Good day, welcome to the Talos Energy first quarter 2019 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then 1 on your touch-tone phone. To withdraw your question, please press star then 2. Please note this event is being recorded. I would now like to turn the conference over to Sergio Maiworm, Vice President, Finance, Investor Relations, and Treasurer. Please go ahead.
Thank you, operator. Good morning, everyone, 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, 2019, 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, 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. Now I'd like to turn the call over to Tim.
Thanks, Sergio, 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 both on acquisition and business development activities, closing three strategic asset transactions that attract evaluation metrics while maintaining a healthy balance sheet and liquidity position.
We guided more of the same in a 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 a 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% uptime outside of the dry dock period. Following completion of the dry dock process, consistent with our previously guided timeframe, production was restored to fourth quarter levels by the end of the first quarter. We were able to use the downtime to complete the hookup of two new subsea wells to the HP-I 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 to 56,000 barrels equivalent a day, which is an increase from our 2018 pro forma annual production of 53.4 thousand barrels equivalent a day. We completed these important activities while we also celebrated an important shared health and safety milestone for the HP-I 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 hookups in the Phoenix Complex, we are participating in two additional deepwater 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. 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 12.1 thousand barrels equivalent a day of production. We also had one and a half thousand barrels equivalent a day of production shut in from our Pompano field due to two separate shut-in events. Production was restored in both Phoenix and Pompano by the end of the first quarter.
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 deepwater projects this year and our desire to accelerate our Zama appraisal program. We expect this CapEx rate to significantly taper off in the second half of the year. Again, this is also in line with our expectations and accounted for in our annual capital guidance of $465 million-$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'll 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 tests that confirms the potential deliverability of the asset. Simultaneous with the appraisal operations, we continue to advance our pre-FEED design activities.
Talos was the apparent high bidder on 23,000 prospective 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. Now I'll go around and offer additional details in our four core areas. First, the Mississippi Canyon core area includes Pompano, Amberjack, Ram Powell, and the Gunflint fields. We had a total net production of 20.6 thousand barrels equivalent a day in the first quarter. We're currently working on a recompletion project in the 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, which three blocks are currently held as primary term leases. The partnership was the apparent high bidder of two additional blocks in the most federal lease sale. Talos will have 30% working interest in the resulting joint venture. The Green Canyon area, which includes the Tornado field and the broader Phoenix Complex, accounted for net daily production of 5.8 thousand barrels equivalent a day and excludes 12.1 thousand 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. A combined impact of 17,800 barrels equivalent a day gross, 12,600 barrels equivalent a day net. Again, this allowed our company-wide production to reach an average of 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-I 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. 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 team's basin expertise.
We believe this level of revitalization and exploitation is repeatable not only in our existing portfolio, but across the Gulf of Mexico. 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 Bullet prospect. If Bullet is successful, that subsea well will be tied back and flow 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 pay in the main objective in the Miocene interval and two shallower zones along the same track. 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 15.6 thousand barrels equivalent a day in the first quarter. Blocking and tackling asset management activities led to 700 barrels equivalent a day, that's an integral part of maintaining the wellbeing and the continued production base of these assets. We also try to maintain an active rig program to unlock the still existing drilling potential of the shelf and take advantage of the infrastructure we own in shallow water. We had a successful well in our Ewing Bank 306 A2 sidetrack, which came online in May at a rate of 1.3 thousand barrels equivalent a day gross, which is 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 A20 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, one and a half miles from the original Zama 1 exploration well location, we logged nearly 900 feet gross of TVD pay, achieving a restricted and unstimulated flow test of over 7,900 barrels equivalent a day, which is 94% oil. We confirmed that the potential to achieve peak production rates of this asset when fully developed between 150,000 and 175,000 barrels equivalent a day. We captured an unprecedented 714 feet of whole core, the longest such acquired in a single well in the history of offshore Mexico. 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 characteristics, development optionality in just 550 feet of water, and a clear commercial pathway to FID and first oil. We hope to repeat this success in our current Zama-3 drilling activity, which is a mile and a half south of the original discovery location, and in a well that we are executing currently. While we work 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 are excited to include Pemex in our discussions and 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 and the goal of achieving final investment decision or FID as soon as possible. In addition to the Zama appraisal, we are 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, the main objective at thick wet sands in 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 two, we continue to be excited about the potential of the overall cross-assignment trade with Pan American, as it has got a combination of some higher risk and lower risk prospects. After the next prospect on Block two, called the Yaluk prospect, will be drilled before we move on to the Olmeca prospect on Block 31, where we will have two wells in the Olmeca prospect that are designed to expand the potential resource established by the previously drilled Xaxamani number one well. The first quarter was a busy but exciting time for Talos, we believe we are 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.
