Talos Energy Inc.
Q4 2015 Earnings Call Transcript

Published: 23 Feb 2016

[Operator:]

Good morning. My name is Simon and I'll be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy Fourth Quarter and Year-End 2015 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. Thank you. Mr. David Welch, Chairman, CEO and President you may begin your conference.

[David H. Welch:]

Okay. Thank you, Simon, and welcome everyone to our fourth quarter and year-end 2015 earnings conference call. We're joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read our cautionary statement and review our financial performance. He will then turn it back over to me for an operational update and a few additional comments, and then we'll be happy to take your questions. So Ken?

[Kenneth H. Beer:]

Thank you, Dave. Let me first 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 the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration, development, production, and sales of oil and natural gas. We urge you to read our soon-to-be-filed Annual Report on Form 10-K for a discussion of the risks that could cause our actual results to differ materially from any forward-looking statements that we 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 for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. With that, let me move on. We'll assume that everyone has seen the press release and the attached financials. So I'll focus on some of the key financial and operational highlights. Our fourth quarter results showed an adjusted $2 million of income before pre-tax, non-cash impairment charge of $351 million, which brought the reported loss for the quarter to $319 million. Our discretionary cash flow for the quarter was about $115 million, around $2 per share, although this would be close to $70 million, if you exclude a $45 million expected tax refund, which was included in the calculation. As was also the case last quarter, there was the $351 million non-cash ceiling test impairment, which was primarily due to the lower oil and gas and NGL prices, which are calculated using a 12-month trailing average. Additionally, if the prices in 2016 continue to stay at the lower levels compared to 2015 prices, we would be subject to another non-cash ceiling test impairment in the first quarter, again, no impact on cash flow but a potential reported earnings impact. Production for the fourth quarter, including the impact of the curtailment of approximately 100 million cubic feet equivalents per day at the Mary field in Appalachia, was 24,000 barrel equivalents a day or about 145 million feet a day, which was just above the upper end of our adjusted fourth quarter guidance of 144 million cubic feet equivalent per day. Again, a solid performance for the Gulf of Mexico group in a full quarter production from the Cardona #6 well positively impacted the volumes. Increased volumes from the oily Cardona field and the curtailment of primarily gassy Mary field boosted the liquids percentage up to 67% for the fourth quarter with gas at 33%. We have provided production guidance for the first quarter of 2016 of 32,000 to 33,000 Boe per day or about 190 million cubic feet a day, which assumes the Mary field remains shut-in for the quarter. Similarly, the 2016 full year production guidance is 31,000 to 33,000 barrel equivalents per day. The full year guidance also assumes a Mary field shut-in for the whole year as well as volume increases from the Pompano platform rig program, an increase in the Cardona field as the #7 well comes on line, and then a natural decline at Cardona in the second half of the year, and finally some assumed hurricane downtime primarily in the third quarter. Overall, we are projecting a 30% increase in the Gulf of Mexico production in 2016 over 2015. Regarding pricing, our fourth quarter oil price realization before hedging was around $40 per barrel, which is down from the $70 per barrel from a year ago. Our oil hedges for the quarter did pull up our fourth quarter realized price to just under $70 for the fourth quarter. Our gas price realization before hedges was $1.57 for the fourth quarter due to the weak Henry Hub benchmark and a very negative Appalachian differential for the Heather and Buddy field volumes. After hedging our realized price jumped to just under $2.50 per MCF for the quarter due to the limited volumes combined with the hedges. In the fourth quarter, our realized NGL price increased versus the previous quarter due to the minimal production from Appalachia as the Mary field curtailment reduced the lower priced NGL volumes. On the cost side, we continue to show a declining LOE dropping – at least operating expense dropping to about $21 million for the quarter as operational leverage at Pompano, overall cost savings, and reduced volumes in Appalachia allowed for the cost reduction. The transportation, processing and gathering expense dropped dramatically for the third quarter due to the curtailed Mary volumes, which incorporates a majority of the TP&G charges. Note that our guidance for 2016 excludes production and, therefore, TP&G expenses from the Mary field. Any resumption of production at Mary would cause us to revise our TP&G guidance for the year as well. Our base G&A before incentive comp was about $16 million for the quarter. We would expect this figure to trend towards or under the $14 million per quarter for 2016. Reported