Talos Energy Inc. (TALO) Q3 2015 Earnings Report, Transcript and Summary

Good morning. My name is Karol and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Stone Energy's Third Quarter 2015 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I will now turn the call over to Mr. David Welch, Chairman, President and the CEO of Stone Energy. You may begin.

Okay. Thank you, Karol and welcome everyone to our third quarter 2015 earnings conference call. We're joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. First Ken will read the cautionary statement and then review our financial performance for the quarter, he will then turn it back over to me to discuss the adjustments we've made to our cost structure and outline our path to future profitable growth. Ken, to you please.

Alright, thank you, Dave. And let me start with the forward-looking statement. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration, development, production, sales of oil and natural gas. We urge you to read our 2014 Annual Report on Form 10-K and the soon-to-be filed third quarter 10-Q for a discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements, we may make today. In addition, in this call, we may refer to financial measures that may be deemed to be non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. And with that, I will move. We'll assume everyone has seen the press release and the attached financials. Accordingly, I'll just focus on some key financial and operational highlights. In the third quarter results we had an adjusted $8 million loss or loss of about $0.15 per share before pretax, non-cash impairment charge of $295 million, which brought the reported loss to $292 million. Our discretionary cash flow for the quarter was about $67 million, or about $1.20 per share. As was also discussed in last quarter's conference call, the non-cash ceiling test impairment was primarily due to lower oil gas and NGL prices, which are calculated using a rolling 12-month trailing average. If prices continue to stay at lower level that are compared to last year, we would be subject to another non-cash ceiling test impairment in the fourth quarter; again no cash - no impact on cash flow, but a potential impact reported earnings. Production for the quarter including the impact of approximately a little over 100 million cubic feet equivalents per day in September curtailment the Mary field in Appalachia was 40,000 barrel equivalents per day or just under 240 million cubic a day, which was above the upper end of our adjusted third quarter guidance of 231 million cubit a day. In fact, we hit our original guidance despite the shut in at Mary. The outperformance was primarily due to virtually no unscheduled downtime in the Gulf of Mexico versus our base guidance which doesn’t corporate some projective hurricane downtime in the quarter. The Gulf of Mexico volumes again were about plan. Additionally volumes in Appalachia were tracking above plan before the Mary field curtailment. Production from the Cardona 6 well also positively impacted the volumes up with the third quarter. The volumes from the oily Cardona wells and the curtailment as a primarily gassy Mary field boosted the liquids percentage up to 63% in the third quarter with gas at 38%. The Cardona field with the number 4, 5 and 6 wells is now producing at approximately 15,000 gross Boe per day and the Cardona 7 could add another 4,000-5,000 Boe per day by mid-2016. Remember Stone has a 65% working interest in these Cardona wells. We also expect to have the volumes from Amethyst coming online for the first quarter of 2016 and then production from the Pompano platform rig program volumes throughout next year. So we would expect the deepwater Gulf of Mexico to continue to show high margin production growth into 2016. In the third quarter, we averaged about 104 million cubic feet equivalent per day in Appalachia despite their curtailment of the 100 million a day in Mary. We’ll continue to monitor the situation at the Mary field but we want to make a good business decision on when do we start production, which includes generating appropriate margins for our shareholders. As highlighted previously, we don’t expect any new wells to be drilled and completed in 2015, so we would expect the Appalachia volumes to show declines - a decline into and throughout 2016. We do have 25 wells on three pads where we’ve drilled, but not completed the wells, waiting for improved margin and our margins and pricing. The Mary curtailment is expected to impact our fourth quarter volumes by about 35 million cubic feet per day per month are over 100 million cubic per day for the money if we remain shut in. Without Mary, our overall company fourth quarter volumes are expected to be in that 25,000-26,000 barrels equivalents per day or roughly 150 million to 156 million cubic feet equivalents per day. This includes about a week or so of bear in time at Pompano for the platform rig installation. Accordingly, we are adjusting our full year 2015 production guidance to 39,000 to 41,000 barrels per day, which does assume a Mary shut in for the full quarter. Regarding pricing, our quarterly oil price realization before hedging was around $45.50 per barrel which is down over 50% from our $94 per barrel from a year ago. Our overall hedges at $92 per barrel pulled up our third quarter realized price to around just under $70 per barrel with certainly the oil price drop was a significant hit to revenue for the