Talos Energy Inc.
Q3 2013 Earnings Call Transcript

Published: 5 Nov 2013

[Operator:]

Good morning and my name is Stephanie and I will be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy Third Quarter Earnings Conference 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 would now like to turn the call over to Chairman and CEO, David Welch; you may begin your conference.

[David Welch:]

Thank you very much, Stephanie. And welcome everyone to our third quarter call; joining us this morning is Ken Beer, who is our Executive Vice President, Chief Financial Officer. Ken is going to discuss the quarterly financial results and then I’ll give you an update on the progress of our strategic plan. So with this, we’ll follow this with your questions. And now, I will turn over to Ken.

[Ken Beer:]

Thank you, Dave. And let me start with the forward-looking statements. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration for and the development, production and sales of oil and natural gas. We urge you to read our 2012 annual report on Form 10-K and our most recent 10-Q, which have a discussion of the risks that could cause our actual results to differ materially from those that any forward-looking statements we may make today. In addition, in this call, we may refer to financial measures that may be deemed non-GAAP financial measures, as defined under the Exchange Act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between the financial measures and the most directly comparable GAAP financial measures. And with that rather than go through the third quarter results in detail, we will assume that people have seen the release and the attached financials, and we will just focus on some selective financial items. Our discretionary cash flow for the quarter was $166 million or around $3.30 per share, which was above the analyst first call cash flow estimates of just over $3 per share, and the earnings for the quarter was $36 million or about $0.72 per share. Production for the quarter came in at just under 50,000 Boe per day or just under 300 million cubic feet equivalents per day, which was above the upper end of the recently updated guidance for production. Once again, our Marcellus volumes were strong contributor as we experienced minimal pipeline downtime during the quarter, and in the Gulf of Mexico, we also saw up count or up time rate at a very high level with minimal pipeline or facilities downtime. And finally and thankfully in the third quarter, we had no Hurricane downtime. So everything was clicking during the quarter; however, in October we did have Hurricane downtime from Tropical Storm Karen. We also experienced some unplanned downtime at Ship Shoal 113 for a few weeks and we’re restricted in Appalachia for a portion of October due to a pipeline outage there. We also closed on the divestiture of our Weeks island field on October 1st which reduced volumes by about 1200 Boe per day. Unfortunately, our volumes in November have rebounded particularly in Appalachia where we did hit the 100 million cubic feet of equivalents per day mark after bringing online another pad (Ph) in our Mary Field. However, due to the slow start in October the Weeks Island assets sale and projective weather related volume curtailments in Appalachia during November and December as the cold weather causes the liquids to drop out of the gas line, we expect our fourth quarter volumes to be in the 42,500 to 45,500 Boe per day or 255 million to 273 million cubic feet equivalents per day in that range. And yet because of the strong third quarter we’re still able to slightly raise our full year guidance to the 44,500 to 45,500 Boe or 267 million to 273 million cubic feet a day again for the year. The production split for the quarter was approximately 40% oil, 9% NGLs and 51% natural gas as much of the volume growth was in Appalachia. And once again, our quarterly oil price realizations remained above $100 per barrel; however, the narrowing of the Louisiana Sweet premium continued during the quarter and is now around $5 per barrel premium versus WTI although still very attractive price. Our NGL pricing averaged just under $39 per barrel, a bit higher than expected due to some positive adjustments from last quarter sub $30 per barrel price. We would expect NGL pricing to remain in the mid 30s per barrel range for the remainder of the year. Overall, gas prices weakened during the quarter especially in Appalachia, dropping to under $3.50 per Mcf. For our gas hedge position helped keep our realize price at about $3.80 per Mcf. On the cost side our LOE was around $54 million for the quarter with our unit LOE per Mcfe dipping under $2 per Mcfe or under $12 Boe which is very good, very strong. Operations guys are clearly doing a good job of keeping LOE cost down and we have lowered LOE guidance for the year. The transportation processing and gathering expense jumped at $13 million for a couple of reasons. Obviously there is a direct correlation to the increase in gas and NGL volumes especially in Appalachia where there are incremental gas and NGL processing fees. Additionally in the third quarter we experienced some unusual lending charges to our high BTU gas stream in Appalachia to bring the gas down to our pipeline quality specifications. Although this will continue into the fourth quarter, we expect this fleet (Ph) to disappear pretty soon. However, with the higher volumes and the extra processing and lending charges we have increased our guidance for this expense. Our DD&A rate for the quarter averaged just under $3.40 per Mcfe which is towards the lower end of guidance and we’ve slightly reduced the DD&A guidance for the year. Accretion expense remains steady at just under $8.5 million per quarter. For G&A, our base G&A before incentive comp was in line at just over $14 million for the quarter although the incentive compensation expense did see an increase for the quarter. Reported interest expense was around $8 million for the quarter, which was down slightly from last quarter as our unevaluated properties increased, which does impact the reported interest versus the capitalized interest. There are still about $4 million of non-cash interest in those numbers primarily tied to the convertible notes accretion. The total cash interest is running at just over $15 million per quarter. Regarding taxes, we’re still projecting around a 36% reported tax rate with virtually all of it being deferred and we received the tax refund from our tax carry back during the year. Our CapEx for the quarter came in at around $162million, and for the nine months we are about $488 million. However, with the two Deep Water rigs currently running at San Marcos and Amethyst and our Tomcat deep gas prospect also drilling, we expect a significant jump in CapEx in the fourth quarter. Our debt position remains stable at the $975 million mark assuming the $300 million face value for the convertible notes or about $924 million if we use the recorded discounted $249 million figure for the convertible notes. Our $400 million borrowing based on our bank facility remains undrawn and we exited the quarter with over $240 million in cash. During the quarter, we did add a couple or more hedges to further protect our cash flow and CapEx program, and we have included the updated hedge position in the press release. Bottom line is we had a strong quarter and well positioned as we enter into this active deep water program. That should wrap up the financial overview and with that I’ll turn it back over to Dave for your comments.