interest expense for the quarter was just over $12 million, slightly higher versus the first three quarters due to a reduction in unevaluated properties. Also, as I've mentioned before, about $4 million of this reported interest expense per quarter is non-cash tied to our convertible notes accretion. Our total cash interest, including capitalized interest, is still running about $15 million per quarter. Our reported taxes showed a benefit for the fourth quarter and we would not expect to pay taxes in 2016. In fact we are expecting to receive a tax refund of about $25 million in 2016 and another $20 million in 2017 on tax loss carrybacks tied to P&A expenditures that we've made over the past number of years. This $45 million cash refund, which is now on the balance sheet as a tax receivable, will certainly help during this period. One accounting subtlety to be aware of since we have no deferred tax liability left on our balance sheet, the deferred tax benefit that we can recognize against future pre-tax losses is minimal or zero. So again, there's no cash impact, but it will remove the traditional 36% tax shield in your models for 2016. Our CapEx for the fourth quarter was approximately $134 million or about $464 million for the year. The fourth quarter CapEx included completion and tie-in costs for our 100%-owned Amethyst project and the start of the Pompano platform rig program, which also impacted the fourth quarter CapEx number. Accordingly, we slightly exceeded the board-authorized $450 million budget for 2015. Our 2016 CapEx budget was set at $200 million by the board. The budget is dominated by two projects, the ENSCO 8503 rig contract and the Pompano platform rig development program. Dave will highlight the steps that we have taken to lessen the exposure on the ENSCO contract via some farm-out transactions which our team was able to execute on. Additionally, there are some options regarding the Pompano platform rig expenditures, which could include stacking the rig on location after one more drilling project. In the press release, we also have highlighted that we project to spend an additional $40 million on rig subsidies and potential stacking charges, which will run through the income statement under other operational expenses. This figure is in addition to the $200 million scheduled for capital expenditures. Even though the potential stacking and farmout subsidies feels like CapEx, the accounting standards dictate that this spending is expensed and not capitalized. So we are projecting somewhere around $240 million to be spent on projects and rig charges. However, we will be working hard to reduce this figure during the year, similar to our efforts in 2015. At 12/31/15, we had about $11 million in cash and our $500 million borrowing base remained undrawn except for $19 million in LCs. We were fully compliant with all of our financial covenants under the credit facility at year end. As of today, we have drawn about $50 million on the line and we would expect our borrowing base to be reduced in April for the spring redetermination. As noted in the release, we project that we may breach our total debt to EBITDA covenant of 3.75 times at the end of the first quarter as our EBITDA has continued to decline. We are talking with a bank group on a possible amendment, although any amendment would probably come with some additional borrowing and financial restrictions and a reduced borrowing base. We will continue to review our options regarding the situation. Our $300 million 2017 convertible notes mature one year on March 1, 2017. We are reviewing our options for addressing the converts, including various financing, asset sales, and debt restructuring alternatives. No decision has been made, but the management and board have been deliberating on the different actions for the company as liquidity remains a focus for Stone. Finally, we continue to monitor BOEM, the offshore regulatory body charged with the financial surety on abandonment obligations. BOEM has issued draft guidelines for a new set of regulations, but the exact timing and impact is very difficult to guess. However, even under the current regulations, we would expect to lose our exempt status and could be asked to provide supplemental bonds or some other form of surety. We will be meeting with BOEM in the coming months and we'll be reviewing with them the required steps to be made. And lastly, a comment on our reported reserves. Our estimated proved reserves at year-end were 57 million barrel equivalent, with another 23 million barrel equivalent and 59 million barrel equivalents of probable and possible reserves respectively. Also, as noted in the release, there were 95 million barrel equivalents or 570 Bcfe of proved reserves in the 2014 year-end figure, which were reclassified at year-end 2015 as contingent resources due to the lower prices. This included substantially all of the Appalachian crude reserves. Obviously, the resource is still in the ground, but is not economic at the $1.50 per Mcf price for gas and the $11 per barrel for NGLs used in the year-end calculation for 2015. We did show a positive performance revision of about 8 million barrel equivalents for the year and our proved developed reserves now constitute almost 75% of the total. I believe that wraps it up for the financial overview, and with that, I'll turn it back to Dave for his comments.