quarter. Our gas price realization before hedging - before hedges was a $1.65 for the third quarter due to both weak Henry Hub benchmark and a very negative Appalachian differential. After hedging, our realized price was $2.09 per Mcf. However, if you incorporate the gas hedge contribution from the derivative income like which added about $4 million before noncash charge guide us down to the $2.4 million. This would have added about $0.45 per Mcf to the adjusted realized price are would have guidance up to about $2.55 per Mcf. As we have noted previously, we are hopeful that the expansion programs from the midstream and pipeline companies in the Appalachian area will increase the access out of the base and ultimately reduce the negative differentials over the next 12 to 18 months. The current pricing environment remains very poor in the area which is led to our curtailment at Mary. In the third quarter, our realized NGL prices dropped under $8 per barrel as Appalachian NGL pricing continues to experience a severe discount from an already low product price environment. Historically, the NGL volumes have provided a pricing step up on an Mcfe basis but at this price point, it actually pull down the Mcfe gas price and we’re still burden with the high processing charges which contributed to our decision to shut in. On the positive side, the cost side, the cost story, we’ll continue to show decline - we continue to show declining LOE dropping to about $24 million for the quarter around $6.60 per Boe, almost a 50% decline versus per unit cost in the third quarter of 2014. The combination of primness operational leverage at Pompano, overall cost savings and higher volumes at low - in low cost Appalachian has allowed to this impressive cost reduction. The transportation processing and gathering experience dropped slightly from the second quarter; recognize that the third quarter TP&G expense did have a onetime TP&G charge of about $3 million for some previous Gulf of Mexico regulatory charges. Note that the Mary filed remains offline for the quarter would expect this cost to drop again in the first quarter - I am sorry - in the fourth quarter to probably somewhere under $10 million. On the DD&A, our DD&A rate for the quarter was around $2.75 or so. We would expect the DD&A rate to be around $3 per Mcfe for 2015, although future potential ceiling test impairment could impact this figure slightly. Our base G&A before incentive comp decrease $19.6 million for the quarter. However, this is included approximately $4 million in severance and other onetime charges. We would expect this figure to trend towards or under the $15 million per quarter rate. The reported interest for the quarter was just over $10 million, again flat versus the first two quarter. As I’ve mentioned before about $4 million of this - of the reported interest expect is noncash interest tied to the convertible notes accretion. Our total cash interest, capitalized interest is running about $16 million for quarter. Our reported taxes were negative due to the net loss for the quarter and we do not expect to pay any taxes for 2015. That’s important to note from accounting standpoint that we have no differed tax liability left on our balance sheet at September 30th. This would likely be the case in the fourth quarter as well and may limit the amount of accounting tax benefits that we recognize against future pretax losses. Again there is not cash impact but it would remove our 35% tax shield in your models and ultimately impact book equity. Our CapEx for the third quarter was approximately $125 million or about $330 million for the first nine months. The fourth quarter CapEx will include the completion and timing cost for our 100% owned Amethyst project. Also we are currently mobilizing the Pompano platform rig, which we have 100%, that will also impact the fourth quarter CapEx figure. Accordingly, we do have some upward pressure on our board authorized $450 million budget, our current projections show us running about 25 million or about 5% above that CapEx budget, so we’ll continue to review our CapEx reduction options. Looking ahead to the 2016 CapEx budget, we certainly expected to lower than our 2015 budget and more aligned with the expected cash flow or EBITDA for the year and we are looking to - we are working to present our 2016 budget to our board next month. At 9.30, we had about $75 million in cash and our $500 million borrowing base remains undrawn expect for 19 million NLC. Last month, we did receive conformation on our $500 million borrowing base until next spring. So we certainly have adequate near term liquidity and we’re fully compliant with all of our financial covenants under our credit facility. Our 300 million of convertible notes do not mature until 2017 and with coupon rate of 1.75% obviously very attractive piece of paper. We are reviewing our options for addressing the converts including use of our current bank facility, a possible restructuring with current holders, the second lean wind of notes selling minority working interest in our quarter assets, evaluating some joint venture arrangements in either Appalachia or the deepwater Gulf of Mexico and certainly monitoring external financing options. With nothing currently drawn on our $500 million bank facility, we certainly can be constructive on our next step regarding the convertible notes. I believe that wraps it up in the financial side, with that I’ll turn it back to Dave with his comments.