[David Welch:]

Okay, thank you very much, Ken. All of our businesses performed very well this quarter and we continue to deliver important strategic milestones for the future. We delivered our production at near record levels approaching 50,000 barrels of equivalent per day, slightly above the upper end of our third quarter guidance. This is due to good weather and great work by our asset teams. We also expect to perform comfortably inside of our recently increased full year guidance even though as Ken mentioned, we expect the fourth quarter to decline a bit due to some onshore property sales as well as downtime in October comprising a storm evacuation in the gulf and temporary third party issues in both the gulf and Appalachia. Also our reserves were stable and we are expecting to grow them again for the year. At the end of last year our proved reserves were almost balanced with approximately 49% liquids and 51% natural gas. We do not expect any major deviation from this balance in our reserves report at the end of this year. In the third quarter we generated significant discretionary cash flow of a $166 million which funded our $162 million of capital expenditures in the third quarter. The balance sheet remains strong as we ended the quarter with over $240 million in cash and a bank revolver which remains undrawn at $400 million. Our first long-term debt obligation is not due until ’17. Our strategy remains the same as the last seven years; pursue investment and price advantage natural gas and material oil prospects. We continue to exploit our legacy conventional shelf assets as we develop our three growth areas Appalachia, Deep Water Gulf and the Deep Gulf Coast gas. In addition we are in the midst of a market test to potentially divest certain non-core conventional assets in the Gulf Coast including the sale of on onshore property in October. The positioning and continued performance sets us up well for the execution of our five year plan. The five year plan includes an aggressive well work program with limited drilling investment in the conventional shelf and the sale of certain non-core assets, exploration in liquids rich Deep Gulf Coast, continuation of our one top hole, one horizontal rig program in Appalachia and now our accelerating investment in the Deep Water Gulf. In our legacy business we’ve completed six successful wells this year out of seven drills with the aim of maintaining a relatively stable liquids production rig, but not trying to grow reserves there in the limited size of remaining opportunities. In Appalachia, we see another eight or nine years of Marcellus development drilling ahead of our at our Mary area with that one vertical rig, one horizontal rig and one frac crew program in this liquids rich area. We now have an operations organizations functioning there like a machine with the efficient, simultaneous execution of permitting pad construction, top-hole drilling, horizontal drilling, frac operations and hook up and production. Our teams are executing with precision and our steady program is yielding both effectiveness and efficiency. We expect to drill about 30 new wells this year with longer leads and higher recoveries as our team continues to deliver improving results. This is the equivalent of what a two horizontal rig program would have achieved for us just two or three years ago. Production from our wells appears to be holding up very well and our predicated EURs are expected to continue to raise as gain more production history. Appalachia production average 82 million cubic feet a day in the third quarter and we recently hit a milestone of over a 100 million cubic feet a day which includes over 4,500 barrels of liquids. In the fourth quarter we’re forecasting our reduced average Marcellus production rate due to potential third party pipeline freezing in November and December. This freezing issue is being addressed by the pipeline company, but the full fix will not likely be in place this winter. We do expect the benefit from higher liquids pricing within the next year as a result of re-piping and addition of new process and equipment in the Fort Beeler plant and new fractionation facilities being brought online at the Martinsville fractionation plant. These pricing uplifts will take place in several stages and by the end of the second quarter of next year we expect that we’ll have the net effect of improving the equivalent well ahead natural gas price from around $6 to almost $7, off of a $4 base gas price. We also expect that the third party pipeline company will commence the addition of a 24 inch line parallel to the current 12 inch pipeline sometime next year giving us room to continue to ramp up our production in the future. As our rigs continue to increase and as liquids prices rise we expect that Appalachia could become cash flow generator for the company within the next couple of years. Self funding and cash generation are important milestones for any resource player and we look forward to achieving it in our Marcellus development. We’ve also drilled