Talos Energy Inc. (TALO) Q4 2018 Earnings Report, Transcript and Summary

Good morning, and welcome to the Talos Energy Fourth Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Sergio Maiworm, Investor Relations. Please go ahead sir.

Thank you, operator. Good morning, everyone and welcome to our year-end 2018 earnings conference call. Joining me here today to discuss our results are Tim Duncan, President and Chief Executive Officer; and Michael Harding, Executive Vice President and Chief Financial Officer. Before we get started, I would like to take this opportunity to remind you that our remarks today will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements. Factors that could cause these results to differ materially are set forth in yesterday's press release, on Form 10-Q for the quarter ended September 30, 2018 filed with the SEC on November 5, 2018 and on Form 10-K for the quarter ended 2018 which we filed with the SEC yesterday. Any forward-looking statements that we make on this call are based on assumptions as of today and we undertake no obligation to update these statements as a result of new information or future events. During this call, we may present both GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday's press release, which was filed with the SEC and which is also available on our website at talosenergy.com. And now, I would like to turn the call over to Tim.

Thanks, Sergio and thank you everyone for joining our call. It's been an extremely busy year for us as we transition from a private to a public company in 2018, after our reverse merger with Stone Energy. We've seen the benefits of the merger immediately coming in the high side of our production guidance and generating significant positive free cash flow on a pro forma basis in our first year as a public company. We increased our proved to develop reserve base by 20% in our year-end 2018 proved reserve report compared to the pro forma year-end 2017 by converting several key subsea projects into proved developed that will bolster the business in 2019 and beyond. We're off to a great start in our appraisal work of our Zama Discovery in offshore Mexico as well. As a reminder, we continue to show in our earnings release two sets of values. On a full year 2018 basis, you will see an as reported values and pro forma values. The as reported values include the legacy Talos assets for the entire year and then specifically the Stone assets from May forward including the Ram Powell asset we purchased after the announcement of the merger, but just prior to the closing of the merger. However, the more useful measure of the assets in our view is the pro forma view of the company which looks at the performance of Talos and Stone from the beginning of the year and then Ram Powell after its closing in May. The good news is this is the last time, I'll have to make that statement and the third and fourth quarter results are inclusive of all the combined assets of both companies. The 2018 annual guidance that we provided upon closing the Stone transaction was done on a pro forma basis. So for example our annual net production guidance on a pro forma basis was 49,000 to 53,000 barrels equivalent per day, while our actual production for the year was 52.4 thousand barrels equivalent per day which was 77% oil liquid. Similar to what I mentioned on our last call, I would again encourage you to visit several of the presentations on our website. The latest detailed deck posted in the fourth quarter provides a deeper dive into our strategy, our drilling inventory, and how we built the company focused on generating positive free cash flow and creating shareholder value through a disciplined approach to capital allocation. The model is simple. We have a deep understanding of our basins, the U.S. Gulf of Mexico and offshore Mexico both of which are prolific geological basins, the respond to seismic reprocessing to help reduce risk, and our areas where our teams excel operationally. The U.S. Gulf of Mexico benefits from ample infrastructure and premium pricing and the current market environment allows us to engage in a combination of low-entry M&A and an infrastructure-led exploration and exploitation with conventional offshore wells that have lower initial declined making bearable projects onshore. Offshore Mexico allows us to access an emerging basin with a significant resource base in water depths that allow us for low breakevens and hence a quick turnaround to cash flow. We think the combination of assets in these two countries will help us both grow at a measured pace in the U.S. Gulf of Mexico but then more materially in a low-cost structure when our Mexico volumes come online. I'm going to run through the high-level results starting by summarizing full year 2018 on a pro forma basis and then the fourth quarter contribution to this year-end values. I'll also highlight a couple of the corporate level results before taking a deeper dive into our core areas. The year improved reserves for 2018 were 151.7 million barrels equivalent with a pretax PV-10 of $3.9 billion using SEC pricing which includes flat prices of $65.56 a barrel and on WTI and $3.10 in Mcf prior to adjustments related to quality transportation deductions based on differentials. Reserved replacement was just over 100% compared to year end 2017 pro forma reserves. Because of P&A requirements related to the merger were higher in 2018 than what we would expect going forward, we focused on a series of lowest projects that resulted in our proved developed results increasing 20% in our year end 2018 reserves compared to the pro forma year end 2017 reserves. The year end 2018 proved developed reserves were 115.5 million barrels equivalent with the pretax PV-10 of $3.19 billion which does not include our recent Gunflint transaction in January 2019, our recent success in the Boris 3 deepwater well and our Phoenix Complex which was still booked as a part of year end. Also keep in mind, these volumes do not include any value for our large Zama Discovery which is currently booked as a contingent resource. Full year production was 52.4 thousand barrels of equivalent per day while fourth quarter production was 53.4 thousand barrels equivalent per day which was approximately 73% oil and 79% liquids in the fourth quarter. Full year revenue of just over $1 billion with fourth quarter revenues of $259 million. In the fourth quarter our realized oil price was $63.04 per barrel keeping in mind that's inclusive of transportation deductions so a good $4 per barrel above the average realized pricing above the average WTI pricing in the period. Our net income for the full year was $275 million which translates to an earnings per share of $5.96. Adjusted EBITDA for the year was $585 million in our capital program inclusive of P&A was $452 million. So, clearly we're generating positive free cash flow even if you account for our debt maintenance. Liquidity position at year end was $460.3 million excluding the borrowing base increase in the fourth quarter. As we communicated before, in November of 2018, the company's borrowing base was increased 42% to $850 million, however, at the time, we elected to maintain our commitments at $600 million, but we had access to that additional $250 million of capacity. We continue to strengthen our balance sheet which is evidenced by our net debt to annualized EBITDA at one times at year end. And to finalize this section I just want to remind everybody that we have already posted our guidance -- our 2019 guidance back in January where we established our expectations that we can modestly grow production year-over-year and continue to generate free cash flow in the $55 WTI price environment. Let's walk though some details across our four core areas. In the Green Canyon area, which includes the Tornado field and the broader Phoenix Complex, has been an area where we've been quite busy in recent months. Production in the fourth quarter was 17.9 thousand barrels equivalent a day net to our interest. And our Phoenix Complex which includes our Tornado subsea wells, we successfully completed our mandatory drydock for our hosting floating production vessel, the HP-1. We are currently undergoing sea trials and expect to bring production back online within the coming days. Therefore the total shut-in period in the Phoenix area should be approximately 56 days which is within our guided 45 to 60 days. As painful as it is to defer the production from this complex, it disturbs the long-term health of that production facility and we're going to need it. Both the wells in our recent Phoenix drilling campaign were successful. Both will start completion operations in the coming days and will be hooked up to the HP-1 early in the second quarter. We expect that Tornado 3 well to deliver initial production rate between 10,000 and 15,000 barrels equivalent a day gross which will be 5,000 to 7,500 barrels equivalent a day net as we own 65% with Cosmos owing the other 35%. Our Boris 3 wells should deliver between 3,000 and 5,000 barrels equivalent a day gross which is 2.8 thousand to 4.6 thousand barrels equivalent a day net to our 100% working interest. Both subsea tiebacks have very quick turnarounds by utilizing our infrastructure in place. Also in the third quarter, we announced our Green Canyon 18 transaction