Okay. Thank you, Ken. Over the last 12 months, we’ve quickly adjusted to the new environment of lower commodity pricing. In doing so, we’re fortunate to be able to build on actions taken in 2014 before prices drop, the strength in our balance sheet and optimize our portfolio. Since prices have dropped, we’ve lowered cost structure and tightly focused our investments. While it has been and continues to be a difficult evolution, in less than year, Stone has positioned itself to continue to operate in the low price environment and to grow the company in the future. We’ve done this by focusing on the lowest cost for supply oil basin, the deepwater Gulf of Mexico and the lowest cost of gas supply basin Appalachia. As we’re positioned today, we feel we can grow in the deepwater Gulf of Mexico, well at the same time, maintaining a significant gas option in Appalachia. Accomplishing this task was not easy and required to consorted efforts of our entire organization. First, it was imperative that we adjust Stone’s cost and spending structure with the lower price. We accomplish this by reducing all three major categories of spend, lease operating expense LOE, salary general administrative expense SGA and capital investment. Next it was and continues to be important for Stone to maintain its favorable liquidity position. In the third quarter, our lease operating expense was $24 million of $6.60 per barrel equivalent. This is a significant reduction from the $44 million or $12 per barrel, oil equivalent realized in the third quarter of ‘14 which is itself significantly lower than the previous year’s quarter. Some of this cost reduction was realized with a sale of our higher unit cost conventional shelf assets in July of 2014. However, much of the savings are attributable to cost reductions efforts. We expect this cost reduction trend to continue in the 2016 with LOE projected to decline as much as another 20%. One of the unfortunate consequences of the cyclical nature of the energy industry is need to rebalance our overhead during times of low prices. During the third quarter, Stone executed a second reduction in force and is expected to decrease our already reduced SG&A by about 20% from 2015 and 2016. This action was needed to better align our employ base with our tidal focus and expected lower spending profile. In addition to the cost saving, Stone has worked to reduce capital spending of about $900 million in 2014 to approximately half that 2015. We anticipate reducing spending further in 2016 as we strive to spend close to cash flow. In order to reduce our spending in 2016, it will be vital that we manage the exposure inherent with our deepwater rig contract and concentrate our spending in the Gulf of Mexico with an emphasis some revenue generating development projects. The deepwater rig contract has been managed through a combination of exploratory drilling at a lower working farm outs and if need to exercising our option to stack the rig. The first and best option to manage the capital is to find partners and drill our exploration prospects. We have several quality prospects and are optimistic that we will obtain partners to reduce our working interest to a desired level. Even at lower working interest, our exploration prospects expose Stone to a significant potential to grow. The second option is to farm out the way the companies that have work to do but no rig. This essentially ships some of the contract exposure from Stone to another operator. Currently, we are working with several potential operators to farm out the rig for portions of 2016. We’ll continue to market slops throughout the term of the contract. The third option is to simply stack the rig. While stacking the rig is obviously the least desirable option but it does limit our exposure to around $75 million for the year. By pursuing all three of these option simultaneously, we should be able to manage the rig exposure by providing some opportunities to have production and/or reserves for the company. In addition to managing the rig, we have significantly reduced spending in Appalachia and focus most of our 2015 capital on development projects in the deepwater of Gulf of Mexico. With the ENSCO 8503 rig, we drove and completed the Cardona 6 well; we are currently completing the Amethyst discovery. And once finished, we will mobilize the rig to the Cardona 7 development. The Cardona 6 well was drilled and completed in the second quarter, well came online about a month or early and it’s currently flowing about 5,000 barrels of oil equivalents a day. Combined with the other two Cardona wells, as Ken said, the project is currently flowing about 15,000 barrels of oil per day. Soon holds a 65% of working interest in this project. The Amethyst discovery which is owned to 100% by Stone is being completed at present and it’s scheduled to come online by the first quarter of 2016. Production is expected to be in the 25 million to 75 million cubic feet gas per day range. Cardona 7 is expected to begin providing production sometime in the first quarter of 2016. It should produce at rate similar to the other three Cardona wells around 4,000 to 5,000 barrels of oil equivalent per day. These Cardona wells are economic in the current environment and we’ll have a significant impact on 2016 cash flow. We are also mobilizing a platform rig to the Pompano platform for our three or four well development drilling program there. All of these platform wells target proved on developed reserves in the Pompano field. Two of the wells will develop reserves at the top of structure in the large M83 reservoir which is already produced over 115 million barrels of oil equivalent. The program is expected to be yield high returns even in the slower price environment. Through management of the ENSCO rig contract and narrowing our spending to only our most profitable projects in the Gulf of Mexico, we planned to further lower our capital in 2016 to be close to cash flow. We also realize the importance of staying financially liquid during the stress times in the industry. In addition, to addition