Talos Energy Inc. (TALO) Q1 2019 Earnings Report, Transcript and Summary

Good day, and welcome to the Talos Energy First Quarter 2019 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, Vice President of Finance, Investor Relations and Treasurer. Please go ahead.

Thank you, Operator. Good morning, everyone and welcome to our first quarter 2019 earnings conference call. Joining me 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'd 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 March 31st, 2018, filed with the SEC yesterday and on Form 10-K for the year ended 2018, filed with the SEC on March 13th, 2019. Any forward-looking statements that we make on this call are based on assumptions as of today, and we undertake no obligations 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 earnings press release, which was also filed with the SEC, and which is also available on our website at www.talosenergy.com. And now, I'd like to turn the call over to Tim.

Thanks, Sergio and thank you everyone for joining our call. It is a pleasure to present our first quarter results and progress in the early days of 2019, which have been extremely busy and productive for Talos. In our last earnings call covering our fourth quarter and full year 2018 results, we highlighted the potential of our business in our first year as a public Company with our results showing significant cash flow generation capability, proving that we can modestly grow our production with infrastructure led exploration and accelerate significant net asset value realization through the appraisal of our globally recognized Mexico discovery, while at the same time managing our obligations inside cash flow. We also demonstrated our ability to opportunistically execute bolt-on acquisition and business development activities closing three strategic asset transactions at attractive valuation metrics while maintaining a healthy balance sheet and liquidity position. We guided, more of the same in the 55 WTI environment for 2019. As mentioned during our fourth quarter call, we successfully completed our regulatory dry-dock process in March of this year for the Helix Producer I, called the HP-I, which is the floating production vessel at our Phoenix complex. The dry-dock process is an important operation that is designed to ensure the operational reliability and long-term health of the critical production facility on one of our key assets as demonstrated by the facility's higher than 95% up-time outside of the dry-dock period. Following completion of the dry-dock process and consistent with our previously guided timeframe, production was restored to fourth quarter levels by the end of the first quarter. However we were able to use the downtime to complete the hookup of two new subsea wells to the HP-1 upon its return to production. The two wells, the Tornado 3 well and the Boris 3 well were drilled prior to and during the dry-dock period and their addition resulted in an increase in the Company's production to an average of over 60,000 barrels equivalent a day in the first week of May. All of this activity is built into our 2019 annual production guidance of 53,000 barrels to 56,000 barrels equivalent a day, which is an increase from our 2018 pro forma annual production of 53,400 barrels equivalent a day. We completed these important activities, while we also celebrated an important shared health and safety milestone for the HP-1 with our friends from Helix we celebrated eight years and 2 million man-hours without a lost time incident, a milestone that we're extremely proud of. It's been a busy 2019 for the Company operationally, as we've had active projects across every one of our operating areas. In addition to Tornado 3 and Boris 3, the two subsea completions and hook-ups in the Phoenix complex, we are participating in two additional deep-water drilling projects in our core Green Canyon area. We continue to appraise and validate the potential of our Zama discovery in offshore Mexico. And we're continuing to drive value creation through both drill bit and asset management activities in our shallow water assets. So some highlights for the quarter. Production in the first quarter was 42,000 barrels equivalent a day down from the prior quarter due to the 57-day Phoenix dry-dock process which deferred approximately 12,100 barrels equivalent a day of production. We also have 1,500 barrels equivalent a day production shut in from our Pompano field due to two separate shut-in event. Production was restored in both Phoenix and Pompano by the end of the first quarter and with the inclusion of the Tornado 3 and Boris 3 subsea wells, again, we achieved an average of over 60,000 barrels equivalent a day for the first week of May. Adjusted EBITDA for the quarter inclusive of our hedge settlements was $93.7 million and it was $96.7 million excluding realized impact of our hedges. Capital expenditures for the quarter were $155.6 million inclusive of P&A activities. In a 2019 capital program that is front-end loaded in the first and second quarters, primarily due to the timing of our deep-water projects this year and our desire to accelerate our some Zama appraisal program. We expect this CapEx rate to significantly taper off in the second half of the year. And again, this is also in line with our expectations and accounted for in our annual capital guidance of $465 million to $485 million. Our liquidity position remains strong at $356 million at the end of the first quarter and our current adjusted debt-to-EBITDA, as defined by our credit agreements of 1.3 times; a ratio that will immediately improve with full run rate quarters later in 2019. In the U.S. deepwater, we achieved a production milestone six years in the making by more than quadrupling the gross output from the Phoenix complex since we acquired the asset. In our Zama discovery in offshore Mexico, we completed our second appraisal operation, the third total penetration securing a record whole core which provided a significant amount of information from the rock and fluid property perspective and also performing a highly successful series of flow test to confirm the potential deliverability of the asset. Simultaneous with the appraisal operations, we continue to advance our pre-FEED (ph) design activities. Talos was the apparent high bidder on 23,000 perspective gross acres or 10,000 net acres in the recent Gulf of Mexico federal lease sale in March at an average cost of approximately $200 an acre. This includes expanding an exploration joint venture with Murphy, which I'll discuss in more detail shortly. So now I'll go around and offer additional details on our four core areas. First, the Mississippi Canyon core area includes Pompano, Amberjack, Ram Powell and the Gunflint field. We had a total net production of 20,600 barrels equivalent a day in the first quarter. We're currently working on a recompletion project in Ram Powell asset which is an asset we purchased in the first quarter of 2018 as part of the ongoing field study and redevelopment plan there. We also finalized a 28,000 acre joint venture with Murphy along the prolific Middle Miocene trend in the Mississippi Canyon area. This JV includes