With that, I will 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 plan within financial expectations and with notable success in Tornado-3, Boris-3, and Zama. With a significant portion of our 2019 capital program in the first half of the year and the HP-I 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. 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 elected 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 but 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 price 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 U.S. Gulf of Mexico and nearing the completion of the Zama appraisal program.
Now I'll turn to the results of the first quarter. Talos's 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-I dry dock 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 gray 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 $44.60 per barrel of oil equivalent, 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-I dry dock and Phoenix export line maintenance. Our net loss in 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.
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 financial data, I'll now turn the call back over to Tim.
Okay, Mike, thank you for the update, I'll hand it over to the operator for questions.
We will now begin the question and answer session. To ask a question, you may press star then one on your touch tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.
Morning, guys. Appreciate the update.
Good morning, Jeff.
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? In general, how you guys are situated with Pemex's offset activities on their own block and how you guys are thinking about maybe FID timing these days?
Yeah. All right. Jeff, how are you? You might have knocked out half the question queues in this first question. A couple of things there. One, yeah, as usual, when we get done with each of these operations, we'll appraise the market on where we are. 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. That's why we were so excited about what we were doing in the Zama-2, both with the whole core and the flow test is, again, we weren't in the meat of the reservoir there. We're kind of on the northern edge. We're going to go down a mile and a half to the south of the original discovery well to the southern edge, and again, catch a whole core and get a full section.
When we get done with that, it's a slower operation when you're whole coring. When we get done with that, we'll announce those results. I think the other thing about the well test we did, not only was the deliverability exceptional, and keep in mind, there wasn't anything complex about that flow test. We just ran pipe over the zone, punched some holes in the well, kept the drawdowns very low, didn't stimulate anything, and flowed that back, then the combined flow test of almost 8,000 barrels equivalent a day. We're excited about that. The other thing we tried to achieve in that test, Jeff, is really to do a long flow test and a long build up to look at the drainage area that we thought we had there.
What's important about that is because the pre-unitization agreement requires us, and we're happy to do it, share all that information with Pemex. We can 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. That leads you to where they are in their operations. There's a sequencing of events that are going to occur as we get closer to FID. Again, we start to run out of our operations and run into more negotiating the unit and working with the government on development plans.
Because of that well deliverability and looking at the deep radius of investigation of the well test, we can talk to Pemex and say, "Look, here's the right place to design a well." 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. 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. There's really nothing right now that we need specifically out of that Pemex well, there's a lot of progress we can make before they drill that. We're trying to make that progress.
They're working on procurement of a rig. I would suggest that rig's 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 we're in a shared reservoir, that we're 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. We're going to make a lot of progress in the second half of the year on the unitization discussions.
Okay, great. Really helpful detail. For my follow-up, really more kind of a high-level strategic one to pick your brain on, Tim.
Yeah.
I thought it was interesting how you guys won all of the joint bids on the recent sale, but only one of your four single bids.
Yeah.
Curious if there's anything to read into that dynamic. Is it really more of a one-off? I guess, does your recent JV with Murphy kind of indicative of maybe a changing of how strategy is maybe evolving in the offshore world?