production with the above development program, we’ve been careful to manage our borrowing base and initiated plans to address the 2017 convertible notes. A borrowing base was reaffirmed to $500 million in October. The focus of development spending in the Gulf of Mexico has enabled Stone to maintain a stable production profile. Stable or even increasing production will continue with the completion of the Amethyst discovery, the drilling of the Cardona 7 well and the startup of the Pompano platform rig program. The production from these wells is essential to underpin our borrowing base. With the reduced capital investment program in 2016, we should minimize our need to draw in our credit facility. So while 2015 has come with many challenges, we feel we’ll be exiting the year with the right cost structure and capital plan for the current price environment. This is important, we have maintained a viable liquidity position with plans underway to address the 2017 converts and capital spending targeted close to cash flow in 2016. We should maintain adequate liquidity heading into 2017 and beyond. While it’s absolutely imperative that we make the adjustments needed to address low commodity prices is equally important to provide opportunities to Stone to grow in the future. So in continues to be exposed to significant upside to the Gulf of Mexico deepwater exploration program, in 2015 we participated in discovered and monetize the Crown and Anchor prospect and are currently participating in the drilling of the Vernaccia prospect. In 2016, we plan on drilling our Derbio and Lamprey prospects as well. Each of these current projects provides an opportunity for significant reserves growth. The Vernaccia project, which is current being drilling by Eni, targets a full way geologic closure in Northern Mississippi Canyon. These structures have historically enjoyed high probabilities of success in Mississippi Canyon. Stone holds have promoted 22% working interest in the project with only a 4% cost exposure in the exploration well. The results of Vernaccia could be known around the end of this year. We believe Lamprey to be a high probability of success prospect just south of Alaminos Canyon. You believe it’s an analog to the Great White field a few miles to the north. In addition, early evidence to guess that Pemex nearby try and explore to Maximino discoveries to the self-shows similar seismic responses that we see in Lamprey. These are all large discoveries and Pemex is also recently announced that they plan to drill their TRS exploratory prospect which is only about three miles south of Lamprey. TRS makes possibly start drilling as early as this month. Obviously this well will be a major data point for Lamprey. We believe that Lamprey’s successful could be a major producing hub. Internal estimates are at Lamprey’s ultimate recovery ranges from 104 to 547 million barrels of oil equivalents with an estimated mean of 372 million barrels of primary recovery. In addition, ultimate recovery could potentially be driven higher by executing a water flood has been done in the adjacent Great White field. We are actively seeking a partner for those 100% working interest prospect, Lamprey has an expected dry hole exposure of approximately $63 million. If Lamprey is a significant discovery, we will likely drill an appraisal well shortly thereafter to progress the development of sanction. Currently we plan to drill the Lamprey well or wells following our Derbio prospect in Mississippi Canyon. This is change in sequence from our previous plan which had Lamprey drilling before Derbio. However, we would hope to see some results from the nearby Pemex TRS well by the time we drill Lamprey and that’s the reason for the switch and order. Derbio is another amplitude supported trap that is a sister prospect to our Amethyst discovery. We also in Derbio had a 100% working interest and it has a reserves distribution of 18 million to 180 million barrels equivalent. Derbio is shallower and cooler than the Amethyst discovery; therefore it’s likely to contain an even higher level of liquids in the gas stream strain. It’s successful; this could be another short tieback to the Pompano platform. Additive to the prospects above, we have a significant lease hole position in the deepwater of the Gulf of Mexico with over 45 additional prospects. This exposure to ongoing deepwater exploration and development provides Stone with a growth engine that could still provide economic returns even in the low commodity price environment. In addition to the deepwater oil growth option, our Marcellus and Utica positioned in Appalachia appears to be in the core of the clay and it’s attractive valuable long term option on gas. As a result of low natural gas prices and higher differentials between Henry Hub and the M2 market, we’ve minimized activity in Appalachia in 2015 and 2016. However, we well positioned to quickly react when economics return to the basin and indications are that it should happen. We see the natural gas forward curve in Contango and the differentials in backwardation over the next few years, which leave to improve economics in the Appalachia basin. We have a rig there capable of both Marcellus and Utica wells, have a development plan, have permits and a position to ramp back up as economic conditions improve in Appalachia. In closing, we’ve maintained significant liquidity, focused and achieved the lower cost structure and redressing the 2017 converts. We are also executing development drilling projects to underpin our base production, maintaining our deepwater exploration upside potential and have a significant position in Appalachia as an option when economic conditions improve there. We are intent to create an exciting future for the company despite the headwinds our industry is currently facing. I firmly believe that we have the right board, executives, managers and employees to deliver during these times. I also feel that we’ve taken the correct steps to position Stone for both survival and future growth. With this, we’ll now be happy to take your questions.

