Talos Energy Inc.
Q4 2014 Earnings Call Transcript

Published: 25 Feb 2015

[Operator:]

Good morning. My name is Alissa and I will be your conference operator today. At this time, I would like to welcome everyone to the fourth quarter 2014 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. If you would like to ask a question during this time, please press star then the number one on your telephone keypad. If you would like to withdraw your question, please press the pound key. Thank you. David Welch, you may begin your conference.

[David Welch:]

Thank you, Alissa, and welcome everyone to our year-end 2014 earnings conference call. We’re joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read the cautionary statement and review our financial performance for the year, then I’ll make a few comments on our response to the low commodity price environment, the year, and the status of our operations. Ken?

[Kenneth Beer:]

Thank you, Dave. Let me start with the forward-looking statement. In this conference call, we will 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 the risks and uncertainties normally incident to exploration, development, production and sales of oil and gas. We urge you to read our 2014 annual report on Form 10-K, to be filed tomorrow, 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 and posted on our website for a reconciliation. With that, let me move forward. We’ll assume that everyone has seen the press release and the attached financials. Additionally, we will assume that you’ve also reviewed our January 20 press release which provided our 2014 reserve information as well as some details on our $450 million capital budget approved by the Board. Our fourth quarter adjusted earnings came in at $4.1 million, about $0.07 per share. After accounting for a non-cash impairment charge of $351 million pre-tax, the reported loss for the fourth quarter was $190.5 million and for the year the reported loss after the impairment charge was $189.5 million. Our discretionary cash flow for the quarter was just over $90 million or around $1.60 per share. For the year, our discretionary cash flow was approximately $438 million and production for the year was just at the upper end of our annual guidance at 42,700 Boe per day, or 257 million cubic feet a day equivalent. The ceiling test impairment was due to several factors, including lower oil and gas prices, widening negative gas differentials in Appalachia, reduced oil price premiums in the Gulf of Mexico, and higher projected transportation processing and gathering expenses. If the prices and differentials continue to stay at these depressed levels, we would expect to be subject to another non-cash ceiling test impairment in the first quarter. No impact on cash flow, but a potential earnings impact. Production for the quarter was 42,400 barrels equivalent per day, or 255 million cubic feet equivalent a day, which is just at the upper end of our fourth quarter guidance. Volumes from both the Gulf of Mexico and Appalachia were slightly above plan with the December Cardona and Utica volumes--in December, Cardona and Utica volumes added to the year-end exit rate of over 275 million equivalent sum per day. Remember we sold our non-core conventional shelf assets in July and other non-core properties throughout the year; however, the new volumes from our Cardona, Utica and Marcellus wells now more than offset the production from these divested properties. Our Cardona volumes have remained stable at around 10,000 Boe per day and the Cardona No. 6 to be drilled this year could add another roughly 5,000 Boe per day in the second half of the year. In mid-February, we were producing in excess of 130 million equivalent per day up in Appalachia, although we would expect these volumes to decline during the year as no new wells will be completed in 2015. As you know, we’ve laid down our Marcellus rig. As an aside, we’ve also been experiencing some weather-related freezing shut-ins on selected pads in Appalachia, although the higher Appalachian prices certainly have provided some relief. Overall, we are projecting 2015 volumes to be in the 39,000 to 43,000 Boe per day range, or 234 to 258 million cubic feet equivalent per day, which is around a 10% increase over 2014 when you pro forma for the property sales of last year, assume they were out in the beginning of the year. We’ve also provided guidance for the first quarter ’15 at 45,000 to 46,000 Boe per day, although after the first quarter, subsequent quarters will be subject to our overall natural decline until the Cardona No. 6 provides incremental volumes. With the added production from the Cardona wells, we would expect our higher margin oil and NGL barrels to be over 50% of our total 2015 volumes. Regarding pricing, our quarterly oil price realization before hedging was under $70 per barrel, which was down about $24 from the third quarter. Our oil hedges pulled up realized prices to just over $83 