and fractured a short horizontal well to test the Upper Devonian shale, which lies just above the Marcellus at our Mary field. The Upper Devonian is about half of thickness of the Marcellus and our test wells at 2,450 foot lateral which stayed in the zone. We frac the well and floated back gas [indiscernible] in water. The well is not yet cleaned up so we’ll need to place it on production with the other wells on its pad for a while to get a representative test. Initial sustain flow from the pad is expected late in the fourth quarter this year and we will learn some things from that. However we’ll still want few months of production history in the next year before drawing any major conclusions about commercial development. The late breaking news at our Mary area is the potential for the Eureka to be an economic growth engine as well. The Eureka is about 4,400 feet deeper than the Marcellus but it’s also 115 feet thick compared to the Marcellus which has an average pay thickness of around 55 feet at Mary. The Eureka is likely dry gas below its Marcellus but since much of the infrastructure has already been build for our Marcellus development, the economics could be viable even at lower gas prices if we can get sufficient production rates. To this end we’re considering drilling a Eureka test well on our acreage in 2014. Several offset operators have already reported strong production results from the Eureka in the general vicinity of our acreage. We have over 40,000 net Marcellus acreage in our Mary field and on the Eureka rights on much of this. So if it works, it could be a significant addition for our company. In the liquids rich deep Gulf Coast area, we continue to produce our two discoveries at South Erath and La Cantera which were flowing daily net rates of approximately 22 million cubic feet of gas, 400 barrels of condensate and 530 barrels of NGLs. We’ve planned to drill or participate in the drilling of two to four exploratory wells over the next three years and our liquids rich gas business along the cost, and have recently spudded the Tomcat well just offshore in West Cameron 176. The results should be known in the first quarter of 2014. We believe this prospect to be potentially similar in size to the La Cantera and we own Tomcat a 100% where as we have 35% working interest in La Cantera. If successful we would expect to have Tomcat on production in just a matter of months. All of our deep gas exploration prospects are expected to offer high rate wells and material liquids content if successful. We have several additional attractive prospects being developed in our inventory including La Montana and Pumpkin Ridge and are keen to drill them in 2014 or 2015. At the Pumpkin Ridge prospect, we have just acquired a 100% working interest and approximately 14,700 acres which cover a sizeable geologic structure. This is a semi Ultra Deep prospect similar to our reported discovery drilled about 10 miles away and operated by a major. The objectives are younger and shallower and thus less expensive to test and if successful to complete, then the Wilcox objectives comprise in the Ultra Deep play. We still have a lot of work to do but this could turn out to be another exciting opportunity for Stone in the future. In deep water, our activity has increased in both development and exploration drilling. We believe this will result in significant increases and production within in the next couple of years. Starting with the Northern Mississippi Canyon Corridor we're anchored by our 200% owned production hubs at Amberjack and Pompano. Combine these two important pieces of infrastructure contain about 75,000 barrels per day of unused production capacity with room for further expansion is needed. We have three wells near our Pompano platform authorized for drilling; these are the Cardona development well which we sometimes call Cardona North, the Cardona South development well and the Amethyst exploration well. These are our first company operated deepwater drilling wells in subsea tiebacks. All the critical permits, rigs, vessels et cetera have been secured for the drilling of these wells. And Amethyst is the first well we will drill using the Diamond Ocean Victory moored (Ph) rig. The two Cardona development wells are scheduled for the ENSCO 8502, dynamically position semi-submersible drilling rig. The Ocean Victory is just now moving on to location and the Amethyst exploration well should spud within a week. The first Cardona development well should spud in January or February. We were able to move Amethyst out of the peak hurricane window and also to move the Cardona development drilling about three months closer to the date of expected first production. These adjustments were both reduced cost and risk and should enhance the rate of return on the projects. Amethyst is located about five miles from the Pompano platform, which could be a subsea tieback toast if the well is successful. The prospect has a P90 to P10 range of 6 million to 60 million barrels equivalent and we should know the outcome in the