[Operator Instructions] Your first question comes from the line of Kim Pacanovsky from Imperial Capital. Your line is open.

Yeah. Hi. good morning, everyone. I am just wondering if could give us a little bit more detail about the Lamprey process?

The prospect itself?

No. About your interest that you’ve seen in selling down in interest in Lamprey. The process not the prospect.

Sure. Sure. It’s a very dynamic situation Kim. You know the reason announcement with Pemex drilling to TR as well just south of the boarder I think is going to alter that process a bit, that’s why we’ve see Derbio in front of Lamprey, so we can have a little more time to see what kind of results it might get from their well.

Okay.

To some extent, they may be actually testing the southern end of our structure which would be very helpful.

Sure would be.

We also have seismic data that looks like it’s coming available south of the boarder which we haven’t had before. So our process is, we’ve talked to a number of companies, we are continuing to talk to them, but we are in a real state of flux now given new seismic data and potential new well data.

Okay and you said TRS is Pemex well?

Yes, it is, it’s a -

Yeah, and who - are there partners?

No, they own it and it’s about three-four miles just south of the boarder.

Okay. Great and could you just give us an idea of what you are thinking on adding gas hedges in 2016, you don’t - obviously the strip is pretty awful right here, but you don’t have a very hedge position for ‘16?

We don’t. I’ll just point out that we have added some oil hedges, we now have about around 30% of our 2016 oil hedge at an average price of around 60. On the gas side, I think we have about 20 million Btus hedges that a little over $4. We have a hedging committee that meets ones a month then we look at all the indications. And you know you are right, the strip look pretty dyer lately, so we haven’t placed any additional gas hedges yet, but we do monitored every month.

And Kim you might remember, most of our gas has been Appalachia, so we’ve got a couple of gas hedges there really would address our current volumes. That will change when Amethyst comes on, but again we’re in a 100% share at excite timing or the exact amount, so some of our hesitation on putting in gas hedges stems from the location of our volumes as well as uncertainty around Amethyst.

Yeah, it’s timing. Okay, great. And just a modeling question, could you just give us a breakup of the products for production in the four quarter guidance?

Yeah, maybe this is the way to think about it, this is kind backward engineering but it will kind of Mary out of the equation. The Heather and Buddy volumes are somewhere in that 20 million to 25 million a day. The Gulf of - Gulf Coast volumes are somewhere around the same 20 million to 25 million a day. So there spit the million out of the 150 would be gas. You know I don’t actually, nothing tips out of the oil NGL breakdown, but oil should be pretty static if not slightly up in the fourth quarter. NGL volumes particularly with the shutdown at Mary will be down.

Will be down, okay.

Down pretty dramatically.

Great. Okay, very helpful. Thanks so much.

Yeah.

Our next question comes from the line of Richard Tullis from Capital One Securities. Your line is open.

Hey, thanks. Good morning, everyone. David or Ken, I think you’ve had mentioned in the press release that you had this fit-for-purpose rig in Appalachia. If you stack that rig, what’s the cost there?

It’s about $6 million a year.

Okay, so it’s pretty minimal.

It’s pretty minimal and however we will be trying to form that well - I mean that rig out as well but I think for modeling and our internal models were assume that we’re going to stack it.

Okay, okay, okay. And I know it’s not a very wide range for the fourth quarter production, what do you expect to exit the year at?

Yeah, I mean in numbers just take that roughly 150 and add a 100 million you know kind of gives you your 250.

Okay.

And again, you’ll see a decline from that - from Appalachia but you will see an incline from certainly Amethyst and then number 7 and Pompano rig problem, I think at least our thought and we don’t have guidance for next year on the production side Richard, but certainly you can kind of do some math and it would show some pretty positive growth in 2016 for the overall company.

Okay.

All of that drive by the Gulf of Mexico, the high margin Gulf of Mexico production.

Okay, okay. What’s the oil percentage in that 15,000 a day Cardona production currently?

80%-85%.

Yeah, okay. And then David, you’d mentioned potentially 20% lower LOE next year, I imagine you meant on a barrel or Mcfe basis, but does that count on Appalachia being back online next year to achieve that sort of reduction?

Yeah, that would be our, you know it’s our full company is moving forward and we’ll put out some guidance on those numbers later, that’s just kind of a - to let you know that we’re not finished cost cutting yet that we still have some ways to go, I am getting more efficient.

Okay. I think that’s all I had right now; I’ll jump back in the queue. Thank you.

Thanks Richard.

Our next question is from the line of Ron Mills from Johnson Rice. Your line is open.

Good morning. Just as a follow-up to Richard’s question, the question on 2016, you know as it relates to CapEx, I think consciences to somewhere in the mid-200s in terms of cash flow. What would it take to get down to that level of CapEx, I am assuming you would be sell down Derbio and Lamprey but is there anything in there that would lay to go from kind of $475 million budget down to somewhere in mid-2s?

Yeah, Ron, the rig far now it is a key piece of getting down to a low level and we’re working on that every day and hope to have something done on it for the end of the year. Also you know one of the things we could do is join some lower working interest prospects and actually spin less money by drilling a project that we took say a 10% working interest that were somebody else’s project. And then the final thing if need be stacking the rig for part of the year if we’re not successful in getting the rig formed out or in getting lower working interest in different opportunities.