per barrel, but the low prices seen in the first quarter will clearly push down realizations in the first quarter despite being around 50% hedged at $92 per barrel. Our gas price realization remained under $3 for the fourth quarter due to both weak Henry Hub benchmark and the negative Appalachian differentials. Obviously, the industry success up in the Marcellus and now the Utica has caused a regional oversupply situation, although the expansion response from the midstream and pipeline companies suggests much of the access issue should ease over the next 12 to 24 months. We have secured sales arrangements through this year, which provides us with a market for our gas but are subject to pricing at the M2 Index. On a positive note, during these winter months, we have experienced improvement in the Appalachian differential. Also, due to accounting complexities, the effect of some of our 2015 gas hedges were recorded through the income statement as derivative expense of about $16 million in the fourth quarter and $18 million for the year, which was primarily tied to the outer month mark-to-market gains. We expect this treatment to continue in 2015 with the same desired protection of the gas hedges, but we are recording it through derivative income. For cash flow purposes, the cash from these hedges will be received during the course of 2015 as we subtracted them out of the 2014 discretionary cash flow number. In the fourth quarter, our realized NGL prices averaged around $32 a barrel, down from the third quarter but still a little stronger than may have been expected. Remember in Appalachia, we capture some condensate in our NGL volumes, so it provides us a small uplift in pricing. The first quarter NGL price have definitely trended downward from that $32 number. On the cost side, our LOE dropped to $36 million for the quarter as the sale of the non-core properties helped reduce our operating expenses. We expect LOE to decrease again in the first quarter and have set our 2015 full-year LOE guidance to a range of $115 million to $125 million, which is down over 30% from 2014 primarily due to the sale of the non-core shelf assets. However, remember that even as we add Cardona volumes, we would expect our absolute LOE cost to remain pretty flat, which should lead us to a reduced LOE per Boe on that unit basis. This is part of our operational leverage at the Pompano platform where platform or PHA fees that we receive from our partners can offset or really more than offset the incremental cost of the new production. The transportation, processing and gathering expense was over $19 million for the quarter as Appalachian volumes increased. We would expect this figure to increase slightly in the first quarter with the increase in Appalachian production, but then taper off as the decline curve takes hold. Our DD&A rate for the quarter is $3.55 per Mcfe. We would expect this DD&A rate to be in the $3.30 to $3.60 per Mcfe guidance range for 2015, although any potential ceiling test impairments may impact this figure. Our base G&A before incentive comp came in at just over $17 million for the quarter. We would expect this figure to trend down slightly during 2015 as we have had some staff and cost reductions, although first quarter we might have some charges tied to this reduction. Reported interest for the quarter was just over $10 million, flattish with the third quarter. Once again, remember that about $4 million of reported interest expense per quarter is non-cash tied to the convertible notes accretion. Our total cash interest is still running about $16 million per quarter. Regarding taxes, our reported taxes were negative due to the ceiling test impairment, but we paid minimal cash taxes for 2014 and would expect this to continue in 2015. Our capex for the fourth quarter was about $228 million, $229 million or over $880 million for the year. The annual figure includes about $56 million in abandonment expenditures. The fourth quarter also recorded much of the installation and facilities expenditures at Cardona, the Utica completion, and some long lead items for the Amethyst development. As previously disclosed, our Board has authorized our 2015 capex budget at $450 million. At year-end, we had about $250 million in cash, including $177 million in restricted cash tied to the non-core property sale. At February 24, we had about $216 million in cash, all unrestricted as the restrictions on the potential lifetime exchange structure all lapsed. Our $500 million bank facility remains undrawn except for $19 million in LLCs, so we have plenty of near-term liquidity. We believe this liquidity will fund us into 2015 and provide us with balance sheet strength and flexibility. Our 2015 hedge position is included in the press release and shows about 50% of our expected oil and gas volumes hedged at a price of almost $92 and $4.15 per Mcf. With that, I believe that wraps up the financial overview, and I’ll turn this back over to Dave.

