Talos Energy Inc.
Q2 2015 Earnings Call Transcript

Published: 6 Aug 2015

[Operator:]

Good morning. My name is Shawn and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Second Quarter 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. Chairman, President and the CEO, Mr. David Welch, you may begin your conference.

[David H. Welch:]

Okay. Thank you, Shawn, and welcome to our second quarter 2015 conference call. We're joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read the cautionary statement, review the financial performance for the quarter, he will then turn it back over to me to provide some additional color on our execution and an operational update in this low-priced environment. So, Ken, over to you.

[Kenneth H. Beer:]

All right. Thank you, Dave. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and 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. We urge you to read our 2014 Annual Report on Form 10-K and the soon-to-be filed second quarter 10-Q for a discussion of the risks that could cause our actual results to differ materially from those that in any forward-looking statements, we may make today. And 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 measures, our financial measures and the most directly comparable GAAP financial measures. And with that, I will move on to our comments. We'll assume that everyone has seen the press release and the attached financials. Accordingly, I'll look to focus on some of the financial and operational highlights. Our second quarter results showed an adjusted $9 million loss or loss of about $0.17 per share before and after tax non-cash impairment charge of $144 million, which brought the reported loss to $153 million. Our discretionary cash flow for the quarter was about $85 million, or around $1.50 per share, which was above the First Call consensus of about $1.35 per share, driven primarily by greater-than-expected production and lower costs. As was also discussed in last quarter's conference call, the non-cash ceiling test impairment was primarily due to lower oil gas and NGL prices, which are calculated using a rolling 12-month trailing average. If prices continue to stay at the lower level compared to last year, we would be subject to another non-cash ceiling test impairment in the third quarter; again, no impact on cash flow, but a potential reported earnings impact. We also had about $45 million impairment to a potential resource play we tested in Canada over the past couple of years, which did not show enough positive results to continue the effort in Canada. We also recognized an upward working interest adjustment to a number of wells in our Mary field in Appalachia. A few potential partners did not elect to participate in several pads, which had been drilled and we had assumed their participation for accounting purposes. The largest adjustment was tied to leases that are having an ownership change late in 2014 and the new owner did not move forward with an election to participate alerting us in the second quarter. The volumes associated with the previous periods were approximately 18 million cubic feet equivalents per day. So production for the quarter, excluding the previous period adjustment, was about 46,000 barrel equivalents a day, or 274 million cubic feet equivalents per day, which is well above the upper-end of our second quarter guidance of 258 million cubic feet equivalents per day. Volumes for the Cardona #4 and #5 were above plan. The expected third party pipeline downtime affecting the Pompano volumes were minimized by the pipeline operator and our marketing group, shaving about 15 days off the expected downtime; and Appalachia was also above plan, flattish with the first quarter despite no well's been drilled. So a strong production in quarter from our base properties. Including the 18 million cubic feet equivalents in volumes up in Appalachia from the previous quarter's working interest adjustment reported quarterly production came in at 292 million cubic feet equivalents per day. (05

[David H. Welch:]