from Whistler Energy. The Green Canyon 18 field was producing approximately 1.9 thousand barrels equivalent a day gross at that time and 1.5 thousand barrels equivalent a day net to our 100% interest. So low entry transaction where our $14.5 million acquisition cost translates to just a little over 9,000 of flowing barrel. But more interestingly, the Green Canyon 18 facility has 30,000 barrels a day of oil capacity, so it's largely underutilized. While we work to develop a drilling program to revitalize assets itself, which has produced over 100 million barrels equivalent to-date, we quickly pulled together multiple business development opportunities with our original seismic that we can tie back to this facility, where the fixed cost are paid for. Of those, we've entered into a participation agreement with EnVen to drill the Bulleit prospect. We'll have an initial working interest of 57%, we'll be the operator. Operations will begin late in second quarter of 2019, utilizing the rig we have working for us in the Phoenix Complex. Bulleit is 10 miles away from the Green Canyon 18 field and the prospect is set up by amplitude-supported Pliocene objective similar to the production in Green Canyon 18. If drilling is successful, Bulleit will be a subsea tiebacks to Green Canyon 18, utilizing part of the unused capacity on the platform. We also entered into an agreement to purchase Exxon's Antrim Discovery, 30 miles southwest of the Green Canyon 18 field. Antrim found subsalt the from a Miocene reservoir in Green Canyon Block 364. We will appraise the discovery with a new well, possibly as early as 2020 and if successful, those volumes can be tied back to the Green Canyon 18 field. To quickly pull these opportunities together within months of closing a bolt-on transaction is a great representation of how we want to execute our business model. Finally, we've entered into a participation agreement to drill the Orlov subsea project with Fieldwood where we'll have a 30% non-op interest. This prospect is very similar to our recently success in – recent success in the Boris field in the Phoenix complex and the project that we’ve had interest in for some time. If that project be successful, it will be a subsea tieback to Fieldwood's Bullwinkle facility for a short turnaround first oil. The Mississippi Canyon core area includes the Pompano, Amberjack and Ram Powell field and has a net total net production of 19.3 thousand barrels equivalent a day in the fourth quarter, net to our interest, which was impacted by a shut in production related to hurricane Michael in the fourth quarter. We're excited about the foundation these assets represent for the future. In 2018, we had a successful subsea well come online in the Pompano field called Mt. Providence, which continues to outperform and was one of the larger positive revisions for us this year. Shortly after closing our Ram Powell transaction, LLOG Exploration announced they will develop their Stonefly project as a subsea tiebacks our Ram Powell facility, therefore, paying Talos a production handling tariff. These types of deals represent a balanced approach to acquiring mature assets in deepwater, not only developing new drilling opportunities within that required resource base, but also utilizing these assets as business development vehicles. We also announced in January, we closed a small bolt-on transaction by buying a 9.6% non-operated interest in the Gunflint field from Samson Offshore. Transaction costs totaled $29.6 million for 2.2 million barrels equivalent of proved reserves, 80% of those reserves were proved developed and the transaction represents $13.45 of the BOE on a 1P basis and the asset averaged between 1.5 thousand to 1.8 thousand barrels equivalent a day net in the months leading up to closing. We believe there are potential several drilling locations within the asset and the surrounding areas that will provide upside to the transaction. Our shallow waters and other core area accounts for both our legacy shallow water assets and some small deepwater assets, both operated and non-operated. This core area accounted for 16.1 thousand barrels equivalent a day of net production in the fourth quarter. As we discussed in previous calls, we like to keep one rig running continuously on our shallow water acreage set and we'll continue to do so throughout 2019. This allows us to add quick production and manage the long-term profitability of these assets, which helps us manage our P&A spending as well. We brought on two new wells late in the fourth quarter and early first quarter of 2019 in our Main Pass 72 field, which together totaled approximately 2,000 barrels equivalent a day gross and 1.6 thousand barrels equivalent a day net. The Ensco 75 rig is currently working in our Ewing Banks 306 field where drilling success last year allowed this asset to reach production levels it hadn't seen in 15 years. We will drill three new wells in this field in 2019, which includes some lower risk field pays and then an offset to our deeper Miocene discovery that we announced last year, all off of the same production platform for our quick turnaround. In offshore Mexico, after absorbing the data from our discovery well in Zama, which we guided between 400 million and 800 million barrels of gross recoverable contingent resource, it was time to get back to operations in the fourth quarter and drill these three appraisal penetrations. We announced recently that the first appraisal location called the Zama-2 well penetrated the oil water contact slightly deeper than expected and consistent with our geological and geophysical models. The first leg of our appraisal was completed safely and efficiently 28 days ahead of schedule and 25% under the AFE as we continue to learn more about it and become more comfortable with the drilling environment in offshore Mexico. We're currently active in our second appraisal of the Zama-2 sidetrack, which is a straight hole, north of the original Zama-1 location. We've recently completed coring operations there and we expect to start our flow testing in the coming weeks. We will announce more details when those operations are complete. We will then move to the Zama-3 location, which is south to the first discovery well where we will repeat those coring operations. The appraisal program should be completed by midyear, at which point the resource range will be narrowed when we get closer to FID and book these reserves and to prove them probable. And again as a reminder it's currently booked as a contingent resource. Concurrent with these activities, we'll continue to work diligently on our pre-FEED efforts with the goal of pushing this project toward FID in the first half of 2020, which could allow us to have production online in the second half of 2022. Again that -- what makes this economics of this project so unique is the size of this resource in shallow water depths. We have around 550 feet of water here, which allows for fixed structures, dry trees and maximum flexibility in fully developing the asset. In our last call, we discussed the historic cross-assignment trade in our Block 2 acreage, the first of its kind in offshore Mexico where we traded out of 25% of our participating interest in Block 2 for a 25% participating interest in Block 31 directly to the south, giving us a 25% participating interest in both blocks, which are located in very shallow waters. Hokchi Energy, a subsidiary of Pan American Energy will be the operator of both blocks. This deal allows us to aggregate a larger depth of drilling opportunities into one development plan facilitating operational synergies and quicker production, which is consistent with our goals and those of Mexico in the country's energy reform. Four wells will be drilled in 2019 in this area, two on each block. Block 2 is anchored by Talos's Acan prospect while Block 31 is anchored by Pan American's Olmeca project. The Olmeca project is aided by pay found in the previous Pemex well the Xaxamani-1 well. Both projects are amplitude supported and aided by Talos' proprietary seismic reprocessing in the area, which were contributing to the partnership. By pulling this inventory together and specifically focusing on Olmeca and Block 31 as part of this initial drilling campaign, our hope is to reach FID on a development plan for this area in 2020 and this project to complement our efforts in Block 7, allowing us to put together an impactful business in offshore Mexico in the near future. In my closing remarks, I'm extremely proud of our team's efforts in 2018. We asked a lot of our professionals. We needed to integrate two companies. We need to balance a series of growth projects that will further stabilize the business while also executing some residual one-time maintenance and P&A projects that lingered from the Stone bankruptcy days. We also wanted to quickly execute some bolt-on business development opportunities and show our new public shareholders that we can reliably generate positive free cash flow, which we certainly did this year and we can -- we expect to continue to do so in the current commodity price environment. We're excited about where we go from here and you should expect us to continue to deliver these results. I'll hand it over to Mike Harding to walk through additional full year 2018 and fourth quarter results.