[David Welch:]

Okay, thank you, Ken. In response to the low price environment, we’ve moved quickly to adapt. We’ve maintained our organizational capability and have been able to maintain most of the optionality on our future opportunities. That said, however, we responded dramatically and have reduced our capital budget by 50%, our lease operating expense budget by 35%, and our SG&A by 10%. We believe that further reductions may be possible as these do not yet reflect significant savings on materials and services. On the capital budget, we will executing mostly development projects in the deepwater Gulf of Mexico, which has among the lowest cost of oil supply in the non-OPEC world, and our projects show very favorable cost metrics. We have ceased drilling and completion operations in the Marcellus for now as we believe the netback pricing there will improve in a couple of years and we will commence our spending to coincide with better pricing. The three deepwater development projects that we’ll invest in this year are expected to have combined development and LOE costs of approximately $30 per barrel, $15 per barrel, and $13 per barrel. These projects are expected to generate attractive margins and returns, even in a low price world. In the order of the costs mentioned above, we will drill and hook up one additional well to the Cardona flow line loop, which came on production in November. This is the Cardona No. 6 well, which is a very probability of success investment and will be hooked up for production within six weeks of drilling and completion. This should be another 5,000 to 6,000 barrel of oil equivalent per day that we’ll produce through our 100% owned Pompano platform. We own a 65% interest in the No. 6 well, which should have a negative LOE per barrel as we process our partner’s oil and receive a credit for that. The combined development and LOE cost of this project is all-in at about $30 a barrel. The second project we’ll do is to complete the 100% owned Amethyst discovery well drilled in 2014 and construct a single line tieback to Pompano, projected to come online in the first quarter of 2016. One of our strategies to manage capital is to discover and dilute, and we may spend down a percentage of Amethyst to conserve capital in the current environment. We are in discussions with interested parties now. The combined development and LOE for this project will be all-in at about $15 per Boe. The third development investment we’ll likely commence this year is the placement of a platform rig onto the Pompano platform to complete one major rig work-over and drill three development wells. This project should add another 5,000 to 6,000 barrels of equivalent per day and it’s expected that combined development and LOE costs should be all-in at around $13 per barrel. This is probably the highest IRR project available in the company. We also expect to participate on a levered basis in two exploratory prospects in Mississippi Canyon, which is among the lowest cost of supply oil in the Gulf. At present, Coneco is drilling the Harrier well in which we have a 20% cost interest and a 37% working interest. The well is expected to be down in late spring, followed in the summer by the ENI-operated Vernaccia well. We own a 32% working interest and a 25% cost interest in Vernaccia. If successful, it’s likely that both wells could be tied back to our Pompano platform and possibly operated by Stone. Pompano platform is now producing at about 15,000 barrels of oil per day and has the capacity to process 60,000 barrels a day and 200 million cubic feet a day, so lots of running room there. As you will recall, we were able to negotiate an attractive win-win deepwater rig contract with Ensco for the dynamically positioned 8503 rig. We expect to capture the rig in April when it will first drill and complete the Cardona No. 6 well. The rig is then planned to go to the shipyard to add a mooring system, making it one of the only deepwater rigs capable of being moored or dynamically positioned. This means that it can operate in water depths from 800 feet to well over 8,000 feet of water, making it one of the most flexible rigs in the world. This is important because we can drill any well in our portfolio with the 8503, and also because we plan to farm out a rig slot to another operator to conserve capital this year and next. We’re in discussions with interested parties on this activity at present. We then expect to complete the Amethyst well after the rig is released from the shipyard and may commence an exploration project after that, depending upon the potential farm-out result. In Appalachia, as mentioned, we’re taking a Marcellus drilling and completion time-out pending new third party infrastructure expansion. This is expected to cause a reduction in Appalachia differentials and higher wellhead netback prices in a couple of years. We have the luxury of taking this time out because our inventory of robust Gulf investment opportunities, which generate favorable economic returns even in the current environment. We expect to initiate an Appalachia-Point Pleasant-Utica development program either late this year or next year, depending upon regional developments. We’re constructing a fit-for-purpose walking rig which is expected to be available around year-end and is capable of efficiently drilling either the Utica or Marcellus. So that’s what 2015 looks like. We have significant reduced our cost structure already, and it could improve further as we make progress on materials and service cost reductions with our vendors and service providers. Also, it may be worth a quick look back to 2014. This was probably the best performance year in the history of Stone Energy. We made three important discoveries