cross assignment of acreage across five block areas in which three blocks are currently held as primary term leases. The partnership within (ph) the apparent high bidder of two additional blocks in the most federal lease sale, Talos had about 30% working interest in the resulting joint venture. The Green Canyon area, which includes a Tornado field and the broader Phoenix complex accounted for net daily production of 5,800 barrels equivalent a day and excludes 12,100 barrels equivalent a day of dry-dock deferral for the first quarter. However, after the restart of the base production, we also brought online two new wells in April, The Tornado 3 and the Boris 3 wells. The Tornado 3 well came online at a sustained rate of 9,300 barrels equivalent a day gross, we own 65% working interest. While the Boris 3 well has reached a sustained rate of 8,500 barrels equivalent a day. We own 100% working interest. So a combined impact of 17,800 barrels equivalent a day gross, 12,600 barrels equivalent a day net. These figures are all incremental to the prior Phoenix production and will be additive to the second quarter production levels.And again this allowed our Companywide production to reach greater than 60,000 barrels equivalent a day in early May, which keeps us on track with our annual production guidance. In addition to the safety milestones of the HP-1, that we discussed earlier and embedded in the 60,000 barrels equivalent a day we just talked about. We achieved a meaningful production milestone for that facility as well by having our gross production reach 40,000 barrels a day or 47,000 barrels equivalent a day, in that facility for the first time. When we agreed to purchase the Phoenix asset in the fourth quarter of 2012, the Phoenix Field was producing 9,300 barrels a day or 11,800 barrels equivalent a day gross. But we believe remapping the asset with new seismic and improved reprocessing would lead to another round of exploitation and exploration. This achievement of this production milestone is a testament to the potential of our infrastructure led exploration strategy when coupled with seismic technology and our teams based on expertise. We believe this level of revitalization and exploitation is repeatable, not only in our existing portfolio, but across the Gulf of Mexico. And further to that strategy, the Noble Don Taylor rig which drilled and completed the Tornado 3 and Boris 3 wells, is currently on location drilling our Bulleit prospect. If Bulleit is successful, that subsea well will be tied back and flowed to our Green Canyon 18 platform, leveraging the available capacity in that facility, which we purchased in the third quarter of last year, with minimal incremental cost. We also recently had encouraging results in our Orlov prospect finding (ph) pay in and the main objective and the Miocene well and two shallower zones along the same trap. In our shallow water, another core area, accounts for both our legacy shallow water assets as well as some small deepwater assets, this core area generated 15,600 barrels equivalent a day in the first quarter. Blocking and tackling asset management activities led to 700 barrels equivalent a day and that's an integral part of maintaining the well being and the continued production base of these assets. We also tried to maintain an active rig program to unlock the still existing drilling potential of the shell and take advantage of the infrastructure we own in shallow water. We had a successful well in our Ewing Bank, 306 A-2 Side Track, which came online in May at a rate of 1,300 barrels equivalent a day gross, which is a 1,000 barrels equivalent a day net to our 100% ownership and that's an 80% oil-weighted well. We are continuing with this program by drilling a deep test that plays off of our exploration success we talked about last year in the Ewing Bank 306 A-20 well. In offshore Mexico, we're continuing to maintain the urgency that I think the reforms envisioned for the country. On Block 7, we successfully completed our second Zama appraisal penetration. In testing the Northern Extension of the reservoir, 1.5 miles from the original Zama 1 exploration well location, we logged nearly 900 feet gross of TBD (ph) pay, achieving a restricted and un-stimulated flow test of over 7,900 barrels equivalent a day, which is 94% oil and we confirm that the potential to achieve peak production rate of this asset, when fully developed between 150,000 barrels and 175,000 barrels equivalent a day. We captured an unprecedented 714 feet of whole core, the longest that's acquired in a single well in the history of offshore Mexico. And finally, we're really proud of our operational execution completing both the drilling and the well test operations safely ahead of schedule and under budget. We continue to believe in the potential of the Zama discovery with an outstanding subsurface characteristic development optionality in just 550 feet of water and a clear commercial pathway to FID and first oil. We hope to repeat the success in our current Zama 3 drilling activity, which is a 1.5 mile south of the original discovery location and a well that we're executing currently. While we worked through the appraisal, we continue to work with the Pemex team as part of our pre-unitization agreement and the established work teams that this agreement contemplated. We're excited to include Pemex in our discussions, in our plans to accelerate production and make sure that we maximize the value of such an important resource for so many stakeholders. We will continue these unitization discussions throughout the year, while we also work on the final design and development plans in the goal of achieving final investment decision or FID as soon as possible. In addition to the Zama appraisal, we're also continuing our exploration activities focusing on higher risk, higher return targets to complement Zama in our portfolio. On Block two, our partner Pan American Energy drilled the Acan prospect and found gas pay in multiple targets in the shallow section of the well. But the main objective had thick (ph) wet sands. And the shallow sands were not enough to justify the appraisal going forward. Cost net to our 25% participating interest however were low at less than $5 million. Despite the results of this particularly high risk exploration in Block 2, we continue to be excited about the potential of the overall cross assignment trade with Pan America, as it's got a combination of some higher risk and low-risk prospects. After the next prospect on Block 2 called the (inaudible) prospect will be drilled before we move onto the Olmeca prospect on Block 31, where we have two wells in Olmeca prospect that are designed to expand the potential resource established by the previously drilled Xaxamani-1 well. In conclusion, the first quarter was a busy, but exciting time for Talos, but we believe we're well positioned for the remainder of 2019 and beyond. Our team did a great job delivering operationally and financially on a multitude of both growth and maintenance projects that we were able to execute in a short timeframe. So with that, I'll hand it over to Mike to discuss some more details of financial results.