[David H. Welch:]

Okay. Thank you, Ken. No doubt, 2015 and 2016 will be remembered as tough years for our industry. The low-price environment has caused financial stress on many companies and Stone is no exception. While 2015 was a down-year for commodity prices, we've done well with the variables we do control. We increased annualized daily production year-on-year before shut-ins at our Mary Field, decreased operating cost, reduced overhead, and significantly reduced our capital spend. In 2016, we expect to continue to reduce operating cost and overhead, and increase our Gulf of Mexico production. In addition, during 2016, we're targeting to reduce our capital expenditures to about $200 million, manage through our bank redeterminations, and address the 2017 convertible note maturities. Ken's already discussed the bank covenant issue and our options to handle the 2017 converts, so I'll focus more on the operational performance and how we plan to manage our capital spending. In our Gulf of Mexico deepwater, production from the Cardona field commenced in 2015, beginning with the number 4 and number 5 wells early in the year, followed by the drilling and completion of Cardona #6 in the fall. We've just finished drilling and completing the Cardona #7 well, which we expect to be on production in March or maybe even earlier. We've completed and hooked up our Amethyst discovery near the end of December. The Cardona #4, Cardona #5 and Cardona #6 wells were contributing about 15,000 barrels of oil equivalents per day gross and 10,000 barrels of oil equivalent per day net. The Amethyst well is producing at about 35 million gross and 30 million net cubic feet of equivalents, and the Cardona #7 is expected to produce about 5,000 barrels per day gross or 3,000 net barrels of oil equivalent per day. Production from these wells is expected to provide a year-on-year production increase in the Gulf of Mexico. In addition to increased production, Stone has reduced absolute and unit operating costs by about 40%. Unit costs have dropped from $11.32 per barrel last year to $6.92 per barrel this year. Our target for 2016 is to further reduce both absolute and unit lease operating costs. In order to reduce our Gulf of Mexico capital spending in 2016, it will be vital to manage the financial exposure inherent with our deepwater rig contract. We're currently about one-third of the way through the ENSCO 8503 contractual obligation, with the remaining exposure just under $90 million. The contract is being managed through a combination of farmouts, drilling exploration wells at lower working interest, and if need be, exercising our option to stack the rig. We have been successful in securing a farmout to an operator, who expects to commence around March 1. This work is expected to last about 60 days to 90 days. We've also reached a verbal agreement with the second operator, that should cover another 90 days to 120 days. Upon completion of these two farmouts, Stone expects to have fulfilled just under half of the total contractual obligation. We're also in discussions with operators for additional rig usage and we'll update you on those as they mature. Stone will also seek to drill exploration projects and working interests such that the cost to drill the well would not exceed the cost of cold stacking the rig. Finally, we have the ability to use the rig and reduce costs for P&A work or to cold stack the rig. We would only cold stack as a last resort to help meet our capital target. Our Marcellus and Utica assets in Appalachia have been significantly impacted by the low gas and NGL prices and high differentials to Henry Hub prices. The combination of low wellhead prices and a challenging process agreement does not permit us to realize the value of our Mary field at this time. The suspension of drilling and production shut-ins has resulted in the shift of our reserves out of the proved category and into contingent resources as Ken explain. The gas volumes are still present underground, and with an improvement in gas price and/or reduction in transportation processing and gathering costs, these volumes would likely return to the proved category. As with the deepwater Gulf of Mexico, and Appalachia, our teams increased annual production in 2015 despite our Mary field being shut-in for the last four months of the year. In Appalachia, peak production for 2015 was 155 million gross cubic feet of gas equivalents per day to 160 million gross cubic feet of gas equivalents per day. Absolute and unit operating cost reductions were also achieved in Appalachia, with absolute operating cost decreasing from about $20 million in 2014 to $15 million in 2015. Lower absolute lease operating cost, coupled with a higher rate, decreased unit operating cost by 26%. We realize the importance of staying financially liquid during challenging industry environments. We entered the year with $500 million undrawn credit facility, however, as the banks lower their price forecast, we anticipate downward pressure on our facility during the year. We will continue to use this liquidity tool as needed, as we continue navigating through the downturn. The reduced capital program with lower cost, combined with relatively stable production should lessen the amount we'll need to draw on our credit facility. So, while 2016 poses many challenges, we're examining all options to protect the enterprise, and as described, are in action on many of these already. So with this, we'll now be happy to take your questions. Simon?