[Operator:]

[Operator instructions] Your first question comes from the line of Patrick Rigamer with Global Hunter Securities. Your line is open.

[Patrick Rigamer:]

Hi, good morning guys.

[David Welch:]

Morning, Patrick.

[Patrick Rigamer:]

Just maybe a bigger picture question. Over the past couple years, you guys have kind of high-graded the portfolio and rearranged your properties. I’m just curious, are you done with that process, and does the currency commodity price environment make you think any differently about your portfolio, or just any comments on A&D there?

[David Welch:]

I think the way we’re positioned right now is exactly where we want to be, and it’s probably the best place you could be positioned in a low cost, low commodity price environment, just given the cost structure of the projects that we have in the deepwater as well as those that we have up in Appalachia. So we have a Twin Towers portfolio right now - we like that. Obviously if an acquisition comes along, we are always in the market for an acquisition to deepen our interest in our core area if the price is right, so that is something that we’ll be considering.

[Patrick Rigamer:]

Okay, and then I wanted to ask--I guess you touched on a little bit in the prepared remarks, but the 8503, the plan there is the Cardona well, then it goes back to the shipyard, and then it goes to the Amethyst completion, and beyond that either potentially an exploration prospect or farming out the rig slot as we kind of move into 2016. Is that correct?

[David Welch:]

That’s correct.

[Patrick Rigamer:]

Okay, thanks.

[Operator:]

Your next question comes from the line of Chad Mabry with MLV & Company. Your line is open.

[Chad Mabry:]

Thanks, good morning. I had a question on your thoughts on the M&A environment in the Gulf of Mexico, both in terms of the type of opportunities that you’re seeing maybe to pick up prospects and add to your inventory, and in terms of interest from potential partners in your prospects, I guess specifically on the discussions with Amethyst.

[David Welch:]

Sure, so the A&D environment first. There are, we think, about three deepwater packages going to hit the market this year, all of which might have interest for us, but we’d need to see the specifics before we get too deeply involved in that. From a priority standpoint, we’d be looking for something that would provide cash flow that would be material, and as a sidebar if it had some infrastructure associated with it, similar to Pompano or Amberjack, that would be a bonus; and then if there’s exploration potential around the area, that would also be a bonus. So those are kind of the criteria that we’re looking at

[Chad Mabry:]

Really just the other side of that thought process as far as potential partners and the interest that you’re seeing there.

[David Welch:]

Yes, so Amethyst is the one that we’ve taken out to market so far. We took it over to the NAPE Convention that was held in Houston, and I think we have about five parties that are taking a deeper look at it, so it’s getting some interest. It’s not an exploration project; it’s a development, basically, so the exploration risk is more or less gone. Amethyst does have a sister prospect we haven’t drilled yet, called Derbio, which people that are interested in Amethyst are likely to be interested in Derbio as well. So I think that our portfolio is pretty good and we’ve been able to secure partners already for the prospects that we owned 100% - you know, we have Coneco and ENI in a couple of our projects already, which I think speaks to the viability of our portfolio to attract those sizeable companies. You may recall we had a prospect that attracted Exxon last year as well, so we’ve got a pretty good inventory of prospects.