first quarter of 2014. Progress on the Cardona tieback project so far is good. We have ordered the long lead critical path items including trees, well heads, subsea bowels, construction of the nine-mile long umbilical hydraulic and control line and the dual six inch blow lines and jumpers. Since the last call, we have evaluated bids and negotiated and then executed a flow line epic contract for Subsea 7, who is a very experienced provider of subsea flow line engineering procurement installations and commissioning. The epic contract applies to the engineering construction of the flow lines integration and installation of all subsea equipment and the commissioning work required for the start up of production. We have only one major contract yet to award and that's for the installation of the umbilical. This contract is not on the critical path but we have tendered for bids and expect to have the contract signed by the end of the year or in the first quarter. If these development wells are successes, we're still on track to deliver Cardona production by the first quarter 2015. And just to mention this first quarter start-up date for Cardona is at midpoint of the schedule. We could start-up potentially one quarter forward or backward depending upon whether equipment deliveries and other factors. We’re also in action making the necessary modifications to the Pompano platform to accept both new additional tieback wells and platform rig thereafter. This work and the overall project are still on schedule. We have also secured platform rigs for both Pompano and Amberjack and plan to drill four to six development wells for each of those platforms beginning in late 2014. The platform drilling at Amberjack should start in the third quarter or fourth quarter of 2014 and Pompano is expected in mid 2015 following the Cardona platform related tieback work. So with success we should see our deepwater production rising due to the Cardona development and even increasing beyond that as a result of subsequent platform drilling that will extend in the 2015 and 2016. We feel like we’re poised for material production growth in our company operated Mississippi Canyon Corridor from lower risk development drilling. We presently estimate our deepwater production rates could more than double over our five-year plan from 10,000 barrels a day to between 20,000 and 30,000 barrels a day equivalents. In addition this company operated drilling on the non-operated side we're presently drilling the San Marcos exploration well. Our 25% interest at San Marcos's exploration at Mississippi Canyon 983 is now at a depth just over 17,000 feet and moved to a proposed total depth of just over 29,000 feet. The well is testing a P90 to P10 reserves distribution ranging from 10 million to over 100 million barrels of oil. San Marcos is a Miocene age geologic structure separated from Shell recently announced on Vito Discovery, which reported 600 feet of net oil pay. We may have the results from San Marcos before year end but probably in early 2014. Early next year, we're expecting the Mica Deep prospect at Mississippi Canyon 211 to be drilled by Exxon Mobil. This well will also be testing Miocene age sands not too distant from the Marmalard and Marmalard North discoveries. Stone and Exxon each hold a 50% working interest in the prospect with Stone having a 35% cost interest in the exploratory well. This well is expected to take about two to three months to drill. Our P90 to P10 range is 10 million to 100 million barrels gross. Late next year, we also expect to commence drilling the first of our prospects in the previously announced Conoco joint venture. This would likely be the 21 prospect at Mississippi Canyon 118, 21 as a gross P10 reserve potential estimated to be approximately 250 million barrels. It's also possible that the Guadalupe prospect in which we hold a 40% working interest could be drilled in 2014 along with either our both Goodfellow and Phinisi in which we hold 13.5% and 20% working interest respectively. Guadalupe has a gross P10 of over 125 million barrels Phinisi’s P10 as over 250 million barrels equivalent and Goodfellow’s P10 is about 800 million barrels of oil equivalents. So these are all high potential exploration prospects which could materially impact Stone as successful. As you can see deep water has become a very active area for us and we’re expecting significant growth in both oil production and oil reserves over the course of our five-year plan. To sum it all up, we’re executing successfully on all fronts of our strategic plan; we’re managing the shelf decline and testing the market to potentially sell non-core assets there; we’re achieving continued low risk growth in Appalachia, producing and exploring the deep liquids rich gas Gulf Coast; and producing, developing and exploring in the deepwater Gulf of Mexico. The balance sheet is in good shape and we have a funding plan develop to execute on exploration successes that may become future development prospects. With this we’ll now be happy to take your questions.