Thank you, Tim. As Tim referenced Talos continues to be focused on generating positive free cash flow. For the full year of 2018, our pro forma adjusted EBITDA was $585 million with a $452 million capital program. So it's clear we generated positive free cash flow in 2018. And as we stated in our 2019 guidance earlier this year, we also expect to be free cash flow positive in 2019 and beyond. Another focus for Talos continues to be to maintain a strong balance sheet, credit metrics and leverage metrics. Based on the annualized results of the second half of 2018, which is the period stated in our credit facility agreement net debt to annualized adjusted EBITDA was one times and we have no debt maturities until 2022. At year-end our liquidity was $460 million, which represents a 10% increase from the third quarter of this year. Our liquidity consists of $140 million of unrestricted cash and $320 million available under our credit facility. It's worth noting, that this liquidity position excludes the $250 million increase in our borrowing base in November. Before I go into the fourth quarter and full year results, I'll say that the company takes all the boxes we think investors are currently looking for. We generated positive free cash flow have an oil weighted portfolio close to 80% liquid with premium pricing, low leverage with no near-term maturities and we currently trade at a meaningful discount to PV-10 of our PDP reserves. This reflects what I believe to be a very compelling investment case. Furthermore, we have a globally recognized generational discovery in our Zama asset in Mexico which is not yet priced into our stock. Now I'll turn to the results for the fourth quarter and full year for 2018. For production, Talos averaged daily production in the fourth quarter of 53.4 thousand barrels of oil equivalent per day or 4.9 million barrels of oil equivalent. 73% of which was oil. Compared to the third quarter, production was down slightly, mainly due to the shut-in resulting from Hurricane Michael and other small third-party downtime instances. For the full year on a pro forma basis, our daily production was 52.4 thousand barrels of oil equivalent per day which is at the higher end of our guidance and which ranged to 49000 to 53000 barrels of oil equivalent per day. The 2018 production also represents an approximate increase of 5% from what Stone and Talos produced individually in 2017. On the commodity price side, despite the oil price decline in the fourth quarter, our basis differential has widened significantly in the same time period. Our average realized crude oil price after transportation and quality deducts was $53.04 per barrel or approximately $4 per barrel higher than the average WTI Cushing spot price. The demand for oil continues to be robust which continues to provide favorable basis differentials into 2019. On the revenue side, fourth quarter revenues were $258.7 million and for the full year on a pro forma basis, they were just over $1 billion. While oil continues to represent approximately 73% of our production, it accounts for around 87% of our overall revenues. As we continue to allocate capital to our organic drilling project, we expect our oil exposure to continue to grow. As we look at direct lease operating expenses, these expenses were $49.7 million for the fourth quarter. And for the full year on a pro forma basis, our LOE was $177.9 million or $9.28 per barrel of oil equivalent. General and administrative expenses were $23.1 million for the quarter which is inclusive of approximately $4.9 million of transaction cost, mainly related to the Stone Combination and the Whistler acquisition. It is also inclusive of non-cash equity-based compensation. As reported, G&A is $4.70 per barrel of oil equivalent, but $3.54 per barrel of oil equivalent when transaction costs and non-cash equity-based compensation are normalized. And for the full year on a pro forma basis, our G&A for barrel of oil equivalent is $3.35. Other operating expenses include work-over and maintenance expenses which were $15.3 million for the quarter. These costs include approximately $7.5 million of nonrecurring expenses, primarily related to structural maintenance and include the preparation for the HP-1 dry-dock. Our net income for the fourth quarter was $306.3 million or $5.66 per share. For the full year on a pro forma basis, Talos generated a net income of $275 million or $5.96 per share. Excluding unrealized, commodity gains and other items, our fourth quarter adjusted net income was $49.3 million or $0.91 per share. Talos' pro forma full year adjusted net income was $173.8 million or $3.77 per share. Adjusted EBITDA for the fourth quarter was $158.8 million whereas adjusted EBITDA for the full year on a pro forma basis was $585 million. Capital expenditures for the fourth quarter were $142.2 million, inclusive of plugging and abandonment and the full year pro forma CapEx was $452 million. As part of the Stone merger as we mentioned, we were required to spend more capital and P&A than we normally would have. As stated in our 2019 guidance, we expect to cut this P&A spending in 2019 by approximately half. This concludes the prepared remarks for the quarter, financial data and the year. And I’ll now turn the call back over to Tim.