[Chad Mabry:]

That’s great color. Thank you.

[Operator:]

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

[Gail Nicholson:]

Good morning. Looking at that potential farm-out of the deepwater rig, are those potential savings baked into that $450 million capex budget for ’15, and if they’re not, what would you do with that additional savings to farm out that rig for 30, 60 days?

[Kenneth Beer:]

Gail, it’s Ken. So with our capital budget, as always, we have a lot of expected value figures in there. In the case of the rig farm-out, we have some probability of occurrence, so we’ve got some expected savings actually baked into the 450. There’s certainly a chance that we can have more than that, and a chance that if nothing happens, it will be less in terms of our ability to farm out the rig. So every project we have has some expected value and probability of occurrence, so that’s where we kind of roll up to the 450.

[Gail Nicholson:]

Okay, great. Then looking kind of forward into ’16, specifically in Appalachia, what type of price signal do you guys want to see from the natural gas side and/or liquids side to re-engage that program?

[Kenneth Beer:]

What do we want to see? We’d love to see 5, but probably if you get back to a more typical, even if it’s a $4 Henry Hub with a $3 Appalachian number, that seems to be a place where you can start getting some real returns again. I think really what we, and I would suggest the whole industry, is experiencing now is just more of a recycling of dollars at these gas price levels. So you’d like to see the Appalachian price get closer to that $3 again.

[Gail Nicholson:]

Okay, and then just one real quick - Amethyst, it looks like production is going to happen sooner than originally expected. It’s now--based on the release, you said early ’16. I think in the least presentation, you guys were talking mid-’16. Can you just discuss behind what’s behind the timing adjustment?

[David Welch:]

Well, we’ve placed all the orders for the long leads. We expect to have them in. We have the rig coming - it’s on a schedule, so that takes to completion off the critical path. Based on the track record that our team has established with Cardona, we just believe we know how to execute these projects and so we have taken a little bit of the contingency time out and that moves us up to early in the year.

[Gail Nicholson:]

Okay, great. Thank you.

[Operator:]

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

[Richard Tullis:]

Thanks, good morning. Looking at the 2015 production, Ken, I know you gave guidance for the first quarter. Beyond the first quarter, how does it look on, say, a quarterly basis, particularly fourth quarter ’15, say, versus the fourth quarter of last year?

[Kenneth Beer:]

I think what you’ll see, Richard, is from the first quarter, second quarter would certainly trend downward because you’re just looking at the decline curve. Third quarter would also see some decline, although--and we also in the third quarter, as you might remember, we do bake in some hurricane downtime, and then the fourth quarter, you should see some stabilization, maybe even a slight incline with the Cardona No. 6 having its impact. So the shape of our production should be certainly highest in the first quarter, down in the second quarter, maybe the low point might be the third quarter, and then a little bit of a bounce, flattish to a bounce in the fourth quarter.

[Richard Tullis:]

Okay, and then in Appalachia, I’m sorry if you said this already, but what do you expect that will generate in production? I know you did about 128 million a day in the fourth quarter, and with no activity that should be coming off a fairly good bit. What do you expect Appalachia will produce in 2015?

[Kenneth Beer:]

We’ve put out actually in the January release, and probably think this is still a good number, that we should average around 150 million or so, plus or minus. We’ll start the year obviously at a higher level and end the year at a lower level than that number, but that is versus about 100 million a day in 2014. So year-over-year, Appalachia is going to be up; exiting the year, we will certainly be down in the fourth quarter versus the first quarter.

[Richard Tullis:]

So I guess that will help push your oil component of total production up a little bit for 2015 versus where you were in the fourth quarter of last year?