Well, look, 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. We started looking into the plays that both of us are in. We had some reprocessing projects come in. So some of what we do is, hey, look, 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 was a deeper idea, and the bidding spreads were significant. That happens, and that's fine. Then we have acreage where we've got an established position, and we notice in our established position, there's a trend developing in a different operator with another position.
That's just general good business development on going to them ahead of a sale and saying, "Look, should we think about cross-assigning and combining some prospects? While we're doing it, should we bid on some more trend acreage?" That's really what we're doing with Murphy. They're a 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. In that situation, they were in a better position to have more interest and then ultimately operate.
It's a combination of tending to what you own and radiuses around your area, then stepping back from that, then just broader trends in plays that you want to be in, then partnerships you might need to fully kind of expose yourself to those plays. 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.
All right. No, that's perfect detail. Appreciate the time as always, guys. Nice quarter.
Bye, bud. Thanks.
The next question comes from Subash Chandra of Guggenheim Partners. Please go ahead.
Yeah. Hi, good morning. Hey, Tim, the new rule changes, I guess, offshore. Any of that change how you do business or maybe reduce AROs or improve cycle times? Any flavor there?
Well, yeah. 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, or is there a different one? Which one is?
Correct. Yeah, the well control rules.
Yeah.
Yeah.
I don't think there's a lot of changes there. Look, as a general matter, what the BSEE is trying to do. Two things stepping back from that, because it's OTC week, 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 towards ourselves and not just onshore over and over again. The BSEE did a good job kind of presenting some statistics on just how safe of a basin we operate in the Gulf of Mexico. It's unbelievable that the statistics, particularly on injuries and safety, are outstanding compared to other basins. Obviously, we're all proud of that. I think there's 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. We are inspected all the time. They took an approach of, can we be more pragmatic about some of the rules and regulations we have in place? I think pragmatic is the key term there. In that well control rule, I think they only, look, I don't have every detail, but just kind of thematically, I think they only reduced the broad regulation by maybe 15%-20%. A lot of what they think works in there is still in there. 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 or materially changes anything on how we design a 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.
Got it. Secondly, Block 31, can you sort of refresh us on what FID could look like there? What scale project you might be looking at and the capital commitments involved?
Well, right. Just kind of generally in that area, I'm sure there are some slides, and we would encourage you to go to the website and see what we have out there. I'm pretty sure we have some kind of blob 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. We encouraged a conversation with them where we said, "Hey, look, we know what the main project is for you," and that is the Olmeca project that was set up by a well that looked like it has a bit of pay in it in the Xaxamani well. We knew that, but we also knew 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 pool all this stuff together? It's very shallow water. It's around, I think, 100-120 feet of water. Because what they're trying to do is play off of a known resource that could allow. 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're trying to bring to the table is other ideas that if you feel like you have something that has low risk, can you couple that with something that has a different risk profile in that aggregated area, in that water depth? 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. 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 deepwater 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. On Block 31, we have a starting point, so that's a good spot to be.
Yeah. Tim, 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? Does this also depend partly on the participation of the government?
Yeah. Again, we haven't ranged the scale there, but I think just if you think about the water depth, and I think if you look at that slide, I don't have it in front of me, but I think the coastline is literally on that slide. 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-30 million barrels gross or maybe slightly above that, you can probably reach an economic threshold. Again, that would depend on price and some other things. Again, the materiality there is much lower than it would be in what we're doing in Block 7 or certainly what the folks are doing in deepwater. What was the other aspect of that question?
Yeah. If government participation is needed.
Yeah. Well, like anything else. Right. Like anything else. The good news is by doing the cross assignment, we work through some of those issues you might see, with another broader unitization discussion, right? We're aligned with the parties on both sides of the block, certainly aligned with Pan American on what we're doing on Block 31. 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 it. How quickly can you get comfortable that 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 plan, say, in 600 feet of water or certainly 5,000 feet of 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? That design is simplified when you're in that shallow of water. You can get through that process quicker and then put your development plans in front of the government. Look, I would tell you in shallow water, if you look at Eni's project and you look at the Hokchi project, in another area, and you look at Fieldwood's project, they've all gotten through the development plan process. 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.