Thanks, Mike. Let's turn it back over to the operator and queue up some questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And today's first question comes from John White of ROTH Capital. Please go ahead.

Good morning. Thanks for taking my call.

Good morning, John.

Congratulations on such a very nice year of meaningful accomplishments, everything looks really nice.

Yeah. We appreciate it. It’s some busy first year trying to integrate and still execute and we’re happy for – happy with the result.

Yeah, you had a lot going on. Mike two questions mainly on -- trying to get some more comments. Do you want to talk about the timing of Zama-3?

I think it's all fairly well laid out in the guidance. We've got -- we are in the middle of coring operation. I think we've mentioned we've successfully completed that. That's -- those are tricky operations. Those are things we don't always do in the U.S. Gulf of Mexico side, but with this type of discovery that's something we wanted to do here. Then we get into the drill stem test. We had several spots we want to go try to perforate and flow back to the surface and look at deliverability. We may add one. So there's some things you might have to adjust on the fly. And all that needs to be completed and then we go down to the Zama-3 location, which again is south of the first location. So there's a lot that goes on there. And we think the most appropriate thing to do is complete each operation, and then let you guys know how things are going. I would suspect again everything done by midyear is still a very reasonable goal. And so I think you're going to see a couple of announcements between now and then.

Appreciate that your -- you and your team are showing your experience by filing up the geologic information on the Zama block. A follow-up on, again a timing question the Exxon Green Canyon 364. Any timing, comments on that?

Not just yet. I think that lease has some life left in it. It's got some term left in it. I think it's 2023. I've got a couple of colleagues in here 2025 okay. So it has some time. We like it. We like the fact that fits right into the strategy. It could be into the program in 2020. It could be in 2021. I think as we get later in the year and we look at the results from this year, we look at the type of the portfolio we want next year we'll make that decision. I mean, I think one thing you should think about is we don't try to take on longer rig commitments than we really need to. We've been layering on some hedges. I think that's summarized in the K or certainly summarized in the release. We've been layering on some hedges for 2020. As we layer those hedges on we think it's appropriate to start thinking about our rig program for 2020, and it certainly could be a part of that program. It could be in 2021. But I think the broader message for us as we did a transaction in Green Canyon 18 that it wasn't a lot of barrels and it wasn't a lot of money. And you can stand back from that because that's really strategic, it's that really interesting. Keep in mind that asset in Green Canyon 18 is 15 miles north of our Phoenix field. And just that by itself is interesting to us. That means we have a good foundation of the geological opportunities we think are around that area. And we see this as an excellent opportunity to not only develop something that may not be as material to Exxon and that's understandable, but could be material to us. But I think we just have to sort out the capital program for next year, what can come online quickly what we'll learn and have a little more patience on and then work through that. But as we develop that we'll come back and be in touch.

I appreciate that extra detail. I’ll follow-up with Sergio later today, and look forward to seeing you guys next week.

Okay. Thanks so much.

And ladies and gentlemen our next question comes from John Aschenbeck of Seaport Global. Please go ahead.

Good morning, Tim. And thanks for taking my questions.

Sure, John.

So for my first one, I just was hoping to get more color on Antrim. A lot of my questions you actually just addressed. But separately was curious, how significant is the future cash bonus payment to ExxonMobil? And then also what is the override?

Yes. So we're not -- I don't know if you've done a lot of deals with Exxon. You can expect there's a confidentiality provision on some of this stuff. But I would just submit that it was material I will okay it. And so it's not a material amount. It's a reasonable amount. There's an earnout structure and that's probably where I'll leave it. But these are deals that obviously we're sensitive to a couple of things that I would say is the foundation. We're sensitive to the strategy we've created the expectations we create. And I think we like to cut deals that are a win-win for both parties. I think Exxon had something that wasn't as material as they had hoped for. They're a company that would typically like to build out their infrastructure and we're a company that had that infrastructure. And so it made for the right opportunity to put this deal together. But obviously, if there was huge payments involved then you would heard about a lot sooner. So I think it's a reasonable transaction from both sides. And I think the rest of your details maybe a hit in John's response -- in my response to John.

Yes, yes. You did, Tim. And maybe I'll give you the opportunity to kind of expand upon them a little bit. Was just curious if you could share any other information that has you excited about Antrim that you hadn't addressed it already?