[Kenneth Beer:]

Correct, and as I mentioned in the comments, particularly with the two Cardona wells that we currently have on, and we’ll have now full quarter and first quarter of ’15, and then the Cardona No. 6 that we’ll bring on as well as Appalachia, and particularly Appalachian gas declining during the course of the year, you should see the mix turn favorable as it relates to our oil and NGL versus natural gas. We certainly would expect to have oil and NGLs be over 50% with natural gas obviously being less than that.

[Richard Tullis:]

Okay. Looking further out, 2016 and beyond, what do you think it takes capex-wise with current cost expectations to keep production relatively flat with your 2015 outlook?

[Kenneth Beer:]

A tricky question, especially with our properties and our projects. It really is dependent on when and how they come in; for instance, we’ll spend money this year on Amethyst but you really won’t get any production this year, but in 2016 it will come on at, we think, a pretty significant rate. Appalachia will decline during the course of this year, but year-over-year be up. We certainly need some level of drilling to keep Appalachia flat. We kind of have proven that with one rig, we can increase volumes; with zero rigs, it obviously goes down. We’d look out to ’16 and would certainly hope to have volumes be pretty flattish with ’15 as we bring on both Amethyst and then, as Dave alluded, the Pompano platform rig program. Those are the real drivers for 2016. The Appalachia will certainly--if that program gets geared up again for 2016, then you at least have some--would hope to be some incline during the course of ’16 from Appalachia as well.

[Richard Tullis:]

Okay, and then just lastly, what’s the outlook for starting the drilling at Goodfellow this year?

[David Welch:]

Probably not this year. Probably ’16.

[Richard Tullis:]

Okay. All right, that’s all. Thank you.

[Operator:]

Your next question comes from the line of Michael Glick with Johnson Rice. Your line is open.

[Michael Glick:]

Morning. Just a question on service costs. What are you guys seeing in the deepwater? Obviously you’re locked on the rig side, but maybe some color on what you’re seeing on the other services?

[David Welch:]

We’re just really starting to get a little bit of result, Michael. We’ve gone out, and I think we’re going to see something, and we’ve only baked into our plan on the capital side about 5%. But I think we’re probably going to see overall savings in the magnitude of 20% or so. That’d be my guess. We’re starting to get some tenders back from our vendors and service providers, certainly where we buy fuel. We know the fuel cost has come way down, so that’s going to help, but I think somewhere in the 15 to 20% range is probably a pretty good number to think about. We haven’t baked them in yet because we haven’t solidified anything, but that’s an option that’s out there for us.

[Michael Glick:]

Got it. Then Cardona 6, is that in the 2P category, or is that a PUD?

[David Welch:]

That’s a PUD; however, the probable reserves in the Cardona area are potentially twice as big as the proved, so it could help produce that and ultimately grow that number over time.

[Michael Glick:]

Okay, and once it’s drilled and completed, what needs to be done on the infrastructure side to bring it online, and what’s that timing look like?

[Kenneth Beer:]

Just hook it up - less than six weeks.

[Michael Glick:]

Okay, got it. All right, that’s it for me. Thank you.

[Operator:]

As a reminder, that’s star, one if you’d like to ask a question. Your next question comes from the line of Dave Kistler with Simmons & Company. Your line is open.

[Dave Kistler:]

Morning guys. Real quickly, when we look at the balance sheet and liquidity, really no concerns, as you highlighted, certainly through 2016. Understand the desire to sell down Amethyst, but with a LOE net to you guys about $15 a barrel, I would imagine you’d want to see a pretty substantial uplift in terms of what somebody would be willing to bid for that. Is that a fair way to think about that, or are you more focused on bringing additional liquidity to the balance sheet and giving yourself the ability to accelerate other projects at a future date?

[David Welch:]

I think either one is a good outcome, which is a good thing; but I would say that we are more interested in shoring up liquidity and giving ourselves other options. Our strategy in exploration and deepwater all along has had a component of what we call discovery and dilute, so once you make a discovery, you get a step-up in value, and to capture part of that value to help offset the development cost has always been part of our strategy. It’s just even more true in this time. As I mentioned, we have a sister project called Derbio and we have some other great opportunities that we want to get to that we think can create some value for us. So even though it’s 100%, if we do dilute it, the same thing will happen - it will actually not only help our capital but it will also give us a bit of relief on the LOE side, where we could potentially have a negative LOE on Amethyst as well. And that’s a good formula in a low-price world.