Great. Thank you.
All right.
The next question comes from Richard Tullis of Capital One Securities. Please go ahead.
Thanks. Good morning, everyone. 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 a final unitization agreement to FID, and then from there to first production at this point?
I think our goal is, and I don't want to put a hard deadline. I would tell you, I'll give you this goal, and we got to be clear it moves around. I think a general goal is to try to get the unit discussed and generally approved on by the end of the year. I think, look, the parties are engaged, and I think we've had good meetings. The pre-unitization agreement provides that path to have that goal be in place. Again, we have working teams, and those teams are in constant communication. I think all that is working out fine, and we're happy to have them and thrilled to have them as a partner. That's the first step.
From that, though, you have to really tighten up the development plan and then kind of provide that plan to the government. There's going to be some Q&A around that. Again, that can take a little more time. You do have some sequencing. Some of that happens concurrently, but then there is some sequencing on approvals. That's why, kind of can we get to FID? We'd like to get to that at some point next year. I think we will. There's some things to 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'll drill these wells.
What makes this discovery so exciting, we've talked about it, Richard, in the past, and we'll talk about it again, is the actual combination of a water depth that's manageable, a well depth that's manageable, again, between 11,000 and 12,000 feet subsea, well pressures that are manageable. I mean, it really is like going back to the early '80s in the U.S. Gulf of Mexico. Once you get through those regulatory hurdles, that execution can be two and a half years to first oil. You're building some structures. You're putting those structures out there. They'll be big structures in 550 feet of water. I would remind you that we manage three physical structures in over 1,000 feet of water in our U.S.-based portfolio. 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 through 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. We may take a little more time to get it exactly right. The actual project execution is right down the middle of our fairway.
Thank you, Tim. That's helpful. Shifting over to The Orlov good news there. How do you read that one? What's the next steps, and what is the early estimate on resource discovered?
Yeah. Again, we haven't disclosed the resource discovered yet. 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 Troika Field. You might have access to where some of those maps are, but we're east of our Boris Reservoir in the Phoenix Complex. We're south of the Bullwinkle facility that Fieldwood owns. We're going to be utilizing some of that infrastructure. The takeaway here is we found pay in the Miocene section. Along the way, we found a couple shallower pays in the same trap. 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?" Fieldwood happened to be in an active rig program. In a conversation with them, they said, "Look, we can go drill something else then decide if we want to take it here or move that well bore just a little bit." They're going to do that. They're going to execute that, then we'll come back here. It really doesn't change the timeline. 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. The speed to first production is quick. Finding something matters. We're excited about it.
I think exactly whether we take it here or move that well bore is something we'll work out with partners, I think. The good news is the concept has worked. I think broadly, the concept ties to other things in the areas, and that's what gives us confidence.
Thank you, Tim. I appreciate that. That's all from me.
All right. Thanks, Richard.
Again, if you have a question, please press star then one on a touch-tone phone. The next question comes from John Aschenbeck of Seaport Global. Please go ahead.
Good morning, everyone, and thank you for taking my questions.
Morning, John.
Thanks, Tim. A lot of the good ones have already been addressed. 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. 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.
Yeah. Is the thought on that question, John, can more competition come back into the Gulf?
Yes.
Yeah.
How that affects the relative attractiveness of you playing the role as the consolidator.
Yeah, no, I got you. It's interesting. I just read the same thing you read on the Chevron stepping down, and we'll see what happens with Occidental and Anadarko. What would 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's some challenges. Those of us that are here have generally been here for a long time.