Well, I think a couple of things. Anytime you can calibrate sub-salt pay that's interesting for our geological team for the broader area of what we do. And then, I think anytime that you can stick with what you're trying to accomplish in these transactions. Again, a lot of this is set up by doing a low-entry transaction in Green Canyon 18. I think we spent $14.5 million of net cash for I think 1,500 barrels a day net to our interest. So 110,000 in flowing barrel we established something. We're working very hard in that Green Canyon 18 transaction to put a drilling program together for that resource base. But while we're doing that we kind of expand that radius and look for other opportunities. We identified the Antrim opportunity. We think it needs another appraisal well to commit ourselves to pulling all that back up to Green Canyon 18. And so we're excited about what that does. Now that's a project that unlike Phoenix is not going to turn around and you're going drill the appraisal well and it's going to produce in six months. It can take 18 months or so to pull all that online. So we have to think about our capital program as we look into 2020 on what's the balance between things that can turn into production quickly and what are the balance between things that have -- might have more material production, but take a little more time. So we're going to spend some time digesting that. But the first step is pulling that inventory together around the things that we purchased in a low-entry way and that's exactly what Antrim represents.

Okay. Great. That's really helpful. And then for my follow-up just regarding the two new deepwater projects that you're going to drill later this year. Just -- I guess first of all, how would you characterize the risk profile of those? And then more of a point of clarification was wondering if that drilling capital was included in the prior 2019 budget that you provided? Thanks.

Yes. Well let's start with the latter and that's a good question. And we probably should have been a little clear on that in the earnings release. Those are -- I mean, if you go look at our guidance, we talked about four subsea projects. We were in some negotiations and conversations with both parties and these are firms that we've worked with in the past. They're good well run companies. And so we were talking about those. We want to get those into a committed participation agreement which we've done. So yes, the answer is they were in our guidance. I would characterize those as pays that have analogs. I mean, so these are prospects that have analogs paid sections somewhere in our core area and that provides us comfort. And sometimes you can operate those, which is in the case of Bulleit. And sometimes the operator is going to maintain that status which is appropriate in the case of Fieldwood. But what sets this up is the access to infrastructure the -- that's in place that allows us to drill something that has some risk, but a very good-looking analogue that we might be familiar with. And so for example in each of these instances, the analog is something we own. And the EnVen prospect Bulleit that -- the analog is in fact paid to Green Canyon 18. And then in the Fieldwood prospect Orlov, the analog is actually on our Boris area. So similar analog, we feel good about the direct hydrocarbon indication response out of geophysics. We've just got to go drill these wells and find out. And then because of the infrastructure they can both come online fairly quickly for a subsea tieback, which, again, I think fits right into part of our strategy. And when you're appraising something like Zama, that's going to little more time, part of your capital has to be allocated on things that have what I was considering lower risk profile.

Okay, got it. That's it from me. Thanks Tim.

Thanks.

And today's next question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.

Good morning guys.

Hey, Jeff. How are you?

Good. Thanks. Just picking on Bulleit and Orlov here. Was curious if -- are there any promote structure or anything that you guys can disclose? Are those in and heads-up basis? And then I guess just one you guys kind of take a step back and look at the broader opportunity set in the Gulf? Tim can you just kind of talk about are there more deals like this I guess to be done, or would you have an interest in them given kind of how you talked about balancing capital and risk profile and things like that?

Yes. So, again, there's confidentiality provisions in these participation agreements that I think especially right now. I think what we wanted to do is make sure that prevents me to really go into the details. Look I think we do try to avoid some upfront promotes, but we've got to put a structure together that works for both sides, so sometimes you have some success-based earnouts and fees in that regard. But the goal here is I think for both sides when we do these deals both us whether who the seller is and us as a buyer and where we can fit in our operations to try to do so. It's appropriate for the seller to maintain operations, that's great too. I think we're all accomplishing the same goal, which is how do we great optionality in our inventory and utilize the infrastructure that we have. And that's what this is all about. And I think as I've mentioned in conferences and on the road, we are looking for a full menu of business development options within the areas that we have seismic and that we feel like we can add some value. And particularly if we can use infrastructure and that could be a stranded discovery, that's why we did the Antrim transactions. But it's also why we show up at lease deals and then we work on these business development activities as well. It's all part of how do we figure out how to aggregate the right opportunity set for what we're trying to do with our capital program that lends itself to maintaining that free cash flow position we've created. And these types of deals help complement our inventory. We might buy something like the Green Canyon 18 that we may need a year, year and a half to put together that drilling program. What can we do to complement our transaction in the near-term? Bulleit is an example something that could complement the transaction. Is that helpful?

Yes. No, that's perfect. I appreciate that. And for my follow-up down on the Mexico assets. Pemex obviously been in the news quite a bit with their finances and whatnot and I know we're expecting them to drill a well adjacent to Zama here that was going to kind of facilitate the unitization discussions. Just kind of wondering relative to the last time you guys had a call, give a sense for kind of continuing to impact unitization discussions, or you guys still feel pretty good about having those in the back half of the year and ultimately FID in this in 2020?

Yes. Look that is probably the variable that moves around the most Jeff. I think that's fair. And in the good news is what we did with our pre-unitization agreement is make sure we didn’t get disconnected technically with each other. And so we made that agreement that we will share the results of how are you doing and that we would stay in touch with one another and all that is in an effort to make sure we don't have delays when we get into the unitization discussions. And so they are a little bit delayed in their well. I think it's a focus for them. And we are in communication with the team through that Pre-Unitization Agreement which spelled out having a work team that shares the data. And so I do think we're trying to do everything we can to stay on pace with respect to our knowledge transfer and our communication, we would like to see them drill that well. Is it causing a large delay at this point? Maybe not. Is it possibly the variable that moves around a little bit? It could be. But I think, again, I don't want to underscore the effort and what the Pre-Unitization Agreement does for us, it allows us to make sure we're not waiting to build a depth of understanding which is a large part of what holds up unitization discussions. But again they have a little bit of a delay, let's hope they can get back on track.