Thank you, Tim. In the first quarter of 2019, Talos successfully executed on our operations, drilling and regulatory dry-dock plans within financial expectations and with notable success, and Tornado 3, Boris 3 and Zama. With the significant portion of our 2019 capital program in the first half of the year and the HP-1 dry-dock behind us. We look forward to continuing to execute operationally as we move through the remainder of 2019 to deliver planned results within financial guidance for the full year. Talos continues to focus on maintaining a strong balance sheet and strong credit and leverage metrics. Based on the annualized results of the trailing three quarters, which is the period provided in our Credit Facility agreement. Net debt to annualized adjusted EBITDA was 1.3 times and we have no debt maturities until 2022. As of March 31st, our liquidity was approximately $356 million consisting of $46 million of unrestricted cash and $310 million available under our credit facility. As a reminder, Talos selected to maintain its bank commitments at $600 million in the fourth quarter of 2018, despite our lenders approving an increase of our borrowing base up to $850 million last fall. As we conclude a challenging successful quarter, we continue to believe that Talos represents one of the most compelling investment cases in the energy sector, due to our strong cash flow generation capabilities, oil weighted portfolio, with access to premium priced markets along the Gulf Coast and maintenance of a solid leverage and liquidity profile. We look forward to the remainder of 2019 after having initiated material new production in the US Gulf of Mexico and nearing the completion of the Zama appraisal program. Now, I'll turn to the results of the first quarter. Talos' average daily production for the first quarter was in line with expectations at a rate of 42,000 barrels of oil equivalent per day or 3.8 million barrels of oil equivalent, 70% of this was oil. As disclosed before, 12,100 barrels of oil equivalent per day of production from the Phoenix complex was deferred during the HP-1 drydock in the first quarter. With regard to pricing differentials, oil prices stabilized in the first quarter following late fourth quarter declines. Our average realized crude oil price was $58.46 per barrel, which represents a $3.50 per barrel premium to the average WTI price over the same period after gathering transportation and quality deducts. Demand continues to be strong in the Gulf Coast markets, due to a variety of macroeconomic factors including a relative shortage of appropriate great crude suppliers for Gulf Coast refineries. Driven by sanctions on Venezuela and other international suppliers. On the revenue side, our first quarter revenues were $178.7 million, which is also impacted by the production deferral in the Phoenix complex in that quarter. We continue to benefit from highly oil weighted portfolio with over 85% of our revenues driven by oil production in the first quarter. Turning to total lease operating expenses, we incurred expenses of $45.5 million in the first quarter, down approximately 8.5% from the fourth quarter of 2018. G&A was $17.6 million for the quarter, down from $24.7 million in the fourth quarter of 2018. As reported, G&A is $4.60 per barrel of oil equivalent and that equates to $3.60 per barrel of oil equivalent when transaction costs and non-cash equity-based compensation are normalized. Other operating expenses including workover and maintenance expenses were $23 million for the quarter. These costs were inclusive of approximately $10.4 million non-recurring expenses primarily driven by approximately $6.9 million of expenses related to the HP-1 dry-dock and Phoenix export line maintenance. Our net loss and EBITDA consisted of a net loss for the quarter of $109.6 million or $2.02 per share. Excluding unrealized commodity losses from derivatives and other items, our first quarter adjusted net income was $10.3 million or $0.19 per share. And the adjusted EBITDA for the quarter was $93.7 million. Capital expenditures for the quarter were $155.6 million inclusive of plugging and abandonment costs and as previously guided, we expect capital expenditures for the year to be heavily weighted in the first and second quarters of 2019. This concludes the prepared remarks on the quarter's financial data. And I'll now turn the call back over to Tim.

Okay, Mike. Thank you for the update. And I'll hand it over to the operator for questions.

We will now begin the question-and-answer session [Operator Instructions]. The first question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.