[Operator:]

Your first question comes from the line of Dave Kistler with Simmons & Company. Your line is open.

[David William Kistler:]

Good morning, guys.

[David H. Welch:]

Good morning, Dave.

[Kenneth H. Beer:]

Good morning, Dave.

[David William Kistler:]

Real quickly, thinking about the curtailments and the guidance that you guys have provided, in the event that you lift the curtailments, can you talk a little bit more specifically about how that would impact transport and LOE? I know you mentioned that LOE – I mean the transport would certainly move higher, but can you give us a magnitude, and same thing with respect to LOE?

[Kenneth H. Beer:]

Yeah, Dave, it's Ken. On the LOE side, maybe just a slight increase in guidance. Again, you're not talking about a large absolute number to start with, and there are some – there's still some operating expenses that we incurred even while shut-in. So, small adjustment, maybe $5 million, something like that. On TP&G, again, it will be – it certainly will be a larger adjustment. Some of it is highly dependent upon the type of fees that we will be paying going forward. Certainly the fees that we paid for the first couple of quarters were just not economic, and so we backed off of that. But you can see for the first three quarters of the year, we were about $55 million. So kind of from a run rate standpoint, versus the $3 million that we had in the third quarter and maybe the $20 million that we are providing guidance on, the $20 million really incorporates the TP&G fees on Amethyst as well as the additional production in the Gulf of Mexico. But depending upon when, we would certainly expect to see that number move up pretty significantly, that $20 million TP&G estimate move up pretty dramatically, depending upon when we bring on the Mary Field.

[David William Kistler:]

Okay. I appreciate that color. And then maybe switching over to the comments about remarketing of the rigs, and maybe looking a little bit more for specifics here, when you gave kind of the $40 million to $50 million of cost that might be incurred associated with that, I guess $6 million would be associated with the stacked rig up in the Marcellus, and then the balance would be probably more specific to the ENSCO rig. Can you talk about how that shifts around relative to your guidance? Is that balance already incorporating the two agreements that you have in place? Is it incorporating anticipation of another agreement with respect to farming out, just trying to dive into a little more detail there?

[Kenneth H. Beer:]

Yeah. And even that's a bit of a moving target in that we've got a probabilistic model that we're using. So, you know, this is somewhat of – ultimately it will be deterministically that happen or not. But we do have baked into our assumptions and into our numbers that we would have the farmout that is now going to take place starting, let's call it, March 1, and then followed by a second farmout. And then the back-half of the year, once those farmouts are complete, we'll either have the rig drilling for us at either Derbio or Lamprey, or we've got some modeling that has it as stacked. The $40 million really incorporates the rig subsidy that we are providing for the next, let's call it, roughly six months, as well as some chance of occurrence of just a – of a suspended or a stacked for the remaining four-plus months at a stacked rate. So that's how we come up with roughly $40 million on the other operational expense side. Again, it's – you know, we're looking at somewhere around $240 million-ish as where we stand currently. As we mentioned in the comments, our real push is to get that $240 million down closer to $200 million or certainly approaching $200 million, and there are some steps that we can take, but it's going to – I wanted to make sure that people recognize that some of those dollars are coming out through the income statement, not through capital expenditures.

[David William Kistler:]

Okay. I appreciate the added color there. And then one last one. Can you give us any sort of update in terms of what you guys are hearing with respect to the Pemex well and maybe what that's doing with derisking Lamprey or with respect to selling down the working interest there?

[David H. Welch:]

Yeah, thank you for that question, David. In all candor, we don't really know anything about it. There are rumors floating around the industry, but that's all we're really hearing. The one thing that we are – the one, I guess, positive piece of information that we do have is the rig is still on location. And we believe, but we're not a 100% positive, that they are sidetracking the well, which, if so, might be a positive indication. So, it's a tight hole. There's very little information available about it. We just know from GPS positioning that the rig is still on location. And I wish I could tell you more, but that's really all we know right now.

[David William Kistler:]

I appreciate that, and thanks for sharing what you do know.

[David H. Welch:]

You're very welcome.