Okay. Understood. Appreciate the comments and nice quarter guys.

Thanks. Appreciate it.

And today's next question comes from Shahin Amini of Pareto Securities. Please go ahead.

Thank you. Good morning gentlemen and congratulations on a solid quarter. I have two questions. You had to unplanned downtimes last year, HP-1 disconnected unexpectedly. And Pompano you had a compressor issue. I expect you've spend some time looking at it technically. Could you sort of give markets and investors confidence at these were very much a one-off, or do you feel that you need to implement new procedures and processes? Is there anything that can be done to mitigate this in the future? And the second question on Zama. And on the back of the appraisal data you've gathered to date, can you provide any more color on the reservoir quality and how the second well compares to the first well? Thank you.

Yeah. So let's -- I'll actually go in that order. Thanks for both those questions, by the way. First, we'll talk about the downtime last year in the Helix Producer 1. Look, I would say generally absent of those events and those events were always difficult and I do think Helix does a wonderful job as a steward and the operator of the vessels, so just you understand how that works. They obviously operate the vessel on the vessel. Their job is try to keep that vessel station to dynamically position vessel. And then we manage all the production facilities and the designated outrigger of the block. When you get -- we have this drydock probably every two and a half years. You've got, I think, eight or nine thrusters around this vessel. And those thrusters have been over time get challenged. That's exactly why we go into drydock. We're going to be coming out of drydock with brand-new thrusters. And so, there's some -- typically there's some challenges as we get into that period going up to drydock. And we saw a couple of those challenges. And then there's -- I think updating on software systems and things like that. I would submit, and I don't have it, that our uptime in the absence of those events is probably somewhere around 95%. It's very, very high. And so, I think generally they do a good job there. It's difficult to see kind of two in a year. It's not a huge surprise when you're doing and going into the drydock. And so, we're going to welcome the ship back with a fresh refurbishing of the thrusters and some others updated software systems and things like that. But it's something they have to manage. But I want to underscore I think -- I really do think Helix does a heck of a job. Now the Pompano compressor outage, that's -- it's -- look we have mature assets out there. It's tricky. I think we have a maintenance team runs around and works very, very hard, trying to keep our production up. You're going to have those from time to time. We always revisit the action items. But again, I actually think in the absence of that that field has pretty good uptime. Downtime, with respect to offshore operations, is probably one of the toughest variables to model through. We try to do our best to model this through as well. But again, it's just something that we have to stay focused on. The question on Zama, I think it was a rock property question. I think what we ...

Reservoir quality, yes.

Yeah, reservoir quality. I think we disclosed in the down-dip location are several things. One little more sand there than we thought which is nice, because you want more sand when you start going down-dip and think about what the aquifer might look like and the energy support that aquifer could provide. And I think we had net to grosses within the expectation that we have here, keeping in mind that's a very large kind of column of oil in the pay section and then column of sand generally. So, the rock properties are -- and the other thing I think we're talking about is the rock properties are consistent to what we see in the Upper Miocene section in the U.S. Gulf of Mexico and that's important. Typically a very good rock property is in the Upper Miocene in the U.S. Gulf of Mexico. And those rock properties respond to geophysics and some of the tools we use geophysically. So I don't know if we disclosed specifically the rock properties. But I think as a general matter for Miocene rock in the U.S. Gulf of Mexico, as we look like here, have porosities between 23% and 26% and perms into hundreds of millidarcies. And so, I think you've got a complex that we can expect that deliverability from. What we're going to do on our drilling stem test is really try to kind of hone in on what to expect on that deliverability over a different perforated interval. And so we can think about how to fully develop this asset. And we'll disclose the expectations going forward of deliverability once we complete those tests. But we haven't seen anything that's discouraging about the rock properties across our appraisals to date. Well, I think all we disclosed on Number 2 is the fact that we've kind of maintained our coring operations. But again, no surprises with respect to rock properties.

That’s very helpful. Thank you.

Okay. Thanks for the question.

And our next question today comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.

Yes. Thank you. The two new partnerships with Fieldwood. And then, do you have a feel for the reserve potential on those projects?

Obviously, we do Marshall. But I'd probably have a lawyer that reminds me I'm on a call and probably shouldn't submit that right here on this call. But look they're -- they are -- they're the type of prospects that kind of what we would say look similar to things we're drilling in the other parts of our portfolio. The reason we like these is the time to first production. But we didn't disclose reserves in this particular earnings release. I think as we get closer to drilling those wells we might be able to kind of put some guidance out here. But right now we're probably not disclosing that.

Okay. Fair enough. And you didn't have a lot of drill bit reserved ads in 2018, but saw an impressive amount of PUD conversions. Can you talk about the nature of your 2019 drilling compared to 2018 in terms of PUD conversion potential versus new reserves?

Yeah. So let's go back to 2018. I mean, I think it's important to note that, we didn't guide that 2018 was going to be a year where we try to go too far outside the reserve report. I think part of the reason there is Stone had some lingering obligations. And when we went into the merger we knew those obligations were there. They also had some unrestricted cash in the combination that can help us work through those P&A obligations. So we knew, they were there, but there were still going to be a larger percentage of our capital program than we would want to have on a year-over-year basis. And so our decision was let's go execute some lower risk PUD conversions that frankly we like them were attractive and that was Mount Providence on their side. It was Tornado 3 and Boris 3 on our side, to help really stabilize the business in 2019. We knew we had a dry dock coming up. And so that was a decision to kind of stay inside the report which we did. And then frankly what that resulted in is a higher waiting of value and PDP which I think you see today. And then they increased broadly in proved developed reserves, which I think helps us from a credit perspective. I know as well and you saw an increase in the borrowing base in the fall. I think part of that is related to the way we allocated capital last year and the first year of the merger. So that puts kind of 2018 behind us. In 2019, you're going to see a little more activity outside the reserve report. I think the combination of lower risk ideas and then of course everything we're doing down in Zama is outside the reserve report. And so we have a – we're highly proved developed now, I think around 75% proved developed, still some things that we'll do inside PUD, but they're probably smaller and shallow water. But in deeper water, most of what we're doing is outside the reserve report. And obviously, Zama is outside the reserve report. And you should think about Zama as something that over time will find its way into the reserve report on a proved basis. And when it does it will be material.