Okay. Thank you, Ken. We're now preparing for the lower-for-longer scenario, while still believing in the longer-term viability of the exploration and production business. This year, we've cut our capital spend and our lease operating expense each by almost half; we reduced our G&A expenses as well. If the lower-for-longer scenario persists, we'll likely do even more in all categories again next year. The equity issuance in May of last year and sale of our non-core shelf assets last July improved our liquidity such we remain in a relatively good position, ending the quarter with about $142 million of cash on the balance sheet and an undrawn $0.5 billion revolver. Our objective over the short and intermediate term is to conserve cash and position ourselves to maintain liquidity and protect the balance sheet. We've also used this period of low prices to focus our organization almost exclusively on two of the lowest cost non-OPEC oil and gas supply basins. These two areas are oil in the deepwater Gulf of Mexico and gas in the Marcellus and Utica and Appalachia. Strategically, we've recently highly curtailed all current business development activities, including a potential resource play in Canada and have dramatically de-emphasized the deep gas and conventional shelf businesses. We've also temporarily delayed our investment in Appalachia waiting reduced differentials and better transportation terms before returning to development spending there. We do see both of these events on the horizon and are well-positioned in some of the best acreage in Appalachia, where we own stacked Marcellus and Utica rights that have much infrastructure in place. The important discovery we made in the Utica and Appalachia at the end of 2014 should position us for over a decade of low-risk development, investment and growth once the infrastructure catches up and differentials and transportation costs begin to improve. So in the intermediate term, we do expect to get back to work in Appalachia, but we'll hold off until margins improve. Meanwhile we continue to take steps to preserve our acreage with the minimum amount of spending. Most of our reduced capital budget of $450 million is allocated to the deepwater Gulf, where we're focused primarily on development drilling projects that create high returns and positive three-year cash flow. Added to these development projects are a few deepwater exploration wells that we expect will provide us with the next round of development opportunities as well as help to satisfy our rig commitment. We have a two-year contract for the ENSCO 8503 deepwater drilling rig. And one of our top projects over this time period is to manage the rig expenditures to be consistent with the viable capital program. There are three levers at our disposal to do this. The first and best lever to manage capital and retain potential to create value is to find partners with the prospects that are coming up over the next couple of years. We believe we have quality prospects and are optimistic that we'll find partners to get our working interest down to the desired level and we're active in this effort right now. The second lever is to farm out the rig to another operator, decreasing our contractually obligated spending under the two-year commitment. We're actively in the market now, discussing possibilities with other operators. The rig is performing well and we believe this will facilitate our being able to execute this option. The third level is to suspend operations at our convenience for an extended period of time, pay a reduced day rate and also eliminate substantially all of the support spread rate, which is greater than the rig cost itself. The current rig day rate is $341,000 per day. If we decide to suspend operations, we can reduce our overall spread costs by 70%. Obviously, the last lever is not as desirable as either of the first two, but we will do what we have to do to protect our liquidity in the balance sheet. With the ENSCO 8503, we just recently finished its first development well, the Cardona #6, successfully and efficiently. The rig is presently off our payroll, in the shipyard for its five-year inspection and the addition of a mooring system to enable it to work in essentially all deepwater depths. We expect to get the rig back in October. The other two already producing wells – Cardona wells, the #4 and #5, have been holding up very well. They're still currently producing approximately 10,000 barrels of oil equivalent per day. We've already produced about 2 million barrels from these two wells and believe that the ultimate estimated recovery for the whole Cardona development could be closer to 20 million net barrels compared to our proved reserves, which are under 10 million barrel equivalents. So I'm happy to report that the Cardona #6 well was drilled and completed for just over $80 million, which is about $30 million under the AFE cost, making it one of the most efficient wells drilled in the area. There's several reasons for this performance. First, extensive preplanning, including execution of the Drill Well on Paper process, Complete Well on Paper process, and a formal management of change process, which makes sure that everyone knows exactly what they need to do. Secondly, we've conducted extensive recruiting and training to get the best people we can on the rig, supervising and conducting actual day-to-day operations. Thirdly, and very importantly, the contract between Stone and ENSCO provides provisions that incentivize ENSCO's operational efficiency in a way that both enhances safety and reduces Stone's overall cost. ENSCO can earn performance bonuses based upon efficiency and safety, which is good for them and good for us as well. The better the rig performs the fewer days it takes for us to drill and complete our wells. Fewer days means savings for us, not just in rig cost, but also in the ancillary support services, which are often more – even more costly than the rig itself. So the rig and the contract performed just as planned on the Cardona #6, and helped to achieve these savings. So at this point, we're quite happy with the rig performance. If we can maintain this level, it could mean our gaining the equivalent of an additional free deepwater well over the two-year term of the contract. Turning to the next steps for the rig, after leaving the shipyard, we plan to complete the Amethyst well, which is another subsea tie back to Pompano. Once the well is completed, we expect to install the subsea flow-line and umbilical and connect to the Pompano platform to commence production in the first quarter of 2016. Project is proceeding on schedule and on budget at this time. Platform modifications to receive the well for production are essentially complete. What remains is the well completion, the flow-line and umbilical installation and hook-up. This development is an efficient, hopefully, sub-two-year cycle time from the date of discovery project, and the initial production rate from Amethyst well is expected to be in the 20 million to 80 million cubic feet of gas equivalent per day, including 30 barrels of condensate and 50 barrels of NGLs per million cubic feet of gas. We currently own a 100% working interest in Amethyst. Once Amethyst is completed, we'll most likely move over to the Cardona #7 development well to drill, complete and (22

[Operator:]

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

[Jonathan Richard Evans:]

Can you just talk a little bit about your initial thoughts for CapEx spend next year? And then also, as you go into the redetermination, do you think any indication, does the $500 million stay pretty constant, or can you give us any insights?