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 isn't to stretch. Our job is just to make sure we understand what's actionable. One thing about us, John, is we've got to know who we are and where we are in the life cycle of the company, where we are with respect to the balance sheet, where the capital markets are, and 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's an example, and we've done small bolt-on deals in the last year.
I think it's just important for us to be patient and see what's transactionable. 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. 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're stressed. I think that's just going to continue to be the theme.
I think the takeaway is, I think there's plenty of opportunities in this basin relative to the counterparties available. Those of us that are still here have worked hard to stay here. Look, there might be competition, but I think that's perfectly fine. Again, I think if we're patient, there'll be plenty to do here. We're excited about it. Look, there might be some money that comes into the basin, but again, I still think what's available to transact on and those players that are willing to transact, I think is still dislocated and generally the buyers favor. It may create a bid-ask spread. I'm talking about just the availability of assets.
Okay. Got it. Appreciate the call, Tim, thank you for the time.
All right, John. Thank you.
The next question comes from Gail Nicholson of Stephens. Please go ahead.
Good morning, everyone. Going into the [Offham 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 two.
Oh, yeah. Look, what you basically had there is one amplitude that worked exactly like you thought it was and one amplitude that didn't. When you're in this basin, couple that with, again, going to the south, I think we think there's some amplitudes there that have already worked. Typically, you 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. Sometimes there's a difference between what we're trying to accomplish geophysically. Some things we try to do structurally, and that would get a little more technical and get to a little more detail. Yeah, you need to calibrate what you do and what worked and what hasn't worked.
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. It's too early to figure out what's been kind of de-risked and what's been culled. We'll do that with time, but that's just the nature of what we're trying to do in these emerging plays. I would submit, Gail Nicholson, and I know you follow a lot of folks, that's a consistent message anytime you're in these emerging plays. You're trying to figure out, hey, look, what did that signature mean? 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 in an emerging basin, so that when we did these tests, we wouldn't expose too much capital to the company. Some of these, again, one section worked, one section didn't work. You try to figure out what you've de-risked and what you might need to cull, but it's probably a bit too early from that. It's pretty fresh. We just moved the rig in the last week.
Okay, great. Looking at the asset management program that you guys are going to be doing at Ram Powell.
Yeah.
Can you just talk about what you're exactly doing there and what we should think of expectation for potentially a production uplift post-program?
Yeah. Again, we haven't quite guided that. I think ultimately we'll be done with it, and we'll just tell you how it goes. Look, that's a field. Anytime we get into these transactions, and that Ram Powell transaction's been, again, an example of a nice transaction there. I think that was a win-win deal for the sellers and for us. The first thing we try to do is really get in there and really understand the assets and the producing levels. We did a workover there last year, an asset job that provided some uplift on that asset compared to the production in the previous 12 months. Then it looked like as one of the completions was waning, that we could do a major rig workover there, where we actually replace all the tubing and chase a different section. Again, stack pays in that area.
We'll wrap that up and let you know how it goes. Now, typically, these are completions in the area that have. There are little gas here. Again, all the infrastructure's in place. A lot of wells might produce 1,000 to 1,500 barrels a day, but maybe 10 million cubic feet of gas a day. There's a lot of recompletions in that kind of framework, if you will. This may not be too different from that on a gross basis, but we'll complete the work and report it back. 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.
It's really step 1 in what I would call a multi-step process that really creates value to the asset. What we hope to talk about, maybe next year, is a rig program associated around the radius of that asset. To buy ourselves that appropriate amount of time, this type of asset development works. 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's mapping like crazy in what I would say is about a 25-mile radius on things within the asset and away from the asset that I hope we can talk about next year. That's all consistent with how we try to attack these things.
Great. Then just one housekeeping question. Can you just talk about P&A timing, how we should think about the remainder of 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?
It was light in 1Q, and I think that's just kind of partly a function of services and planning. Look, some of these things we were able to defer a little bit. We knew the rig work would be a little heavier. As we taper down that rig work, we'll probably taper up some P&A. On a broad capital basis, I think the way we guided it, P&A was roughly about 15%, maybe 13%-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 Energy side. We knew it would be materially lower. 13%-15% of our capital program is kind of a spot we like to be at.