[Dave Kistler:]

I appreciate that. Maybe just one in terms of timing - when you’re thinking about putting that rig back out there, let’s call it summer time, from that perspective is the running room for this three months to get the sell-down, or could a sell-down even take place after you start getting the rig out there to finish completion, et cetera?

[David Welch:]

It could happen at any point in time. We’re active on it right now, so it could happen before we get the rig out there or it could happen during operations.

[Dave Kistler:]

Okay, and then one last one just with respect to the rig. In the event that you don’t farm it out kind of after the Amethyst completion, is it something that you can put idle for a period of time and what kind of cost change would that cause, or are you just fully contracted at the given rate?

[David Welch:]

Well, if you just idle it, it would be at the given rate unless you could negotiate something different, which is probably not too likely. That would be possible; that would not be obviously anything we’d really want to do, because the rig cost is more than half, probably going to be more than half of the cost of drilling a well, so you’d like to get something for that.

[Dave Kistler:]

Absolutely. Well, I appreciate the added color, guys. Thanks so much.

[Kenneth Beer:]

Thanks, Dave.

[Operator:]

Your next question comes from the line of Glen Williams with National Securities. Your line is open.

[Glen Williams:]

Good morning, everyone. You may have touched on a lot of these, but I may have missed it. If you could quickly go through the economics of what you’re expecting from Cardona and Mississippi Canyon on an LOE basis. Also, I would imagine you’ve seen interest and continue to see interest in Amethyst, and I was wondering if you could kind of weigh what that interest had been within the last quarter or so versus, maybe, 2013 or so.

[Kenneth Beer:]

The LOE surrounding the Cardona project, if you look, Glen, at what happens to our LOE on an absolute basis, because we do have a partner, Hunt, at 35%, they do pay us a platform handling fee, and that fee actually is credited against our LOE cost. So really, what we’ve tried to communicate is our LOE is going to remain flattish, or in this case slightly negative, as we bring the first two wells, and even as we bring the third well on, so you effectively have 100% or a little over 100% margin on the volumes that we bring on from the Cardona area. With Amethyst, because we have 100%, we wouldn’t have any PHA fees unless we do sell down a portion, but the true incremental cost on an LOE basis is probably in the neighborhood of only about a million dollars, so for volumes coming through the Pompano facility, pretty fixed costs, so obviously you start to push down your LOE per Boe as you get more and more barrels coming through the facility. As I think you might remember, right now we’re at about 15,000 barrels going through but have capacity of closer to 60,000 barrels a day, so plenty of additional capacity, and that’s where you get the operational leverage where you effectively have no real LOE added to the cost side.

[Glen Williams:]

Okay.

[Kenneth Beer:]

And then to your other question with Amethyst in terms of interest, again certainly when we were looking to market Amethyst pre-drill, it was much more of an exploration prospect or project. Now, this is really a development project, although as Dave commented on, the idea of a discover and dilute just to spread your dollars around. IF we get dollars coming in for Amethyst, it obviously allows us to put those dollars to other future projects, so that’s the concept - it would be some partial sell-down at Amethyst, and as Dave alluded to, we have had good interest. It’s something that certainly kind of post-NAPE we might move as quickly as we can with a partner who steps up to the plate, in that we’ll get the rig sometime this summer to be drilling Amethyst. I think the attraction for potential parties is they’re looking at production coming on in 2016. This is not like an exploration play where you buy into it and the production comes three or four years later. This is literally a one-year turnaround.