Question first, Tim down in Mexico, with Zama 3 ongoing. Can you maybe give us a little bit better sense in regards to the timeline for when you guys think you could be in a position to communicate findings with Zama 3 and in general, how you guys are situated with the Pemex's offset activities on their own block and how you guys are thinking about maybe FID timing these days?

You might have knocked out half of the question queues in this first question. So a couple of things there. One, as usual, when we get done with each of these operations we'll appraise the market on where we are. So we had to move the rig, as you know what we're trying to do in these appraisals is really get to the edges of these reservoirs and so that's why we were so excited about what we were doing in the Zama 2 both at the whole core and the flow test is, again we weren't in the meat of the reservoir there, but kind of on the northern edge. We're going to go down 1.5 mile to the south of the original discovery well to the southern edge and again catch a whole core and get a full section. And when we get done with that, it's a slower operation when you are whole coring, and when we get done with that, we'll kind of announce those results. I think the other thing about the well test we did, not only was the deliverability exceptional, and keep in mind that there wasn't anything complex about that flow test. We just ran pipe over the zone, punched some holes in the well, kept the draw-downs very low, didn't stimulate anything and flowed that back and in the combined flow test of almost 8,000 barrels equivalent a day. So we're excited about that. But the other thing we tried to achieve in that test, Jeff, is really to do a long flow test and a long buildup to look at kind of the drainage area that we thought we had there. And what's important about that is, because the pre-unitization agreement requires us and we're happy to do and share all that information with Pemex, we can kind of loop them in on what we're seeing, so that they get comfortable and we're comfortable about how we're sharing this reservoir together. And so that kind of leads you to where they are in their operations. So there's a sequencing of events that are going to occur as we get closer to FID. And again, we start to run out of our operations and run into more negotiating the unit and working with the government on development plans. And so, because of that well deliverability and looking at the deep radius of investigation of the well tests, we can talk to Pemex as they look, here is the right place to design a well. And frankly what we really need out of that well, and how much we may or may not need from that well. I think when we're done with the appraisal, we're going to have a pretty good idea of what this whole thing looks like. And I think we're getting Pemex comfortable on where we are in a shared reservoir, we need to make an application to the government that we're in a shared reservoir. So there's really nothing right now that we need specifically out of that Pemex well. And so there's a lot of progress we can make before they drill that. And so we're trying to make that progress, they're working on procurement of a rig. I would suggest that rig is probably doing a lot more than just drilling an offset to our discovery. I think the more important progress for us is really communicating to them, what we've found and starting making the appropriate applications with the government that were in the shared reservoir, that were working with the Pemex on the unitization. We will have ultimately four penetrations on our side, the penetration on their side, I don't think is really a material difference to what we'll have appraised on our side. So we're going to make a lot of progress in the second half of the year on the unitization discussions.

And for my follow-up really more kind of a high level strategic one to pick your brain on Tim. But, you know, that was interesting how you guys won all of the joint bids on the recent sale, but only one of your four single bids, and curious if there's anything to read into, into that dynamic. Is it really more of a one-off and I guess does your recent JV with Murphy I guess indicative of maybe a changing of how the strategy is maybe evolving in offshore world?

Well, I think what we've done in the past year is we've done a deeper dive into the combined acreage of not only our portfolio, but the stone acreage that came with the merger and we started looking into the plays that both of us were in, we had some reprocessing projects come in. So sum of what we do is we have infrastructure in the area. We see an idea -- let's just put a bid on that and see if we're right. On one of those we had a shallower idea. I think there is a deeper idea and the bidding spreads were significant, and that happens, and that's fine. And then we have acreage where we've got an established position and we noticed in our established position, there is a trend developing in a different operator with another position and that's just general good business development. I'm going to them ahead of a sale and saying, look should we think about cross designing and combining some prospects, and what we are doing is should we bid on some more trend acreage. And that's really what we're doing with Murphy. They're great operator, when we went to them, they had a little more interest than we did which starts the negotiation on what you would do if you start to kind of go after some trend acreage. And so in that situation, they were in a better position to have more interest and ultimately operate, but I think it's a combination of tending to what you own and radiuses around your area, and then stepping back from that, and then just broader trends in place that you want to be in and then partnerships you might need to fully kind of expose yourself to those plays. And so I would just say they're different processes. We want to participate in all of those, because ultimately that's where we can create the most value.

The next question comes from Subash Chandra of Guggenheim Partners. Please go ahead.

Tim, the new rule changes, I guess, offshore. Any of that change how you do business or maybe reduce AROs or improve the cycle times. Any flavor there?