[Operator:]

(Operator Instructions). And your first question comes from the line of Michael Glick of Johnson Rice. Your line is now open.

[Michael Glick:]

Good morning. Just a question on Amethyst, I know you guys have been marketing a portion of your interest in the well, I’m just curious if you could provide kind of an update on that front?

[David Welch:]

Well, sure. Sometimes you just have to put a stake in the ground and that’s what we’ve done here with the rig commitment and the rig moving to location. Michael, it’s not our general strategy to drill exploration well at a 100% and we are still talking to some people and if we get an acceptable deal we would certainly lay off a portion of that well. Ken, anything you want to add?

[Ken Beer:]

I’d say we’re moving forward I mean just gotten the rig and we’re moving forward and we will continue to talk with folks but we’re drilling away and we’ll see the results hopefully early in the first quarter.

[Michael Glick:]

Okay, and then because of your ownership of the Pompano platform, where on that reserve distribution do you think you need to be to justify development at Amethyst?

[David Welch:]

It’s pretty low I think anywhere on the distribution would be a development Michael given the fact that it’s only 5 miles from Pompano and that we own the platform a 100%. So we wouldn’t have any PHA fees or anything it’d just be incremental operated which would be very low. And even if the low end of the profile there you’re still talking about $16 a barrel for finding cost. So it would be highly economic anywhere on that distribution.

[Michael Glick:]

Okay, and then if you get success do you think you move on to Derbio next year?

[David Welch:]

We will certainly be working hard to get Derbio on the schedule if Amethyst works. The chance of success of Derbio go significantly higher if Amethyst prove successful and I can just tell you that Amethyst is one of the prospects in our portfolio that’s a higher than normal [indiscernible] higher chance of probability of commercial success.

[Michael Glick:]

Could you maybe provide a little bit more color on why that is like why you view it as a lower risk prospect?

[David Welch:]

Yes, it’s a little bit lower risk because of two things; one, we have a down dip well called Super Tramp (Ph) that was drilled by BP in the 90s, that well had some shales in it and we have a newer vantage of seismic that has an ABO response and amplitude versus offset response that indicates that we can get up depth and see better sand quality by moving to the northeast. So that’s why it’s a little bit higher the fact that we had oil shales down dip and we have seismic amplitude response in addition to that. Those two things make it a little bit lower risk than typical exploration well. The other thing I can tell you just as a point of reference is this is the well BP was planning to move to drill after the Macondo well was a discovery. And unfortunately we all know that rig sank and they never drilled that well.

[Operator:]

Your next question comes from Jeb Bachmann of Howard Weil. Your line is now open.