Thank you.

All right. Thanks, Marshal.

And our next question today comes from Richard Tullis of Capital One Securities. Please go ahead.

Hey. Thanks. Good morning. Tim the PV-10 versus the company enterprise value differential is interesting. I know, Mike touched on it a little bit in his comments. Just to clarify the PV-10 for the year-end 2018 PDP reserves it does include the ARO associated with those properties as well?

Yeah. So let's make sure, we kind of understand ARO as a general matter. So, all of our ARO that is associated with those proved reserves is in the proved reserve report. There is always some ARO typically you'll see that in the current ARO and I don't have the K directly in front of me, but I think it's between $60 million and $70 million of current which coincides with what we've guided in our 2019 guidance, because those deals are offline that's why we're plugging them. And so they're not in the reserve report. So there's always a little bit of ARO not in the reserve report, but every – all the P&A associated with the reserve report is absolutely in the reserve report and then in those PV-10 values. Specific to PDP, typically that will encompass all of the P&A in those assets that don't have maybe a PDNP case or a PUD case. Keeping in mind that, again, we're 75% proved developed and so most of our ARO are in those cases. But we put the ARO in that kind of last proved case, again which is oftentimes in the PDP case, but it's all in the report.

Okay. That's helpful, Tim. And have you perhaps internally estimated what the PDP PV-10 would be used in say current pricing? I know you have the $2.5 billion for the SEC pricing?

Yeah. Right. I haven't nor we disclose and I don't want to take – I don't want to miss on the guess here on this call. I would suggest that, it's still might be higher than what we were trading or at least at what we're trading But we can probably run some math and work through that. And as we get out on the road you might slip that into a slide. But we're going to have to work with counsel on that. But I think the broader message is we're at a pretty good spot. By – basically, we were taking projects last year that already have a fixed cost associated with them in the Phoenix in the Pompano area. And we were pushing at new volumes and a fixed cost structure. And when you push those volumes into PDP and by the way take the capital out, which will then get that capital resided in the reserve report last year, they're going to get a pop on the PV-10 aspect of it and I think that's what you saw here. And I think it's going to be to withstand $5, $6 of an oil price drop or $10 on oil drop -- price drop on that PDP layer.

Sure, sure. And I know you outlined in the earnings release some of the larger projects expected online over the next several months. What about the ongoing work-over and recompletion projects? How much additional production could those activities add say per quarter throughout 2019?

We did -- and, again, it's something else we didn't guide and I don't want to guide today. But I will just tell you that, our expectation is typically, we spend probably around 15% of our capital program on those projects. I think there's been years where that can deliver annually 4,000 barrels a day. There's been years where that can deliver annually 2,000 barrels a day. But its goal is to do two things. One, offset our corporate declines generally and then, help us manage the profitability of those assets and which ultimately helps us manage the P&A. So we haven't put out quarter-to-quarter guidance. We can think about -- I think as we move into the year, we can talk about looking back and seeing how that program's gone. It's a little early to kind of address what we're doing in 2019. But our team works very hard on that. I mean, for example, they're working very hard on some of the assets we bought in Ram Powell and Green Canyon 18 in the last year. And so, I think, as we get further into the year, Richard, we might come back and revisit how some of those projects are going, so you have a better sense on how they can affect the model. But I think we've always gotten a pretty good bang for our buck on that asset management program.

Well, good, Tim. That’s all for me. Thanks a bunch and nice quarter.

All right. Thanks for your questions. All right, Richard. Thank you.

And our next question today comes from Subhasish Chandra of Guggenheim. Please go ahead.

Yeah. Good morning, Tim. I was just curious if we could use price-over assumption for typical Zama well in terms of productivity or EUR. Or do we need to wait for the DST?

Yes. We're going to need to wait. I mean, that's exactly why we're doing it. But I think – and you've been out here a while and I think understand and modeled the Gulf of Mexico companies before. I would just -- what I would submit is a couple of things. When you think about the economic model here, being in shallow water is really the gift of the project. It allows us to have physical platforms. It allows us to have dry trees. And then, we'll still sort out as we do the pre-feed, what's the right way to get that -- the oil and gas off of those physical platforms and dry trees. And we're working through that. But the point of all that is, you ultimately will see a development program that has a drilling rig, a platform rig. And I think these wells are going to get quicker and quicker. There's one thing that I mentioned in my remarks and I think I really want you to hone in on, is our team is sorting out how to drill wells out here. And we really think when we get this thing developed, they're going to go quicker and quicker. And look, it doesn't -- you can go get on our website and you can see the log and you can think about that section and perforating that section in 80-foot intervals, in 100-foot intervals, in 120-foot intervals, whatever it requires each time we drill a well. And then, the question is, what going to be deliverable -- deliverability of those intervals. And we know, we have good rock properties. I mean, we're in a pretty good spot, just because it's in, A, I think we're going to have good deliverability results. But really, B, we're in shallow water, dry trees. There's nothing that's going to have a serial number of 001 on this project. I mean, it really is like going back in time in the U.S. Gulf of Mexico. And I think that's what's going to -- that's what makes the economic model exciting. But as we get those results we'll pass them along. But, obviously, a little too early. That's exactly the goal of the appraisal to be able to come back and help you build out those -- for us to provide that guidance and for you to build out those models.