Some of those we can move around, and we knew we could move around a little bit of it. I do think it'll 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 a guidance on the capital side.
Great. Thank you so much.
All right, Gail. Thank you.
Once again, if you have a question, please press star then one. The next question comes from Raymond Deacon of PetroLotus. Please go ahead.
Yeah. Hey, good morning, Tim. I was wondering on the production, the 60,000 BOE a day in May. Is the oil and gas mix now roughly where it was in the first quarter?
Well, Ray, the first reported quarter was a little, obviously, light on the oil side. Still oil-weighted, obviously, but lighter than it would be because Phoenix is a plus 80% oil field. 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, but we can go 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 because of that weighting on Phoenix, yeah.
Okay, great. With Zama-3, what is the risk there, I guess? That compartmentalization or just higher water cut or something, or it's a little down dip it looks like?
Yeah. That's a great question. Here's what's the darn interesting about it, and I think I talked about it in a previous question. We went down dip, and we found the contact. As you can imagine, when we had a broad guidance that we had out there, our previous guidance was 400 million-800 million barrels equivalent recoverable. Part of that low side, would that contact be there? We went way down dip, and it was there, and I would tell you that kind of helps with where you think about where this ends up. 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 also keep in mind we're going to have, again, dry trees and a platform rig as opposed to a deepwater rig that we're using right now to appraise it. Keep in mind, you have, again, a subsea depth that's very manageable. All that is to be said, that if you thought you needed to have water injection in your plan here, you could design water injection in your plan here and affect a recovery. You may not need to, because what we talked about in our down-dip 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. Also keep in mind, I think we've talked about in the past, 40 miles away, we see the same section.
We're in a heck of a little basin here. We don't know what that drive's going to be from an aquifer perspective, but we could almost kind of manufacture that if we needed to. I think where all that goes, Ray, is we just have all those right ingredients on this project. The water depth, the well depth, the pressures, the bubble point pressures, the rock properties. I mean, the rock properties we talked about and confirmed that 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 a pretty cool project. 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 EVP of Operations felt good the first log he saw in this water depth.
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. 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, we felt pretty good about that we're going to be able to manage that when you had the kind of the drainage radius as we saw. If you had some, these wells ultimately are going to be very quick wells from a platform rig, and you can almost drill your way through some of that and find another spot. Again, all that's because of the cost structure and the water depth and the scale of what we found.
Got it. Great. 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.
Right
In my notes, we're recognizing a $3.50, I think, premium to WTI.
That's inclusive of transportation and quality as well?
Yeah. The Venezuelan sanctions has caused the demand in the Gulf Coast to actually go up. That's adding to the premium issue.
Got it.
I don't know. Look, your guess is as good as ours on how long that's-
Right
Whether that's sustainable. There's 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. The takeaway is we get great pricing.
Got it. Great. Just one question I meant to ask. I know there's a lot of extra platform rigs sitting out there that can work in 500 feet of water. How would you likely finance that or have a partner or, I guess, how would you cover development? Or would you just lease one?
Yeah. Look, it's early, right? I mean, With respect, you're talking about Mexico, I presume.
Right. Exactly.
Right. It's early. 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. 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 or would decision B? It's a little early on that particular issue on, hey, is this someone you can just do a long-term contract? Are you going to be drilling enough wells that you should purchase this? Or is there a joint venture here? I mean, it's not as easy.
Right.
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? Ultimately, does it generate a broad return relative to the rules of this contract? If it does, we'll work down that path. 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. Those are the things that we'll think about in time.
Right. Got it. Great. Well, thank you very much. Appreciate the answer.
All right, Ray. Thank you.
This concludes our question and answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.
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. With that, we look forward to talking to all of you in our next call.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.