[Jeb Bachmann:]

Just had a few questions first on the Marcellus, you talked about that you are looking to improve there as you continue to establish a history with your well production. Just wondering if you can give us an idea I think you’re at 5.1 ex-ethane earlier this year if you can give us an idea kind of what you think that could go to at the end of this year?

[David Welch:]

All I can say for sure and I don’t know where it’ll go to at the end of this year specifically longer term other operators that are in the area are in the neighborhood of 6 Bcf a well and that includes a couple of other offset operators that are not too far remove from where our area is located, so if that’s any help to you that’s all the facts I really know, we won’t know as you know I am sure we do not do our own reserves those are completely engineered at Netherland and Seoul and so until they get enough production history to be confident that there is going to be a higher ultimate recovery our EURs may or may not change that much in the short term. But long term that’s what other operators are seeing and I don’t see any reason why our acreage should be a lot different from what others are experiencing.

[Jeb Bachmann:]

And David on those lines in the cost per well you’re saying you’re starting to see those come down or see efficiencies up there, any comments on what those are looking like these days.

[David Welch:]

Sure I'll think we drill, a typical lateral is in the 5600 foot range and typical wells in the $6.3 million or $6.5 million, to drill and complete fracture.

[Jeb Bachmann:]

Sorry, and then looking at the Devonian well and knowing it's one a five well pad, with four other Marcellus wells, can you tell us the location of that Devonian pass? Is that between these Marcellus rolls to try and figure out this communication or there will be communication between the wells.

[David Welch:]

Well, it's still very early days and it is in between some of those wells and as you know it’s a short lateral compared to the longer Marcellus laterals, what we’re really just trying to do is determine several things; one is that gas that's going to be condensate rich; two is it interfering or not being interfered with by the Marcellus production; and three there are several operators have started to talk about the fracking in the Devonian because it’s pretty close in terms of vertical separation to the Marcellus, several operators have started to talk about it actually stimulating the production that they're getting from the Marcellus. So we don't really know anything yet until we get it online with these pads and with the full pad, but I do expect that we’ll get that started later this quarter and watch it for few months and be able to start drawing some conclusions, you know there are two ways to win, one is that it's separate from the Marcellus, the second way is that it actually stimulates Marcellus production which I've heard that out in the industry as a possibility as well.

[Jeb Bachmann:]

Okay, great then moving down to the Gulf looking off shore just curious on the wells that are planned for 2014, do you have all the permits in hand necessary for those wells at this point.

[David Welch:]

We have the essential permits that are needed for the company operator ones we certainly do, there's a exploration permit which is the big permit, we have that for all of them and then you have an actual permit to drill which you typically get when your rig is ready to go to location within 30 days and that's I won't say that's a rubber stamp but if you crossed all the Ts and dotted all the Is in what you're doing those are generally forthcoming very quickly so we don’t have any permitting concerns Jeb.

[Jeb Bachmann:]

And looking at Mica Deep, I understand that that was a well that came up quicker than expected with Exxon, just wondering if there are additional opportunities around Mica that BP had identified prior to the sale to you guys that could also be fast tracked with Exxon.

[David Welch:]

There is at least one more structure on our blocks that we’ve identified and have pointed out to Exxon, and Exxon liked the Mica Deep prospect obviously for them to go from not even knowing about the prospect to drilling it within a year is a pretty good indication of their enthusiasm for the project and since we've all gotten enthusiastic about it there's actually even been a discovery made at the south that improves the project chances even more so. So we're really excited about Mica Deep and we’re very excited that we actually have a lever on that one where Exxon's going to pay 65% for 50% interest. So they like the prospect and we like it and there are a few other things in the area that could be add-ons to Mica Deep, if it should work.

[Jeb Bachmann:]

And two quick ones if I may, one Thunder Bayou, any update on the ownership percentage there, I think PQ this morning had said that that had been worked out in terms of who's going to be participating, I'm just curious if you guys had a final thought.

[David Welch:]

All I can tell you is that we're not participating in it; we determined that it didn’t compete for capital in our portfolio successfully so we're not participating in that one.