[Operator:]

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

[Richard Merlin Tullis:]

Thanks, good morning, everyone.

[Kenneth H. Beer:]

Morning, Richard.

[Richard Merlin Tullis:]

Ken, how much of the $200 million budget, you know -- continuing around on the previous line of questions -- how much of that $200 million budget is directly related to the deepwater rig, and how much does that roughly work out to on a daily basis?

[Kenneth H. Beer:]

Yeah, so I'll give you just some guidance there. The ENSCO rig, whether it's going to be CapEx or some sort of rig subsidy or stacking charges, we think it's somewhere around $85 million or so for the year. The Pompano rig, pretty similar, about $85 million. Appalachia, $5 million or $10 million. You got seismic at somewhere $20 million-plus. You've got some inventory, that's maybe $10 million to $15 million; recompletions, which is $10 million to $15 million, and then a P&A of roughly $20 million. So, if you add all that up, should be kind of in that roughly $240 million. I've mentioned that particularly on the Pompano platform rig of $85 million, there might be some downward pressure that we can exert there. That assumes, actually, a three-well program. And then the ENSCO rig, again, that roughly $85 million assumes we either are farming out, which we think we've got two farmouts, so that's part of that number, but then after that, as I had mentioned, we either going to – we will take it and drill with it or stack it, and it will – the way that we've got it modeled is we'll have to sell down some working interest, so that we come close to what that stack rate looks like. So, rough number, to answer your question, roughly, $85 million.

[Richard Merlin Tullis:]

When you run the rig, is it in the ballpark of around 7,000 a day gross?

[David H. Welch:]

Yes. So if you run the rig, the overall run rate is around 800 or so. And of course if the rig is cold stacked, you know, that's a lot lower rate. One of the strategies we're pursuing is to take a small working interest in other people's exploration projects who may not have a rig and then be able to come in at a 10% rate, so that the – you know, 10% of the 800 would be less than the cold stack rate. So that's the angle that we're pursuing there. And then of course there are other farmout potential that we may be able to achieve.

[Richard Merlin Tullis:]

And, David, I apologize if I missed it. What is the cold stack rate?

[David H. Welch:]

I don't know if we've ever declared that. Ken, have we?

[Kenneth H. Beer:]

No, we haven't. The stated rate – the working rig rate is about 340,000 Boe a day. But certainly the suspended number, suspended – if we decide to just suspend drilling on the rig, it certainly drops from there.

[David H. Welch:]

I think we probably have a confidentiality agreement preventing us from disclosing that exact number.

[Richard Merlin Tullis:]

Sure. Sure. I understand. The 2016 production guidance, could you roughly split that percentage-wise by area?

[Kenneth H. Beer:]

Yeah. It's pretty simple. It's pretty much all Gulf of Mexico except for, you know, roughly 20 million cubic feet equivalent from Heather and Buddy up in Appalachia.

[Richard Merlin Tullis:]

Okay. Okay. Speaking of the surety bonds that you may need to put in place for the Gulf of Mexico, what would the potential cost of that be, Ken, and is there enough availability out there for that?

[Kenneth H. Beer:]

It's a good question and that's why I bring it up and that we honestly don't know those answers very much in limbo. There, we've been able to secure some surety bonds. We proactively actually this past year, we proactively went out and we've got a couple of $100 million of surety bonds already utilized. Our cost for that would – just for the current $200 million is probably $3 million or $4 million, not a big number. And if we had to double or increase by another $200 million or $300 million, certainly the expectation is that number would go up, but, Richard, hard to know exactly what that would move to. Its just – it's a very dynamic market. But to date, we've had a pretty good experience in both securing bonds and securing on that at least what we think are appropriate pricing.

[Richard Merlin Tullis:]

That's helpful. And just lastly from me, Ken, what working interest would Stone look to reduce to, say, as acceptable range for the deepwater exploration wells, Derbio and Lamprey, Rampart versus the current 100% interest?

[Kenneth H. Beer:]

Yeah, I'll just say we'd probably ideally like to get down to 25% to 33% range with some kind of an industry promote (32

[David H. Welch:]

And to that, if you look, if we can get down to a cost basis of roughly 25% in that that is somewhat close to or in line with what the stack rate would be. So that's kind of why we figure we can target in that 25%, 30%, then we'd certainly rather be drilling than stacking.