And Ron, this is just and this is at a very high level, but if you think about it, we’ll really narrow it our activity level dramatically next year. You’ve got the Pompano platform rig program which at a high level of spin somewhere in the 80ish million dollars. You’ve got the ENSCO rig program which would include Cardona 7 and hopefully have sell down at Derbio and Lamprey which allows to drill wells, but as Dave pointed out, worst case scenario will just stack it. But if you think about spending in the roughly 100 some odd million dollars for that program scenario just under $200 million will have some P&A which would put us over $200 plus million. Maybe $30 million-$40 million in the P&A side is going to be some seismic and some other thing that we’re going to have spent money on, but that’s even open Appalachia and minor spending up there. That could get you to the mid-200s. And then we really don’t have to do anything else and so that’s why at least our sense is our capital budget will somewhere around that cash flow number. You know we don’t have a set CapEx budget that has been blessed by the board but certainly we’d not expect this to be a $400 million $500 million out of budget next year.

And then I know you don’t have the guidance but because of the nature of Cardona, Amethyst and your three of four Pompano development wells, really it almost any level of CapEx it seems like you know you still be on track to deliver plus or minus double-digit growth just depending on when those development projects flow through. Is that at least in line with consensus just is that still achievable at Amethyst?

That feels about right but the big unknown there is what happens on two things, one being what the rate do we achieve at Amethyst. And the second is how long do the Cardona wells hold steady before they get any decline. As right now, all three of the wells are just holding steady.

Okay and then one last, I guess a big clarification, did you say, Ken what’s four quarter CapEx was going to be?

No, but we kind of gave you an idea of what the nine months where and you instead of the 450 if you kind of round it up, an extra 25 million it would certainly kind of give you over $100 million.

Okay and then on the notes, is there as you go through those options, are there any major - you know are there any dates to look for or is it just you continue to monitor the various options on on an ongoing basis and so in your mind you have plenty of time to address that maturity?

Yeah, I mean obviously sooner is better than later. The ultimate date that we are concentrating on is March of 2017 when we do have to pay it back. But certainly we want to address it - address kind of our either retirement, the fees you know how we are going to - how we will pay back the 300 million in advance of that. I will tell you that there is no trigger, no issue as it relates to those notes going current, so it’s not is if we have to do some before March 2016 because they go horn and it triggers something that not the case. But it certainly it’s you know strong desire of the board and management to have a blueprint out there for us and of course the public to see how we’re going to get from point A to point B before March 2017. I mean ultimately we do have 500 million our line that will be I think utilized for some portion. I think we’ve said this before, I would not expect to have a single bullet, address all $300 million I think it will be several steps or actions that we take, it will address the $300.

Great, thank you all the interest.

Thank you, Ron.

Your next question comes from the line Jonathan Evans from JWEST LLC. Your line is open.

So can you help us ask, have the right sizing in the quarter. Can you give us a sense of SG&A next year on a run rate, it’s a 100 this year but you took some more corrective action, so is it 90, is it 80 or what do you think about SG&A for ‘16?

If the range, that’s the right number, kind of right range.

And that, is that cash can without stock options or?

Yeah.

Okay, got it. And then the thing is -

Actually Jon let me, a portion of that will be actually the vesting of stock restricted stock that vests overtime. So a portion of that will actually be not care, so it will be expense but it will be stock it that does best. I can circle back with you to give you exact number but it’s going to be not small numbers, that going to be I think you know probably approaching $15 million-$15 million, I think it’s maybe close to 15.

Got it. So I mean just a way to think about that, is it let’s say you are at 90 and so 15 and that 90 is noncash, so the cash is a difference, is that what you are saying?

Again yes, let me circle with you just to clarify that after the call.

And then on the Amethyst, I mean like you stated you can drive a truck through kind of what you think that’s going to produce, when will you have a better information do you think on where, what kind of level it’s going to flow, when do you think that comes about?

Yeah, probably not till the first quarter till we actually get it online.

Okay.

I mean the real uncertainty is this is a little bit different looking rock from the Cardona type stuff and we just are going to have seen what it does when we put in online.

Okay, and then on the 25 million more that you are going to spend in CapEx, so most of your announcements that you made, you’ve talked about performance et cetera or the rig taken less time, so is this just the Amethyst tieback as cost in your more, what really derived the $25 million extra spend?

Again a combination of a number of factors Jon, we’ve approached it kind of as a probabilistic number, so we have lot of moving parts. You might remember we really started the year closer to 550 or above and have been working down to get to that 450, there are a lot of leverage down that out there to get us to the 450, one of them quite lonely was a Amethyst sell down which didn’t occur, has not occurred and at least at this point we expect wouldn’t occur, so that was part of the equation that you know one of the variables that didn’t occur. There are a lot of other little things on the cost side that that kept pushing us down towards the 450. But at the end of the day, we will have - I mean we’ll Amethyst at 100%, we’ll now have the Pompano rig program starting now in the fourth quarter in terms of the clock ticking is the rig you know was mobilized and delivered to us and that’s a 100%. So you know there were a number of small factors that that pushed us above the 450 in a great scheme of things an extra $25 million on a 450 budget with all the moving parts that we had, we feel at least pretty good about we still would like to it, would rather hit the 450, but there was no single item that we can point to, there were a number of items that put that pressure above the budget 450 number.