[Glen Williams:]

Okay, thank you. Then finally, the drilling time-out that you guys are going to have in Marcellus for 2015, is that more targeted by what’s going on with the current price environment that you anticipate moving forward, or does that have more to do with concerns you have about infrastructure constraints?

[David Welch:]

It’s probably a little bit of all of the above, plus just capital conservation. We expect that there--and there is new infrastructure being built in the area, which will enable that gas to move the markets outside of the M2 market area, and when that happens, we anticipate and the market is anticipating differentials will be shrinking. So the time-out is really to close the gap between the time you make your investment and the time you get a better price for your product. That’s kind of the main driver.

[Glen Williams:]

Okay, thank you.

[Operator:]

Your next question comes from the line of Chad Mabry with MLV & Company. Your line is open.

[Chad Mabry:]

Thanks. Just a follow-up on the liquidity question. Looking at the different levers that you guys can hold, so to speak, your hedges obviously stand out as having a lot of value right now. I’m just curious what the discussions are internally on potentially cashing in some of those, layering on new hedges, et cetera.

[Kenneth Beer:]

Yes Chad, again, those hedges clearly do have value, but clearly we will be recognizing that value during the course of 2015. We don’t need the cash in the next 30 days, so to go through the exercise of cashing in the hedges is certainly something we could do if we needed the cash, but it’s an exercise that we’ll ultimately get the value of those hedges over the upcoming year. Unless we wanted to truly try to time the commodity markets, our thought is just to leave the hedges in place.

[Chad Mabry:]

Got it, makes sense.

[David Welch:]

A little more on that is we basically have half of our production hedged, which is more or less a neutral bet on being able to out-guess the market. That’s kind of where we like to be. If we really were going to bet that it was going to go back up this year, we would definitely unwind them, but that’s not a prediction we’re prepared to make at this point in time.

[Chad Mabry:]

Understandable. Thank you.

[Operator:]

Your next question comes from the line of Michael Glick with Johnson Rice. Your line is open.

[Michael Glick:]

Maybe just to follow up on Chad’s question, what are you guys thinking in terms of hedging for 2016?

[Kenneth Beer:]

Mike, we do have just a small handful of hedges in ’16. Our inclination has been not to layer in additional hedges given the ’16 prices for both gas and oil. We’ve just taken the approach of instead of locking in at what we think are lower prices, we’d rather get through and get closer to 2016 and look to hopefully get some higher prices as we get closer to ’16. We would like to, as Dave pointed out, always be at a point where we’re roughly 40 to 50% hedged. We clearly are not there in ’16 yet, but we’ll just continue to monitor the market and if we see some strengthening in the ’16 prices for gas and oil, we may look to layer in some.

[Michael Glick:]

Okay, and then just last one from me, maybe for Dave, could you give us a quick overview of the geology associated with Harrier and what you like about the prospect, and maybe what the kind of key risk is?

[David Welch:]

Sure. We like the prospect, number one, because it’s visible. You can see it on seismic. It offset a block that Chevron paid $53 million for just to the south, after we already owned the updip portion of the structure. It’s also one of these wells that we have a levered interest in. Our partners liked it - Coneco joined in and is actually drilling a well. It’s one of the first deepwater wells they’re drilling after they’ve re-entered the Gulf. So we like it from a lot of standpoints. I think the main geologic risk, it’s part of a big vaulted four-way closure, but you’re depending upon the seal in a three-way, and seal risk, I think, is probably the big risk. I’ve actually got John Leonard in here, who is our Senior VP of Exploration, if you want to get deeper into it; but John, is that fairly accurate?

[John Leonard:]

Yes, it’s in a good neighborhood, too. It’s synchron [ph] separated from some other discoveries in the area.

[Michael Glick:]

Thank you very much.

[Operator:]

There are no further questions at this time.

[David Welch:]

Okay, thank you very much, and we appreciate you joining our call, and hope to see you at our investor presentation shortly. Thank you.

[Operator:]

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