[Richard Merlin Tullis:]

That's all from me. Thank you.

[Kenneth H. Beer:]

Thanks.

[Operator:]

Your next question comes from the line of Marc Kaufman with Institutional Equity (33

[Unknown Speaker:]

Good morning. I was looking at the differential on oil in the fourth quarter. Was that a negative differential or positive? And I was wondering what you're thinking about for this year?

[Kenneth H. Beer:]

Yeah, the differential still (33

[Unknown Speaker:]

Certainly. A question, if I missed it, interest expense capitalized for this year, is that included in your CapEx number or is the CapEx number a cash number?

[Kenneth H. Beer:]

It's excluded from the CapEx number.

[Unknown Speaker:]

Thank you.

[Operator:]

Your next question comes from the line of Jon Evans with JWEST. Your line is open.

[Jonathan Evans:]

Hey, Ken. I know you have a lot of moving parts with the CapEx, but, you know, if you assume kind of the guidance comes in where you thought with CapEx and the strip stays the same, where – how far do you think you get into the revolver?

[Kenneth H. Beer:]

Yeah, again, I probably won't come up with a number, but I think it's certainly the case that we will have to go into the revolver. We are $50 million into it, really, here in the first quarter, albeit realize in the first quarter, we had the Cardona well that we were drilling and we had Pompano that we were drilling, so any sort of pullback from those two which we would expect starting March 1 for the ENSCO rig and even with the Pompano rig in the back-half of the year, we certainly could look to pull back and stop drilling there. So, we certainly are looking for the facility to provide the gap between cash flow, but the exact number is indeed a moving target.

[Jonathan Evans:]

Okay. And then from the standpoint of the tax refund, the $25 million that you're going to get for 2016, do you know roughly when you'll receive that, and then will you receive the $20 million for 2017 also in 2016 or is that in 2017?

[Kenneth H. Beer:]

Again, this is the government coming back to us where we think we would have about half, or let's call it $25 million sometime in the summer, and then the remaining $20 million either late this year or maybe the beginning of 2017, we really don't know. It's probably important to at least recognize that there's roughly $45 million that is cash coming back to us that probably folks did not have in their model, but that we would expect to receive sometime in the next, let's call it, 12 months.

[Jonathan Evans:]

Got it. And then, can you just – can you talk a little bit relative from the standpoint – I'm sure you saw Gastar's news yesterday selling the piece, and that's kind of right where you guys are in the Marcellus, if you put that same kind of valuation, you guys would get somewhere between $250 million and $300 million. I guess, is selling assets or getting out of the Marcellus an option to help your liquidity, et cetera?

[David H. Welch:]

Yeah, let me take that one. It's Dave. I think the best way to say that is that all options are on the table right now. I will say that long-term we love the Appalachia asset, that we feel like there's a lot of gas there. Our acreage is right in the core of the core. And doing some type of joint venture in Appalachia is something we've long contemplated, and we're certainly considering that along with all the other options right now.

[Jonathan Evans:]

Okay. And then just – you've had this on your slide before, the infrastructure sale leaseback. I mean, Pompano has got to be worth at least $300 million. Is that something you guys are still broaching or not?

[Kenneth H. Beer:]

Jon, it's out there. It's a bit more complex and really would have some ramifications on both the credit facility as well as the borrowing base itself, because all those reserves are tied to the facilities. And so, yes, it's out there as an option but it looks to be at least a relatively complex option at this point.

[Jonathan Evans:]

Got it. And then the last question, I'm just curious, I mean, are you guys trying to prepare for a pre-packaged bankruptcy? I mean, if you look at the converts, they're roughly trading it with about $168 million in value. The other bonds are $217 million roughly, so that gets you to $385 million. You've got $50 million out in cash. I mean, if you look at St. Mary's and you look at the platform, I mean, that's – we're $600 million alone, you get the oil for free. So do you feel like the bondholders are trying to push you into a pre-packaged?

[Kenneth H. Beer:]

Look, as Dave pointed out, we obviously are looking at a wide spectrum of a lot of different options, because in this environment, you need to look at everything. And as I had mentioned, we're looking at restructuring, we're looking at asset sales, we're looking at what else we can do to address what is clearly a very, very difficult environment from a pricing standpoint. But as I also mentioned, we really have not made a decision as to kind of our next step. So that's clearly something that management and ultimately the board will be contemplating.