Well, let's make sure specifically I'm commenting on what's on your mind. Are you talking about the well control rule that came out recently with the director as a different one which I don't think there's a lot of changes there. Look, as a general matter what the BSE is trying to do is, so two things stepping back from that, because with OTC and for those on the call that haven't had a chance to go to OTC, it's a great venue, it's a great event, it happens once a year. I kind of jokingly call it the offshore prom, because it's one week where we actually have a little attention toward ourselves and not just onshore over-and-over again. The BSE did a good job, kind of presenting some statistics on just how state of the basin we operate in the Gulf of Mexico, and it's unbelievably that the statistics particularly on injuries and safety are outstanding compared to other basins. Obviously, we're all proud of that. I think there is this notion that in this administration, are inspections less, are they regulating us less, I will tell you our inspections year-over-year are up, and they're up materially. So we're inspected all the time. And then they took an approach of can we be more pragmatic about some of the rules and regulations we have in place. And I think pragmatic is the key term there and in that well control rule, I think they only -- and look, I don't have every detail, but just kind of thematically, I think they only reduced the broad regulation by maybe 15% to 20%. A lot of what they think works in there is still in there, and some of the things that just upon hindsight are too burdensome or the efficacy isn't really there on what they were intended to do are some of the things they took out. I don't think, it really broadly and materially changes anything on how we design the well or even a notion that it's going to go materially quicker. I think it's just really more about kind of making sure what we have out there, really actually is doing what it's intended to do.

And secondly, Block 31. Can you refresh us on what FID could look like there? What scale project you might be looking at and the capital commitments involved?

So just generally in that area and I think there's -- I'm sure there's some slides and we encourage you to go to the website and see what we have out there, I'm pretty sure we have some kind of blog maps on how some of the inventory crosses both of those areas. How that came together is, we had some reprocessing that was proprietary reprocessing that covered parts of their block. And so we encouraged a conversation for them where we said we know what the main project is for you and that is the Olmeca project, it was set up by a well that looked like it has a bit of pay in, in the Xaxamani well. And we knew that, we also knew it, if that works for you guys, there might be other things to do. Let us show you the data we have, let us show you what we have on our block and that's how we got to the conversation on, hey, can we pull all this stuff together? Now it's very shallow water. It's around I think 100 feet to 120 feet of water. So because what they're trying to do is play off of a known resource, and when you look at the water depth in that area, you could get to the conclusion where you could come to an FID quicker than you normally would otherwise. Again, because you're starting with something and again the water depth. What we are trying to bring to the table is other ideas that, if you feel like you have something that has a low risk and you couple that with something that has a different risk profile in that aggregated area, in that water depth. So you've got two standards there, you've got a minimalist standard or a minimalist rate of return standard to set up an FID. And then you've got that what else could be around there, part of what we have on Block 2 is a bit of that what else. Now with respect to the Acan prospect, just to take this a little further to you. One thing that we're doing in this area is really just trying to understand what geophysical signatures work or don't work. Again, same as Block 7 and frankly I was listening to some of the comments on the Murphy call, they're doing the same thing in deeper water on their Block 5. A lot of what we're trying to do in this upper Miocene, even lower Pliocene section is really understand what do these signatures mean if you don't have a starting point. But on Block 31, we have a starting point. So that's a good spot to be.

Tim, so there are a lot of maps and so on, on Block 31. I guess seeing the term FID and the timing of FID here. What would be a potential scale of this project? And does this also depend partly on the participation of the government?

So again, we haven't ranged the scale there, but I think if you think about the water depth. And you can see, I think if you look at that slide, I don't have it in front of you, I think the coastline is literally on that slide, but I think the materiality levels are much lower there. And again I don't want to try to over guide the prospect inventory. But I would suggest probably between 20 million and 30 million barrels gross or maybe slightly above that you can probably reach an economic threshold. Again, that will depend on price and some other things. So again the materiality there is much lower than it would be than what we're doing in Block 7 or certainly what the folks are doing in deepwater. What was the other aspect of that question?

If government participation…

Well, like anything else, the good news is by doing the cross assignment, we worked through some of those issues you might see with another broader unitization discussion. We're aligned with the parties on both sides of the block certainly aligned with Pan America and what we're doing on Block 31. So you don't have those issues. It really is we're going to drill two wells on Block 31 that are set up by an initial well that has pay on, and so how quickly can you get comfortable, did you have that rate of return threshold to go to the government with an action plan. Now the action plan in 120 feet of water is a lot less difficult than the action plans there in 600 feet of water or certainly 5,000 feet to water. I think the pathway to FID is as much as the FEED work if you will what's the engineering design and what are you trying to do for the resource and that design is simplified when you're in that shallow water. So you can get through that process quicker and then put your development plans in front of the government. And look, I would tell you in shallow water. If you look at E&I project and you look at the Hokchi project in another area, and you look in Fieldwood's project they've all gotten through the development plan process. So it's really more understanding what you have, understanding what your path forward is, I think when you put it in front of the government, if it makes sense, you should expect that you'll get that approved.

The next question comes from Richard Tullis of Capital One Securities. Please go ahead.

Tim, thanks for the earlier commentary regarding the Zama unitization process. Looking at the potential timeline, Tim approximately what would be the expected length of time between the final unitization agreement to FID and then from there to first production at this point?