And I will say that we’re still working toward trying to push that 475 down as well. So it’s not a guarantee thing.

I am even including Jon, it just even had the ENSCO rig coming out of the yard a little early and you might not thing that’s a big deal but if it comes you know ten days earlier and you start remain always a day and we own a 100% with Amethyst that bring them all sudden, there is an extra $10-$12. That it’s hard to model but in real time to be roughly 5% around that number, with all was okay, we would rather always hit our numbers as opposed to be slightly above on an expense side or capital side. But we really felt that as we guide close to the year-end to at least provide the market with a recognition that we might be around that $25 million higher, so that people at year-end were actually you know we put out of our 10-K or Annual Report that the people are coincide that we just felt like that’s where we’re trending, that’s what our current model would suggest. But as Dave pointed out, there is still some things that were working on or working towards that might get us down but the time are somewhat staged against us.

Okay. And then can you tell us or I guess, we just have to wait for the cash flow statement known 959 what you sold that piece for?

I am sorry for -

Yeah.

Yeah, this was not a big number, I would say put in that. $10-$20 million type range is not a big, this is in $50 or $100 million but the real concept here is instead of staying as a small 10% working interest of a smallish project that was not going to tieback to our facility and would have actually called for CapEx going forward even though it’s at a 10% level or that was let’s go ahead and let the current players consolidate their working interest and we can move forward with other projects we have more control over.

Got it. And then just two last questions, relative to the ENSCO rig, when we have a decision on what you are going to do with that, is that just more determined on you know the pieces that yourself potentially with Lamprey or Derbio or I guess what’s the saw process there, can you give us any timing?

You know in the ideal world since this new TRS well is popped up, what we’d like to do is start the year by forming the rig out for a period of time didn’t coming up, picking up Derbio and then going either toward another form out at a Lamprey at that time. So that’s kind of our ideal sequence.

Okay. And then the last question, just roughly Ken, it seems like just back of the envelop you showed in with like some place between 15 and 20 million in cash, is that fair do you think?

Well again we’re going to have a stronger cash burn in the fourth quarter with a 100% Amethyst, 100% Pompano. You know you can look at I think we ended - we said three quarters CapEx about 330 to get up to over 450, 470 which show a higher burn. So we’re going to be pretty close plus or minus small amount of cash either plus or minus. But it’s - you know it’ll be small either way.

Okay, great. Hey thank you for the time, I appreciate it.

Thank you and I’ll circle back with you Jon.

Thanks.

Your next question comes from the line of Robert Alpaugh from Simmons & Company. Your line is open.

Yes, just one question from me. I was wondering what the price would be to get active back in the Appalachia again or if you are looking for a specific duration at a specific price?

Yeah, actually you know what we’re really trying to do is create a margin back a margin up there and it’s going to be dependent not just on a price of gas but the overall cash that the company brings in. So it’s really tied not just the gas prices but oil prices. So it’s a little tricky to evolve your question into a particular component. But I would say in general, you know if we can get $2 or so are better in the Appalachia basin for our gas that would be a real good start.

And as Dave pointed out, you know certainly in the third quarter and I alluded to in my comments is the NGL prices which had typically provided an uplift actually drag this down on both price and ultimately margin and in fact they were negative margin. So some of that equation really you know you have to look at NGL pricing which even seasonally you are starting to see a little bit a rebound for both gas prices at the M2 up in Appalachia as you look at the December and you are starting to see that differential get smaller, you are seeing Henry Hub move up slightly and you are starting to see NGL pricing get a little better. Ultimately there is a margin gain and has been highlighted the positive is this is a low cost area. So we once we get into that $2 plus area on gas prices it’s something that can be considered because the cost structure is pretty - it’s pretty advantage. But at least it was in our minds, it was important to make sure that we weren’t just producing gas to show volumes, we ultimately want to produce gas to make some money and that’s really the one of the thoughts have just holding off on our Mary production.

Alright, well thank you for the color. That’s all from me.

Thank you.

Our next question comes from the Gail Nicholson from KLR Group. Your line is open.

Good morning. When we think of the development wells at Pompano, who should we think of timing, would that be one a quarter or is it more back half loaded in ‘16?

One a quarter is not a bad way to think about it. And we actually in our latest investor presentation show a profile that ramp up in our production profile if you want to get a little more specific.

Okay, great. And then looking past, you know pomp on that development program, is Amberjack platform program potential in ‘17 or how do you guys look at other kind of development opportunities in the Gulf of Mexico, Cardona 7 and Pompano?