[Jeb Bachmann:]

Okay and then last one from me Pumpkin Ridge, would that be near Lyneham (Ph) Creek.

[David Welch:]

About 10 miles away.

[Jeb Bachmann:]

Okay and so the shallower objectives will be similar targets to what they supposedly found in the shallow sections of that well.

[David Welch:]

Exactly.

[Operator:]

(Operator Instructions). Your next question comes from Kurt Friedman (Ph) of Simmons and Company; your line is now open.

[Unidentified Analyst:]

Thinking of the capital allocation first I know you all took a couple diversions from the conventional goals and then in this release you've announced $4 million to $6 million, [indiscernible] I am kind of curious how you think about reallocating that capital, should we expect to see you guys hold on to that capital until you [indiscernible] or could we potentially see you reinvest that capital onshore somewhere.

[Ken Beer:]

Effectively we still kind of have a CapEx budget that we're working under, again I do not think you'll see us taking those dollars and going outside of that number, so the capital breakdown which has clearly shifted more and more towards the deep water, I think in the fourth quarter particularly you will see that and as you look out to 2014, I think we’ve been pretty open and pretty public suggesting that the deep water will continue to garner the line share of any capital expenditure growth.

[Unidentified Analyst:]

Okay great and then kind of shifting gears here. Do you have an estimate for current production is?

[Ken Beer:]

I guess we can at least suggest that production in November is trending back up to a level where we think that the fourth quarter guidance that we provided which is the 42,500 to 45,500 barrels equivalent. We feel like we’ll be able to hit that guidance and really with October behind us we would expect to show good production gains in November and December. The only caveat that they’ve alluded to is that you do have the potential for some reduced volumes up in Appalachia that we have baked into our numbers and that’s really just due to the physics behind the pipes getting colder, having the liquids dropout of the gas stream and therefore you have just less volume that can run through these pipelines. So we will put that in our guidance number if we are able to get through November and December with minimal restrictions and that certainly puts us at or above upper end of that guidance range.

[Unidentified Analyst:]

Okay great that’s helpful and kind of thinking longer term story here. I am curious to hear your perspective on how and I know it’s pretty far out there, but how discretionary cash flow could potentially change year-over-year 15 over 14 as is to relatively low risk Cardona development wells get tied in, I mean, could we perhaps see a pretty dramatic increase year-over-year counter years out from now, if those wells are tied in as planned?

[David Welch:]

Yes, let me say a couple of words and I will turn it over to Ken. We are selling out some properties; we’re potentially selling out some properties from the shelf this year. If so and if Cardona works as we think it will then our production will bounce back and grow above where we were this year in 2015. So that should have a positive impact on cash flow and Ken you may have some specifics you could add?

[Ken Beer:]

Yes, again one of the things that we are looking at are with the two Cardona wells as well as ultimately the platform drilling that we’ll do off of Amberjack and Pompano kind of gives us a real portfolio, more conservative portfolio in the deep water. One of the positive things here as you starting to see production that will generate cash flow in ’15 and ’16. Having said that we’ll also continue to have a pretty robust capital program, so we will have to look at ’15 and ’16 when we get there. But certainly in ’14 what we look to have a capital program relative to our production and cash flow which will be a bit higher, we have been very public about that with the thought that as we get into ’15 and ’16 and ’17 and allow the volumes that we would see from the Cardona wells as well as hopefully Amethyst in ’16 and they have two platform raised at Amberjack and Pompano impacting that ’15 and ’16 time period as well. So a lot of that is going to be very dependent upon both the timing and success of some of the wells that we’re looking to drill from the platform as well as Amethyst and certainly Cardona.

[Unidentified Analyst:]

Okay grate that’s helpful. Thanks guys.

[Operator:]

And there are no further questions at this time. I will turn it back over to the presenter.

[David Welch:]

Okay, thank you very, Stephanie and thanks everyone for joining us on the call and we look forward to talking to you next time, so long.

[Kenneth Beer:]

Thank you.

[Operator:]

This does conclude today’s conference call. You may now disconnect.