So I think our goal is and I don't want to put a hard, hard deadline. I would tell you. I'll give you this goal and say and you got to be clear, it moves around, but I think our general goal is to try to get the unit discussed and generally approved on by the end of the year and I think, look, the parties are engaged in, I think we've had good meetings, the pre-unitization agreement provides that path to have that goal being placed and again we have working teams and those teams are in constant communication. So I think all that is working out fine and we're happy to have them and thrilled to have them as a partner. So that's the first step. And then from that, you have to really tighten up the development plan and then kind of provide that plan to the government. There is going to be some Q&A around that and again that could take a little more time and so, you've got, you do have some sequencing. Some of that happens concurrently, but then there is some sequencing on approvals and that's why -- can we get the FID? We'd like to get to that at some point in next year, I think we will, but there are some things that move around. Now, the good news is because you're in 550 feet of water, you're in a water depth that's very manageable. You're talking about fixed structures, you're talking about dry trees, ultimately that will drill these wells. What makes this discovery so exciting and we've talked about it Richard in the past and we'll talk about it again is the actual combination of a water depth is manageable, a well depth is manageable again between 11,000 feet and 12,000 feet subsea, well pressures that are manageable. I mean, it really is like going back to the early '80s in the US Gulf of Mexico. And so, once you get through those regulatory hurdles, that execution can be 2, 2.5 years to first oil. You're building some structures, you're putting those structures out there. There'll be big structures in 550 feet of water. I would remind you that we manage three physical structures and over 1,000 feet of water in our US based portfolio. So, again nothing out there is going to have a serial number that says 0001 on it Richard, this is all blocking and tackling, I think it's really more about getting to the regulatory hurdles the right way. It's an important unitization, it's the first of its kind down there. We want to make sure we get it exactly right. And we may take a little more time to get it exactly right, but the actual project execution is right down the middle of our fairway.

Thank you, Tim. That's helpful. And shifting over to the the Orlov good news there. I mean how do you read that one? What's the next steps and what is the early estimate on resource discovered?

Again, we haven't disclosed the resource discovered yet, and we like to stay coordinated with our partners on that. I think the way you should think about that is, we had a Miocene target there. It plays off of a field called the Aspen field and another field called the Droshky field and so, you might have access to where some of those maps are. But we're east of our Boris reservoir and the Phoenix complex and we're south of the Bullwinkle facility, the Fieldwood zone (ph) and we're going to be utilizing some of that infrastructure. So the takeaway here is, we found pay in the Miocene section, along the way we found a couple of shallower pays in the same trap. And when you do that, you look at it and say, look, do I want this exact location, do I want to move it around slightly when we think about some of the shallower pays we found. Feel what happened to be in an active-rig program. So in a conversation with them, they said, look, we can go drill something else and then decide if we want to take it here or move that well bore just a little bit. They're going to do that, but it really doesn't change. They're going to execute that and then we'll come back here. And it really doesn't change the timeline and I think that's the theme around, what a lot of us are doing out there around our infrastructure, because their Bullwinkle platform is so close, because we have some of this inventory available, because we're utilizing some of the subsea infrastructure. The breakevens are low here and the speed of first production is quick. And so finding something matters and we're excited about it. I think, exactly whether we take it here or move that well bore, is something we will work out with partners, I think. But the good news is, the concept has worked in, and I think broadly the concept ties to other things in the areas and that's what gives us confidence.

[Operator Instructions] The next question comes from John Aschenbeck of Seaport Global. Please go ahead.

So thanks, Tim. Lot of the good ones have already been addressed, but I did have a higher level question, if you could entertain me here. You've made no secret that you think it's a great time to consolidate the Gulf and even as little as six months ago. I'd say that would be a counter consensus opinion. But, I'm just curious as additional operators have started to slowly, albeit very slowly, voice more interest in the Gulf, how do you think that changes the overall attractiveness of the M&A environment? Just if at all, thanks.

Is the thought on that question, John, can more competition come back into the Gulf?

Yeah. And how that affects the relative attractiveness of you playing the role as the consolidator?

Now I got you. It's interesting, I mean I just read the same thing you read on the Chevron stepping down and we'll see what happens with Occidental and Anadarko. What will be interesting on that is what Occidental thinks about the Gulf. They were a big operator 15 years ago, 20 years ago. Would they come back, would they not come back? If they did, obviously they have an organization in Anadarko in place to do so. I would submit, it's kind of hard to leave this basin and walk right back into it. The technology is unique. There are some challenges. Those of us that are here have generally been here for a long time and I think that's the theme that I talked about in the past, is ultimately there are a lot of assets that could move in the Gulf of Mexico. And I don't know if there's enough counterparties for all of those assets. Our job is just to make sure we understand what's actionable. I mean, one thing about us John, is we've got to know who we are and where we are in the lifecycle of the Company, where we are with respect to the balance sheet, where the capital markets are, what we can transact on. If we can transact on something big, we're going to figure out how to do that, we've done relative value deals obviously Stone is an example. And we've done small bolt-ons deals in the last year. And so I think it's just important for us to be patient and see what's transactionable. But what I think is unique about us is we try and I think I've talked about this in the past we try to play in all the small spaces and big spaces. It could be something that is strategic, it could be something that's a bolt-on. It could be a stranded discovery. It could be an exploration JV. We're trying to play in all of that and I think my only goal is to look back at any given year and say we made the most of our business development activities without doing something that maybe that puts us in a position where we are stressed. And I think that's just going to continue to be the theme, but I think the takeaway is, I think there's plenty of opportunities in this space and relative to the counterparties available. Those of us that are still here have worked hard to stay here. And look, there might be competition, but I think that's perfectly fine. And again, I think if we're patient there'll be plenty to do here and we're excited about it. And look, there might be some money that comes into the basin. But again, I still think what's available to transact on in those players that are willing to transact. I think it's still dislocated. And generally, the buyers favor. And it may create a bid-ask spread. I'm talking about just the availability of assets.