[Jonathan Evans:]

Okay. Two last questions. Just from the standpoint, do you know – do you have any insight into when – you'll know back from the bank roughly if you're going to get some kind of amendment?

[Kenneth H. Beer:]

Yeah. So we actually have been in discussions with our bank group. Truly over the last four weeks, things have shifted around where we're looking at a different structure on the amendment and kind of shifted to a plan B with our discussions. And really just recognized that we weren't going to get something done before the conference call and before the 10-K. So those are conversations that we will look to resume sometime probably into this week. But I don't have a sense of timing but recognize we're not out of compliance. We're fine through the year-end and therefore through the first quarter. And actually it's pretty close as to what our total debt-to-EBITDA number looks like at the end of the first quarter. But our thought was, let's be proactive and at least have some of these discussions with the banks now.

[Jonathan Evans:]

Okay. One last one, I promise, just – and maybe don't want to answer it, but I mean do you guys plan on paying the interest in the convert in 31?

[Kenneth H. Beer:]

Yeah, again, we'll look at all options, but I'd certainly recognize that's coming down the pipe next month. And realize...

[Jonathan Evans:]

So is that a yes or a no?

[Kenneth H. Beer:]

Well, I just – I mean, realize it's not a big number. I mean, on the converts, it's not a big number. It's a couple million dollars. So – but again, we'll be reviewing everything.

[Unknown Speaker:]

Okay. Hey, thanks for your time.

[Kenneth H. Beer:]

Thank you. Take care.

[Operator:]

Your next question comes from the line of Ron Mills with Johnson Rice & Company. Your line is open.

[Ronald E. Mills:]

Hey, guys. A lot has been asked. Just curious, Ken, on your borrowing base, any sense as to how much of your $500 million borrowing base was supported by Appalachian basin and how that might have been impacted by the year-end reserves related to price revisions?

[Kenneth H. Beer:]

Yes, a fair question. So this is now going back to June, so that's what the fall was based on. You still had Appalachia as actually a pretty small component of the borrowing base calculation, just because even back in June, the PV-9, which the bank goes off of, still was looking at pretty low prices, but certainly there was some value, so I don't want to say it was zero. It was just reduced. Obviously at year-end 2015, from a SEC PV-10 standpoint would suggest that there's virtually nothing in for Appalachia at year-end. As to what the bank, Ron, will look like, there will be some value, but it will certainly be a reduced, even from mid-year, Ron. So, the borrowing base from a MAP (43

[Ronald E. Mills:]

Okay. And then, to get down to the $200 million, obviously you would have to be forecasting some sort of sell down in either Lamprey, Derbio or Rampart; did I hear you correctly?

[David H. Welch:]

That's right. I'd say, there are several things that we're investigating. One is farming out the rig, and there are certain circumstances where we may be able to use our infrastructure, so we don't have a subsidy, so that would be a big help. Second thing is just selling down our interest in a couple of these wells that would be tied back to Pompano and not just Derbio, but Rampart is another oilier prospect, which is only a few miles from the Pompano platform. So those wells could be, if a discovery's made in either of those wells, they could be tied back and put on production fairly quickly. Then the rig – the reason we've been able to farm out the rig, Ron, is that it's a flexible rig. As you know, it's one of the few, if I think there may be two in the Gulf that have the ability to either operate in a moored position or in a dynamic positioning. So when people need the rig, they have a scope of work that requires both, it's much easier and more efficient if they contract a rig that has both of those capabilities. And so that's why we've been successful with the rig farm-outs thus far. So we may be able to do the same with a couple of other folks that we're speaking to and continue to try to get additional farm-outs. But to drill Lamprey, Derbio and Rampart, most likely we're going to want to have a partner.

[Ronald E. Mills:]

Understood. I was trying to get towards, as you – do you have at least one of those at least as a placeholder in your $200 million drilling completion budget? And if so, have you already assumed some success in selling down the interest?