Very good question. Yes, we are looking at a potential Amberjack program right now. We have to do some structural analysis on the platform to make sure that it couldn’t handle a bigger rig because we need a large rig to reach some of the larger potential prospects around there. But we are expecting - looking at there right now.

And then just one last question in regards to you know bring that rig back action in Appalachia, you know you have the Marcellus as well as the Utica, when you think about the horizon optionality, at this point in time, do you feel like you might go after the Utica more or is it will more kind of diverse program or any thoughts to what horizon you would attack when reengaging activity in Appalachia?

Well you probably are aware, we are fortunate that we have stack base both in the same geography, we have the Marcellus and the Utica. It looks right now that the Utica is probably going to have a little bit more attractive economics than the liquid rich Marcellus, but that’s highly dependent on what happens to liquids pricing. And so you know overtime I would expect that ultimately expect that oil prices are going to recover somewhat which would have an impact on liquids prices in Appalachia. So we end up with a bit of a highbred program, but I would say it’s slightly bias toward the Utica.

Okay, great, thank you.

You bet, thanks Gail.

Our next question comes from the line of [indiscernible]. Your line is open.

Hi. Good morning. Few quick questions for me, so earlier in the Q&A there was some mentioned, the improving prices in Appalachia, so just to get a better understanding of guidance, is that meant to be kind of a base line and then if there is additional - I guess if you guys decided to put the sudden volumes in Appalachia back online given improving winter pricing, that will just upside to guidance?

Yeah, that’s the case. I mean just mathematically we thought instead of trying to guess the exact day we may or may not bringing Mary back on. The thought was let’s just put out guidance that excludes Mary for the time being. If in the month of December we come back online, we kind of said that should at a 100 plus million a day and should have 30 million-35 million for the quarter. But when let you do your own math, but out thought was for guidance purposes let’s just take it all out, be conservative, you know certainly, you know everybody would certainly hope that we come back on production. And as you just pointed out from a seasonal standpoint, you do see the margins getting better particularly as you get into the December differential which is kind of down there probably about $0.70 or so versus over a $1 for the earlier parts of year well rid out for the earlier parts of the year. So the trends going in the right direction, but for guidance, we just ended up not trying to pick the exact day but just let people add back the volumes depending upon when we actually come back on.

Okay, great, that’s helpful. And then on the offshore rig, there also mentioned of evaluating formal opportunities, so can you provide some more color on you know just how those conversations are going and you know as possible what kind of day rate are you guys taking about in these conversations?

Yeah, what I can tell is that we’re talking to about eight companies or so that have projects that might interested in it. I would say maybe two to four of those have some serious potential interest. The terms are very sensitive because those discussions are going on right now. So I can’t really give you any help on that right now, but as soon as we have something done, we will try to get that out into public domain.

Okay, great, thank you.

You bet.

[Operator Instructions] Our next question comes from the line of Jeff Robertson from Barclays. Your line is open.

Thank you. Dave, can you talk a little bit about the development timeline, if you earned your main resource potential at Derbio and also at Lamprey? And at Lamprey, what is the likelihood of selling down, will also depend on the results of the - in terms of the timing of the Pemex, well as you are talking about?

Well, let me the first things first on Derbio, okay. Derbio is likely to be a tieback to Pompano, therefore it could potentially come online within couple of years after discovery and we’re able to do Cardona a little quicker than that, we may be able to do Derbio just slightly faster than two years. I hope that would the case. And then on Lamprey, yes the new news about this Pemex well TRS 1 is a big deal. And so we would certain like to see what they find on their well before we drill Lamprey and it could also have marketing implications because of they make a discovery you know I would think the price of Lamprey would go up. So we’re reevaluating that right now, walking the fine line between wanting to make sure that we have the right working interest to drill the well. And number two, trying to get the best commercial terms that we can for. So it’s a very good question and it’s highly on our minds and on our discussion list over the next few months. Does that answer yours?

Yes, thanks.

Okay.

At Vernaccia, if you get the results by year-end, you have room in your capital plan for ‘16 for appraisal work or would you have to more something else, excuse me if that was needed?

If we make a discovery there which were very helpful that we will figure out something to do on it you know even if we have to find dollars that you know if we have to spend down a small working interest there or something to lay for itself. But we’ve seen these Gulf of Mexico discovery itself for around $9 or $10 a barrel in the ground just after discovery. So you do create some currency when you make a discovery in the Gulf. And Vernaccia is very well situated, it’s close the infrastructure and I has a potential to be big too. So we’re keenly watching that one Jeff.

Okay, thank you very much.

You bet.

As we have no further questions from the queue at this time, I will turn the call back over for any closing remarks.

Okay, thank you, Karol. I just like to thank everyone for their interest and stay tuned to hope we have great things to talk about in the future.

Thanks.

This concludes today’s conference. You may now disconnect.