[Kenneth H. Beer:]

Yeah, Jon. This is Ken. Let me take the second question first. So on the redetermination, very difficult to tell. I think even the banks are in limbo as to exactly what their price deck is. Clearly, back in the spring, they had a low-price deck. So we're not sure what that will look like. As I mentioned in my comments, you might have lower prices. But one of the positives for us will be, we'll have a Cardona #6 online and we expect to have that online. And as you may be aware, from a bank standpoint, as they go through their borrowing base calculation, by far, the most important factor in their determination is who producing. And in this case, having the Cardona #6 on and having the #4 and #5 performing so well certainly will help us, but very difficult for us to estimate what that new number will be, whether it stays at $500 million or not. Shifting to CapEx, as I mentioned in the comment, again, premature to come up with a number. Certainly, directionally, it will be down from the $450 million that we have for this year. But exactly where that number unfolds, we're working through that now. And we'll certainly have a figure for our board to ultimately sign off. Probably, they will see that sometime in the October board meeting.

[Jonathan Richard Evans:]

Okay. And just one more follow-up to that. Is it fair to say that you hope by this time next year that you have the convert taking care of, et cetera, and extent to that maturity, it seems like that's been an overhang on the company and the stock? So I'm just curious.

[David H. Welch:]

Yes. So I think that's fair to say that a year from today, we would hope to have a lot more clarity on exactly what steps we'll take, whether that is with using internal funds, using our credit facility, using a restructuring with the current holders, coming in with a totally new external financing approach, those are all options that are out there. I think it is important that we don't have to make those decisions – that decision right this moment in what clearly is a very difficult environment. But certainly that is one of the key issues that we'll be addressing certainly as we go into 2016.

[Jonathan Richard Evans:]

Great. Thank you for your time.

[David H. Welch:]

Great. Thank you, Jon.

[Operator:]

Your next question comes from the line of Blaise Angelico from IBERIA Capital. Your line is open.

[Blaise Matthew Angelico:]

Hey, good morning, gentlemen.

[David H. Welch:]

Hi.

[Blaise Matthew Angelico:]

Just looking at possible ways to fund additional CapEx over the coming years, what are your thoughts about potentially selling in its entirety or selling down an interest in Pompano and Amberjack? Those are assets that probably don't receive an appropriate valuation from an NAV perspective. Just curious as to how you're thinking about this as an option to realize value, but also bring cash in the door to fund future CapEx?

[David H. Welch:]

I'll ask Ken to give you his thoughts, but basically everything is on the table right now and we're considering any option that might improve the state of the company. So I'm not really keen to go do something right now, but it's not a bad idea to think about it. Ken?

[Kenneth H. Beer:]

Yeah, and, Blaise, I think what you're alluding to is just that the platforms themselves, which certainly, at least in our minds, have some true value that could be separately financed. Certainly, any step we take in that regard might have some impact on whether it's the borrowing base or other issues. But, as Dave pointed out, these are all capital – or financing options that we're going to take a hard – that we have and will continue to take a hard look at.

[Blaise Matthew Angelico:]

Got you. Thanks. And just one quick follow-up on the onshore. Say, prices are steady-state, differentials remain where they are, and you all don't reinvigorate the drilling program, what would the cost to terminate that rig contract be?

[David H. Welch:]

It's in the $18 million range.

[Kenneth H. Beer:]

Yeah, that's over $6 million a year. So for 2016, you're looking at about $6 million.

[Blaise Matthew Angelico:]

Perfect. Got you. Thank you, guys. Appreciate the color.

[Operator:]

Your next question comes from the line of Patrick Rigamer from Seaport Global Securities. Your line is open.