[Kenneth H. Beer:]

Yes. So, in the way our model works, there is a placeholder but it's a synthetic placeholder with a little bit of Lamprey in there and a certain working interest and a little bit of – I mean, Derbio at a certain working interest. And both of them rest versus just stacking the rig. So it's a synthetic placeholder, it's probably the best way to put it.

[Ronald E. Mills:]

And then just to try to get some clarity on the flexibility, particularly around Pompano, you've done a workover, you're drilling a first development well. It sounds like you have at least one more development well that you have to do. And then, at that point, what would the steps be or what would be involved and what would the impact be if you ended up not drilling the third and/or the fourth wells at Pompano?

[Kenneth H. Beer:]

Yeah. We can pretty much just stack the rig in place, on location, on the platform, and take a breather. I mean, it's just very minimal charge for doing that. Actually even the contract provides for us to just hold on to the rig for some number of months. And then we can just monitor both our cash position as well as, quite honestly, the price of oil. So that's probably the biggest single lever. As I said, we have about $85 million projected for the Pompano platform rig, and certainly that is an area that could get pulled back if we elect just to stop after this next project.

[Ronald E. Mills:]

And including the cost of the workover, I don't know how much that was, but that lever seems to be somewhere in that $30 million to $40 million range?

[Kenneth H. Beer:]

Yeah, probably closer to the $30 million, because there's still some things that we'll end up spending some money on, but, yeah, let's call it, roughly $30 million.

[Ronald E. Mills:]

Great. Everything else was answered.

[Kenneth H. Beer:]

Yeah.

[Ronald E. Mills:]

Thanks, Ken.

[Kenneth H. Beer:]

Thank you, Ron.

[Operator:]

Your next question comes from the line of Jeff Robertson with Barclays. Your line is open.

[Jeffrey Woolf Robertson:]

Thanks. Ken, can you talk a little bit more about bonding requirements for the BOEM and if they come back and tell you, you need more bonds, how long does that take and is there a chance that to get the bonds or to get the bonds and could that cause any kind of disruption in either current operations or what you all plan to do?

[Kenneth H. Beer:]

As I indicated, still a bit – it's still a bit unclear because we just don't know, but the steps would be, we'd meet with them. We've actually been very proactive. We've met with them and communicated with them continuously. So I think we've got a fair amount of goodwill going to just this upcoming year. We'll walk through where and how much bonding would be required, and then put forth a plan in place. There have been other operators that have preceded us. There's at least a couple who have been working with BOEM for really – virtually most of 2015 and now into 2016 to try to layout a security plan for them, because it doesn't all have to be bonding, it can be some other forms of security. So we will look to certainly meet with BOEM. We've been in communication with them, but we really don't have anything that says right this moment exactly what our position – or what they see our position to be right now. But we're just trying to be transparent and at least make sure that people recognize during 2016 we'll have to address some bonding issues with BOEM.

[Jeffrey Woolf Robertson:]

And either Ken or Dave, can you all talk about what the market is as you go out and look for partners in some of these prospects like Lamprey? What kind of market it is that have the terms of what you might be able to expect on a promote (50

[David H. Welch:]

Yeah, I would say, the market generally, Jeff, has degenerated where it's tougher to get promotes. If you have a special situation though, like Lamprey could be, I mean, the whole principle of Lamprey really hinges more or less on what we see at Tiaras, because we think – and we're not 100% confident yet, but we think that the Tiaras well and the Lamprey well are the same prospect. They're just at the southern end, we're at the northern end. And so if they do in fact make a discovery, then obviously our well becomes more like an appraisal well rather than an exploration well, and that will open up a lot of potential partners for Lamprey. On the Derbio, Rampart piece, the attractive feature of those is that they are only five miles away from infrastructure that we own that has additional capacity. So they're a little bit unique from a regular type of prospect that if you were just going out to try to sell in a market, but the market is somewhat limited, but there are some people that have money and want to deploy those resources in good projects. And we think that those three are all good, or we hope that Lamprey is good and we think Derbio and Rampart are good prospects. I don't know if that's helpful, Jeff, but...

[Jeffrey Woolf Robertson:]

It does. Thanks.

[Operator:]

And there are no further questions at this time. I turn the call back over to the presenters.

[David H. Welch:]

Okay. Thanks, everyone, for participating in the call. We'll end the call. So long.

[Operator:]

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.