Yes. Terrific. And then, just a question on FID. And so, first half 2020, what is sort of out of your control in order to deliver that timing? For instance, what do we need Pemex to do? You talked some things on unitization, just some color there.

Yes. And that question came up earlier and it is a good question. Obviously, again, we like to see them drill a well here that we know they're working hard on that. I think the good news about what we're trying to do here is, this wasn't one where it's adversarial. It's not something -- we're holding our information closer to the vest and we would expect them to hold their information close to the vest. And I would just kind of reiterate that working with our partners and putting together that Pre-Unitization Agreement was a very important milestone, so that while we had a sense there might be some delays on their side, they have a lot of leases, they have big capital program. But we didn't want to delay what we were doing. So that is a little outside of our control, but I think we're managing that well through the work group that we've set up together through our active communications with our partners and Pemex and the data sharing that the Pre-Unitization Agreement requires. So I put that out there. And then from a development plan perspective, then we would submit a development plan to the federal government. And working on that development plan and working on the unitization are concurrent activities. They don't -- they're not sequential. And then we need to submit that and have that get approved. We've seen those development plans get approved. Hokchi Energy has had one approved. Eni has had one approved. Fieldwood has had one approved. So we've seen the approval of those plans in both administrations, but again not inside our control. So there's a couple of things that aren't as in our control as what we're doing right now. We haven't been delayed. I get questions from time to time and I would almost throw one out there. Do we have delays with the change in administration? We have not had any. And so we anticipate everyone's working on the best interest of the goal which is a cheap production as fast as possible. And can all that come together in what we hope will be the first half of the year 2020? It certainly could. Could some of those things outside of our control create small delay? Again it might as well. That's balanced by the fact that though that we are in shallow water and what we're going to be able under development scheme isn't as complicated as maybe some other water depth, so all of that kind of out there as you think about that distance is the first production.

Yes. So I got you. A lot of ways I guess to mitigate the risk. And just a final follow-up on that. I'm just sort of curious, how much of it is dependent on that the Pemex well. It sounds like you'll do a lot of stuff to go around it, but... A – Tim Duncan: Yes look, if you're asking the question, do I think amplitude work and do we think -- after we have four penetrations, do we need to see it to know what we have? I mean, I think we'll suggest the answer is no. I think that question is, what is the appropriateness of having that well in play when you work on the unitization and is there a workaround. I mean we'll cross those bridges as we get there. And again we have a good work team. We have a lot of confidence in what -- we have a lot of confidence in this discovery is and what it ultimately will provide for the partnership and then provide for the government and what is -- how meaningful it is in the economic reforms. And our focus is getting it on first production. I think when you work on unitizations; you've got different elements of what are the initial equity splits and what are the redeterminations. And we'll just have to work through the timing of the data collection and how all that fits into the unitization discussion. But generally, you like both sides to bring that active data to the table, so that we can develop this in a responsible combined away. But admittedly with four penetrations on our side, you start to get pretty confident on what you have. And so we're just going to have to go through the year and see where Pemex ends up.

Sounds good, Tim. Thanks.

All right. Thanks for the question.

And our next question comes from Gail Nicholson of Stephens. Please go ahead.

Good morning everybody. Thanks for squeezing me in. I'm just looking at your price realization definitely stronger into 4Q. Was that all just driven by Brent and WTI being wider than the previous three quarters, or is there something other factors that are contributing to better realizations in the fourth quarter?

Yes, it's primarily due to the increase in commodity price in general. And then year-over-year quarter-over-quarter our production has continued to hold in. So kind of the combined of that.

Yes. We might have been touch Orlov in the fourth quarter than previous quarters, but it's a -- I think it's right. It's really more the widening of the basis differential. And again there's a -- yes I mean, there's some mitigating factors back there on why there's widening and what the demands of the oil and you've got sanctions in them as well and we certainly don't want to comment on that. But I do think you've seen a little more of that widening in the first quarter. And so how long that stays with us is not something that we would pretend to guide or forecast, but I think it's interesting that we have and we're always happy to have it.

And along those lines of my thought process seeing that widening, is there any thought about kind of that hedge back specifically in order to capture that, or just in general looking at your philosophy on hedging strategy have any of that changed, since you guys have become a public entity?

Actually in general, our hedge policy really hasn't changed. We've always basically hedged to secure our capital projects and what we've got planned for the year. And we usually do that ahead of time. So like I think we've disclosed, we're hedged this year north of $55, which is the pricing that we've used in our guidance. As far as basis differential hedging, we are looking into that. It's a risk that you take when you go down that road. However, I think the risk reward is something that we need to look at closely as we find ourselves consistently in a positive position.

Yes. And then to complement on that as well, again our hedging philosophy is just to beat the underlying plan that helps us maintain the capital program and maintain the free cash flow position we want to have. And so if we can beat that then we're in the market. In terms of basis differential, you also want to make sure you have a liquid market. And I think that it needs to evolve to where you're comfortable that there's a liquid market. But to be sure, if we think of benefits, our kind of our base philosophy is we absolutely look into it.

Okay, great. Thank you.

Thank you.

Thanks, Gail.

And ladies and gentlemen, this concludes the question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.

Thanks operator. And look we appreciate all those questions and thank you for having interest in the firm and the team. We'll reiterate 2018 was transformative, just in the fact that not only moving from our historical private status into the public domain, but really more importantly integrating the companies, integrating the opportunities that -- pulling folks together in the culture that we think we've created at Talos that focuses on shareholder value and generate free cash flow. And we're hyper-focused on maintaining the discipline that got us to this point moving that forward. And so we appreciate everybody's interest. We look forward to kind of continuing down the road of how we turn out in 2019 and beyond and we look forward to talking to everybody next time.

And thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.