[Patrick Bryan Rigamer:]

Hi. Good morning, guys.

[David H. Welch:]

Hi, Patrick.

[Patrick Bryan Rigamer:]

The press release mentioned that you sold a deepwater block. And I was just curious, any more color on that? And are there more opportunities to do that or – just kind of what was going on there?

[David H. Welch:]

Yeah. This was a lease that a different operator had a discovery right next to that lease. We didn't have plans to move forward. They did want to move forward. So we were able to just monetize the lease at roughly $10 million. So certainly, those are the kinds of hidden assets that we hope to be able to continue to monetize as the opportunity presents itself.

[Patrick Bryan Rigamer:]

Okay. And then, I guess, moving onshore, the Utica well that you drilled was drilled in a different price environment on the service side. I mean, I realize that there's not a lot of activity up there now, but do you have a sense of where development cost, well cost might be today? And is there a certain well cost that would, kind of, make you reconsider the development program up there?

[David H. Welch:]

Let me tackle the latter part of it, and Ken can weigh in on the actual well cost. But we really feel like we need some sort of a structural change there before we would want to get back to drilling. The structural change is really in the price and in the transportation environment. As you know, there's a big differential between Henry Hub and Appalachia right now. There are a lot of pipelines that are being built out of Appalachia that over the next couple of years that differential should be cut in half or even improve better. So that's one factor that we're looking for. The closer we get to 2017, the better – the more pipes are being built, so the lower that differential is likely to be. So that's one thing. The other thing is just that we are starting to now see some of these export LNG things start to add a little demand. And over a cumulative period of time, the demand growth may help lift Henry Hub a little bit as well. So we just feel like it's a good time to take a little bit of a time out. Obviously, with prices coming down across the board for rigs and services, I think we expect that we could drill wells cheaper. But I don't know exactly if we have a current outlook on what a well would be to drill today. Ken, do you know that?

[Kenneth H. Beer:]

No, that's fair. I mean, certainly, those numbers have come down, but, as Dave highlighted, it's really the price – the gas price side that's the bigger driver. And not wanting to add to the oversupply situation in the next three, six, nine months, our thought was, let's go ahead and step back and use this time to prepare for the Utica development program, but not initiate it in the face of, as was highlighted, very unattractive differentials that we do expect to get better. So no reason to rush now, when in 12 months or 18 months we feel like we could see, at least, in our minds, a material change on the differential side.

[David H. Welch:]

And just tactically, we've chosen to put our capital into projects that throw off as much cash as possible over the shortest period of time. And so that's another reason that we've really tilted everything to the deepwater right now. We do have developments to do. And these developments are low-risk. They provide a high return and they also provide immediate cash.

[Kenneth H. Beer:]

Yeah, and really to that point, Patrick, as Dave pointed out, the Gulf of Mexico production is very high-margin, whereas right now the Appalachian production, they've done a very good job of keeping production pretty flat with no extra wells. But the margin there, because of the differential and because particularly in the Marcellus, the low prices that you're experiencing out of the liquids side, it just seems like push capital to where we're getting a high-margin on our production, just makes a lot more sense. And so that's why we've just diverted capital to those projects.

[Patrick Bryan Rigamer:]

Okay. Appreciate the color. And then just quickly on the model, gas and NGL, as a percent of total production, were up a little bit this quarter. I'm assuming that's just because of the prior-period true-up; and going forward, kind of, return to what it was like over the prior quarters?

[David H. Welch:]

Yeah. That's a fair observation. And, in fact, as you get into the fourth quarter with Cardona #6 coming on, that – I think you'll see even more of a waiting towards oil. So not only do you have, kind of, the catch-up behind you in the second quarter, but by the fourth quarter, I expect that number to be up higher.

[Patrick Bryan Rigamer:]

Okay. Great. Thanks.

[David H. Welch:]

Thanks, Patrick.

[Operator:]

There are no further questions at this this time. Mr. Welch, I turn the call back to you.

[David H. Welch:]

Okay. Thanks, everyone, for joining the call. And we appreciate you being here, so long.

[Kenneth H. Beer:]

Thank you.

[Operator:]

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