of that is very supportive land owners; we have a very good relationship with not only land owners but the regulatory groups in that area. And you just have to make a choice is to whether you let acreage go or whether you go out and buy some more term with lease extension renewal.

[Operator:]

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

[Jeff Grampp:]

Hi, guys. Just had a question on the service reductions that you've seen so far and you guys highlighting a 15% to 20% number. Is that what you guys have observed to date, or is that maybe a near-term expectation and it sounds like you guys are still seeing things get reined in? So wondering maybe over the next three, six, nine months, what the expectation is on some further help on the service side?

[Rob Turnham:]

Yes. If you go back to page 21 again Jeff just kind of looking at the cost to ramp down, again about $300,000 so not a whole lot of drilling side we expect to see more there. But $2 million reduction or even a $1.8 million in the completion cost offer the $13 million well as call it 15% to 20% reduction that we are seeing currently and we think you could see some additional cost reduction from there.

[Jeff Grampp:]

Okay. Then I guess a couple clarification questions on the new debt here. Is there expiration on the option for that additional $75 million, and are there any additional warrants associated with utilizing that option?

[Rob Turnham:]

Quite a bit of flexibility there but no, we have the ability to add $75 million during the term of the loan which is for a year.

[Jeff Grampp:]

And on the warrant side, is it basically the warrants you've already laid out, is that it?

[Rob Turnham:]

Yes. It kind of depends on -- if we go back to the same guy or if we bring in someone else then obviously that could be more flexible. So we try to structure such that we have some flexibility on -- if we bring an additional investors but if we go back to the same investor we would expect the terms to be similar but re-price based on wherever the stock price is when go enter into the second tranche. So the 10% premium and coupon would be similar.

[Jeff Grampp:]

Got it. That makes sense. And then last one for me on the 11-ish TMS wells or so you guys are planning for 2015, do you guys have a good number on how many of those will be on multi-well pads? And of those, are you guys planning on doing anything more than two wells per pad, or is that a good number you guys are comfortable with at this point?

[Rob Turnham:]

Yes. So probably 50% to 60% of our current schedule would be two well pads and two wells we are doing doing, we are still in acreage capture mode, we can put the location in between two units in Louisiana to capture as much as 2,200 acres with two wells and then in Mississippi we can capture 1,900 and 20 wells, 1,900 in 20 acres with one well initially but you come back and drill the second well either in the later day or if you want to go ahead and drill it while on the pad then you do it there.

[Operator:]

The next question is from Dan McSpirit of BMO Capital Markets. Please go ahead.

[Dan McSpirit:]

Thank you and good morning. Among the several options before the Company to replenish liquidity and maybe raise working capital from additional second lien to selling PDP reserves to maybe some flavor of equity, how do you rank them in terms of lows to highness, cost to capital, just trying to get out what is the most likely option to be exercised?

[Rob Turnham:]

I'll tell you what from cost of capital if you look at where everything else is trading versus what we just put in place with our senior secured notes. We are not sure that the market appreciated the quality about investment and obviously we can't say who it is with but obviously very supportive of the company. But it doesn't compare to what some of the other things are trading. And other than that just kind of we can't discuss hypothetical raises, how we are going to do it other than -- we have always talked about the Eagle Ford being-- we are not allocating as much as capital to that, at the appropriate time it might make sense to just sell that or joint venture. We don't even have to sell it; we could JV it bringing some capital that way. You are not likely to see us do in any more preferred and or convert. So it is really with the $75 million stretch fees or additional charge, that gives us plenty of flexibility to not do anything unless we something that make some sense and then we will react accordingly.

[Operator:]

Next question is from James Ulland of Ulland Investment Advisors. Please go ahead.

[James Ulland:]

Hey, guys, I'm just wondering since the preferred dividends on the Board agenda for Monday, if the Board Chair could give us a little more color on the considerations the Board has on paying that or deferring it?

[Gil Goodrich:]

Well, this is Gil. I'll just step up say that we will not share at this time on this call what our Board's deliberations are, that's for the Board to do and we will -- it is one of a number of other things on the agenda. It is not the only thing. So once the Board makes a decision you will be hearing from us.

[Operator:]

The next question is follow up from Ron Mills of Johnson Rice. Please go ahead.

[Ron Mills:]

Rob, just clarification on Slide 21. I want to make sure, the $4.1 million that the B-NEZ well cost, does that include the casing being run? I'm just trying to reconcile the numbers

[Rob Turnham:]

Yes. That better immediate case.

[Ron Mills:]

Okay. When I look at that, it's 21 days versus the 29 days, so that's another $1.7 million cost reduction? Is that the right way to look at that?

[Rob Turnham:]

Yes. Go back to your original question, we will make sure we get that right. So you are on page 21

[Ron Mills:]

I'm on 21. And then another point in the presentation you talked about the B-NEZ well with 21 days costing $4.1 million. I'm trying to figure out how I can reconcile those numbers to try to triangulate what wells will cost based on days.

[Rob Turnham:]

Yes, exactly right. So, yes, that's going to be drill cost and we typically -- I believe that's full lateral, you drill the full lateral but I think it is prior to intermediate casing, and prior to the production casing which is part of your completion. We drill the well then we move into completion mode to run production casing and then -- after that then you run it and compare to frac as well.

[Ron Mills:]

But if I look at the middle column there, you have a 6,000 foot single well for 29 days costs $5.8 million. Is that $5.8 million comparable to the $4.1 million on the B-NEZ that was drilled in 21 days?

[Rob Turnham:]

No, Ron. The B-NEZ would be more comparable to the 3.8 plus the point seven.

[Ron Mills:]

Okay. Great. And then also on that table, is there any significance to why on the two-well pad you have an assumed 5,000 foot laterals versus a 6,000 foot lateral?

[Gil Goodrich:]

No. I think main reason is that as you look at our blades well which is 5,000 foot lateral and as Rob mentioned earlier we think most of our two well pads will be downtown area, we through that as an option that we made drill some 5,000 foot laterals down there just want to show that for you.

[Operator:]

This concludes our question-and-answer session. I'd now like to turn the call back over to Gil Goodrich for any closing remarks.

[Gil Goodrich:]

Yes. Thank you, everyone. We appreciate your participation this morning. And we look forward to updating you in the near future. Thank you.

[Operator:]

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.