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

I'm going into the off-cam Block now that you have that starting point with the first well. Has that changed your interpretation of the seismic on the Block at all?

Which block Gail were you referring to?

Block 2.

So what you basically had there is, one amplitude that worked exactly like you thought it was and one amplitude that didn't. And when you're in this basin and then couple that with again going to the south and I think we think there is some amplitudes there that have already worked. So typically, just kind of recalibrate all of that, the next prospect is actually more of a structural play, so more of a geological play than a geophysical play. And so you know, sometimes there is a difference between what we're trying to accomplish geophysically and then some things we tried to do structurally and that would get a little more technical and get to a little more detail. But you need to calibrate what you do and what worked and what hasn't worked. But I would tell you, even in a dry hole, when you find pay and you can figure out where that signature is, it can unlock other things. Now it's too early to figure out what's been de-risked and what's been called. We'll do that with time, but that's just the nature of what we're trying to do in these emerging plays. And again I'll assume it, Gail and I know you follow a lot of folks. That's a consistent message anytime we're in these emerging plays. We're trying to figure out, hey look, what does that signature mean? And again, you hate to have a dry hole, it wasn't a lot of money and that's one of the reasons we did the cross assignments, one of the reasons we picked up these leases in shallower water and in emerging basins. So that when we did these tests, we wouldn't expose too much capital to the company. But some of these, again one section worked, one section didn't work. You try to figure out what you de-risk and what you might need to call, but its probably a bit too early from that. It's pretty fresh, we just moved the rig in the last week.

And then looking at the asset management program you guys said you'll be doing at Ram Powell, can you just talk about, kind of what you're exactly doing there and how we should think of expectation for potentially a production uplift post program?

I think we haven't quite guided that, I think ultimately we'll be done with it. We'll just tell you, kind of how it goes, but, you know, look, that's a field anytime we get into these transactions and not (ph) Ram Powell transactions, but then again example of a nice transaction there. I think that was a win-win deal for the sellers and for us. But the first thing we try to do is really get in there and really understand the assets in the producing levels. We did a work over there last year, an asset job that provided some uplift on that asset compared to the production in the previous 12 months. And then it looked like, as one of the completions was waning that we could do a major rig work over there, where we actually replace all the tubing and chase a different section against stack pays in that area. And so we'll wrap that up and let you know how it goes. Now typically, these are completions in the area that have -- they're a little gassier. Again, all the infrastructure is in place, and a lot of wells might produce a 1,000 to 1,500 barrels a day. But maybe 10 million cubic feet of gas a day. And so there is a lot of recompletions in that kind of framework, if you will. And so this would may not be too different from that on a gross basis, but we'll complete the work and report it back. But the important part about attacking those assets Gail, is it allows us to then think of those obligations get pushed, that ARO gets pushed, gives us time to reprocess data and think about some drilling locations. And so it's really step one, and what I would call a multi-step process that really creates value to the asset. What we hoped to talk about maybe next year is a rig program associated around the radius of that asset. But to buy ourselves that appropriate amount of time, this type of asset development works. So I think it's really the theme you buy at a low-entry cost, you fix and manage and try to improve the asset with what's available to you. This is an example of that. In the meantime, our team is mapping like crazy, and what I would say it's about a 25-mile radius on things within the asset and away from the asset that I hope we can talk about in next year. So that's all consistent with how we try to attack these things.

And then just one housekeeping question. Can well just talk about P&A timing, how we should think about the remainder P&A for the year and if it's going to hit predominantly in one quarter versus another quarter as it was very light in 1Q?

Yes, so it was light in 1Q. And I think that's just partly a function of services and planning and look, you know, some of these things we were able to defer a little bit, we knew the rig work would be a little heavier. So as we taper down that rig work will probably taper up some P&A, but on a broad capital basis, I think the way we guided it, P&A was roughly about 15%, maybe 13% to 15% of our capital program. Keeping in mind that's down half from where it was in 2018. Pro forma when we tried to put together the businesses and we had some legacy P&A, we needed to do on the Stone side. So we knew it would be materially lower. 13% to 15% of our capital program is kind of a spot we'd like to be at. Some of those, we can move around and we knew we can move around a little bit of it. And I do think it will be back loaded on the second half of the year, keeping in mind the rig work will be tapered off significantly, which is why again, we reaffirmed the guidance on the capital side.

[Operator Instructions] The next question comes from Ray Deacon of Petro Lotus. Please go ahead.

I was wondering on the production, the 60,000 BOE a day in May. So oil and gas mix now roughly were less than in the first quarter?

Well, so the first quarter -- Ray, the first reported quarter was a little obviously light on the oil side. Still oil-weighted obviously but lighter then it would be because Phoenix is a plus 80% oil field. So now that we have everything back, you have, I would say a mix similar to, and I don't have it right in front of me, Ray, where we can go and look at it, but I would guess it would be similar to what we had in the fourth quarter. If not, maybe even a little higher. If not maybe just a touch higher, weighting on Phoenix, yeah.

And with Zama-3, what is the risk there, I guess that your compartmentalization or just higher water cut or something or it's a little that we get, but it looks like...

So that's a great question. And here's what's the darn interesting about it and I think I've talked about it in a previous question. So we went down deeper, we found the contact. And as you can imagine, when we had a broad guidance that we had out there in our previous guidance was 400 million to 800 million barrels equivalent recoverable. Part of that low side, would that contact be there, and so we went way downdip and it was there, and I would tell you that kind of helps with where you think about, where this ends up. Then you get into other questions and the questions you asked about compartmentalization and how do we think about recovery. Keep in mind you have a production sharing contract and that sharing contract incentivizes you to spend some capital. You know, also keep in mind, we're going to have again dry trees and a platform rig as opposed to the deepwater rig, that we're using right now to appraise it. And keep in mind, you have again a sub-sea depth that's very manageable, all that is to be said, if you thought you needed to have water injection in your plan here, you could design water injection in your plan here in effective recovery. You may not need to, because what we talked about in our downdip appraisal well is we had a big pile of sand, more sand than we thought. And most of that -- when we found the aquifer within about 10 meters of where we thought we'd find the aquifer. So and also keep in mind, I think we've talked about in the past 40 miles away we see the same section. So we're in a heck of a little basin here, we don't know what that drive is going to be from an aquifer perspective. But we could almost kind of manufacture that, if we needed to. So I think we're all that goes, Ray, we just have all those right ingredients on this project. The well depths, the pressures, the bubble point pressures, the rock properties, I mean the rock properties we talked about and confirm with the whole core are tremendous. It's a large three-way closure, you can go see that on our slides on the website. It's pretty cool project, we just -- look you want to make sure, the amplitudes are doing what you think they're doing. You need to go appraise the edges of this thing. I would suggest my EVF (ph) operations felt good, the first log you saw in this water depth. But we want to get this done the right way. There's a lot of eyeballs on us, we want to over-deliver on expectations, we want to make sure, we're working with Pemex. But if you think about this from just a subsurface perspective, it's hard to shoot holes in it. When you're dealing with these depths, if you thought you had compartmentalization, which by the way the well test felt -- we felt pretty good about that we're going be able to manage that when you had the drainage radius as we saw. But if you had some, these wells ultimately are going to be very, very quick wells from a platform rig and you can almost drill your way through some of that and find another spot. So again, all that's because of the cost structure and the water depth and the scale of what we found.

And just lastly, I wanted to make sure, I understood the comment about Venezuelan crude and the -- is the impact on WTI realizations in the Gulf negative, because there's less Venezuelan crude around? Is that the right way to understand?

It's actually the basis differential is actually positive. So in my notes, we're recognizing a I think, $3.56 a premium to WTI.

And that's inclusive of transportation and quality.

And the Venezuelan sanctions has caused the demand for -- in the Gulf Coast to actually go up, so that's adding to the premium issued.

And I don't know, look, your guess is as good as ours on how long that's -- whether that's sustainable. But there has been obviously, you know this is a basin where we've had positive basis differential for a long time, and we expect to have it. It ebbs and flows with these geopolitical issues, but the bottom -- the takeaway is, we get great pricing.

Just one question I meant to ask. I know there's a lot of extra platform rig sitting out there that can work in 500 feet of water. How would you likely -- would you finance that or have a partner, or I guess how would you cover development or would you just lease.

I mean, we've got a -- with respect, you're talking about Mexico I presume.

Right, exactly right.

So it's early, I mean, I think there's a lot of decisions we're going to have to make on exactly how we want to do different parts of this. I mean, you've got to go back to the contract. If I made a decision A versus a decision B, would A be recoverable through the contract over a decision B. And so it's a little early on that particular issue on, hey is there someone you can just do a long-term contract. Are you going to be drawing enough wells that you should purchase this or is there a joint venture here. I mean it's not as easy thing I just what I would leave you with is in these contracts, some of the commercial things Ray that you might do or I might do in the U.S., you've got to tailor it to, does it make sense and ultimately does it generate a broad return relative to the rules of this contract. And if it does, we'll work down that path, and if it doesn't, we might think about another path. I don't have a comment on that specifically other than to leave that thought with you. And those are the things that we'll think about in time.

This concludes our question-and-answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.

So look, I think that's it. We appreciate everybody for joining the call. We enjoy the questions and we enjoy your participation, and we thank you for your interest in the Company. And with that, we look forward to talking to you, all of you in our next call.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.