Good morning, and welcome to the Talos Energy fourth quarter 2018 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 1 on your telephone keypad, and to withdraw your question, please press star 2. Please note, today's event is being recorded. I would now like to turn the conference over to Sergio Maiworm, investor relations. Please go ahead, sir.
Thank you, operator. Good morning, everyone, and welcome to our year-end 2018 earnings conference call. Joining me here today to discuss our results are Tim Duncan, President and Chief Executive Officer, and Michael Harding, Executive Vice President and Chief Financial Officer. Before we get started, I'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 September 30th, 2018, filed with the SEC on November 5th, 2018, and on Form 10-K for the year ended 2018, which we filed with the SEC yesterday.
Any forward-looking statements that we make on this call are based on assumptions as of today. 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 press release, which was filed with the SEC and which is also available on our website at talosenergy.com. Now I'd like to turn the call over to Tim.
Thanks, Sergio. Thank you everyone for joining our call. It's been an extremely busy year for us as we transition from a private to a public company in 2018 after our reverse merger with Stone Energy. We've seen the benefits of the merger immediately coming in on the high side of our production guidance and generating significant positive free cash flow on a pro forma basis in our first year as a public company. We increased our proved developed reserve base by 20% in our year-end 2018 proved reserve report compared to the pro forma year-end 2017 by converting several key subsea projects into proved developed that will bolster the business in 2019 and beyond. We're off to a great start in our appraisal work of our Zama discovery in offshore Mexico as well. As a reminder, we continue to show in our earnings release two sets of values.
On a full year 2018 basis, you will see as-reported values, pro forma values. The as-reported values include the legacy Talos assets for the entire year, then specifically the Stone assets from May forward, including the Ram Powell asset we purchased after the announcement of the merger, but just prior to the closing of the merger. The more useful measure of the assets in our view is the pro forma view of the company, which looks at the performance of Talos and Stone from the beginning of the year then Ram Powell after its closing in May. The good news is this is the last time I'll have to make that statement, the third and fourth quarter results are inclusive of all the combined assets of both companies.
The 2018 annual guidance that we provided upon closing the Stone transaction was done on a pro forma basis. For example, our annual net production guidance on a pro forma basis was 49,000-53,000 barrels equivalent per day, while our actual production for the year was 52.4 thousand barrels equivalent per day, which was 77% oil liquid. Similar to what I mentioned on our last call, I would again encourage you to visit several of the presentations on our website. The latest detailed deck posted in the fourth quarter provides a deeper dive into our strategy, our drilling inventory, and how we've built a company focused on generating positive free cash flow and creating shareholder value through a disciplined approach to capital allocation. The model is simple.
We have a deep understanding of our basins, the U.S. Gulf of Mexico and offshore Mexico, both which are prolific geological basins that respond to seismic reprocessing to help reduce risk and are areas where our teams excel operationally. The U.S. Gulf of Mexico benefits from ample infrastructure and premium pricing, the current market environment allows us to engage in a combination of low entry M&A an infrastructure-led exploration and exploitation with conventional offshore wells that have lower initial declines than comparable projects onshore. Offshore Mexico allows us to access an emerging basin with a significant resource base in water depths that allow us for low breakevens a quick turnaround to cash flow.
We think the combination of assets in these two countries will help us both grow at a measured pace in the U.S. Gulf of Mexico, more materially in a low-cost structure when our Mexico volumes come online. I'm going to run through the high-level results, starting by summarizing full year 2018 on a pro forma basis the fourth quarter contribution to these year-end values. I'll also highlight a couple other corporate-level results before taking a deeper dive into our core areas. The year-end proved reserves for 2018 were 151.7 million barrels equivalent, with a pre-tax PV-10 of $3.9 billion using SEC pricing, which includes flat prices of $65.56 a barrel on WTI and $3.10 an Mcf prior to adjustments related to quality transportation deducts and basis differentials. Reserve replacement was just over 100% compared to year-end 2017 pro forma reserves.
Because P&A requirements related to the merger were higher in 2018 than what we would expect going forward, we focused on a series of low-cost projects that resulted in our proved developed reserves increasing 20% in our year-end 2018 reserves compared to the pro forma year-end 2017 reserves. Year-end 2018 proved developed reserves were 115.5 million barrels equivalent with a pre-tax PV-10 of $3.19 billion, which does not include our recent Gunflint transaction in January 2019, our recent success in the Boris 3 deepwater well in our Phoenix Complex, which was still booked as a PUD at year-end. Also, keep in mind, these volumes do not include any value for our large Zama discovery, which is currently booked as a contingent resource.
Full year production was 52.4 thousand barrels equivalent per day, while fourth quarter production was 53.4 thousand barrels equivalent per day, which was approximately 73% oil and 79% liquids in the fourth quarter. Full year revenue of just over $1 billion, with fourth quarter revenue of $259 million. In the fourth quarter, our realized oil price was $63.04 per barrel, keeping in mind that's inclusive of transportation and deductions, so a good $4 per barrel above the average realized pricing above the average WTI pricing in the period. Our net income for the full year was $275 million, which translates to an earnings per share of $5.96. Adjusted EBITDA for the year was $585 million, and our capital program, inclusive of P&A, was $452 million. Clearly, we're generating positive free cash flow even if you account for our debt maintenance.
Liquidity position at year-end was $460.3 million, excluding the borrowing base increase in the fourth quarter. As we communicated before, in November of 2018, the company's borrowing base was increased 42% to $850 million. At the time, we elected to maintain our commitments at $600 million. We have access to that additional $250 million of capacity. We continue to strengthen our balance sheet, which is evident by our net debt to annualized EBITDA at one times at year-end. To finalize this section, I just wanted to remind everyone that we have already posted our 2019 guidance back in January, where we established our expectations that we can modestly grow production year-over-year and continue to generate free cash flow in a $55 WTI price environment. Let's walk through some details across our four core areas.
In the Green Canyon area, which includes the Tornado field and the broader Phoenix Complex, has been an area where we've been quite busy in recent months. Production in the fourth quarter was 17.9 thousand barrels equivalent a day net to our interest. In our Phoenix Complex, which includes our Tornado subsea wells, we have successfully completed our mandatory dry dock for our hosting floating production vessel, the HP-1. We are currently undergoing sea trials and expect to bring production back online within the coming days. Therefore, the total shut-in period in the Phoenix area should be approximately 56 days, which is within our guided 45 to 60 days. As painful as it is to defer the production from this complex, it assures the long-term health of that production facility, and we're going to need it. Both wells in our recent Phoenix drilling campaign were successful.
Both will start completion operations in the coming days and will be hooked up to the HP-1 early in the second quarter. We expect the Tornado 3 well to deliver initial production rate between 10,000 and 15,000 barrels equivalent a day gross, which would be 5,000 to 7,500 barrels equivalent a day net, as we own 65% with Kosmos owning the other 35%. Our Boris 3 well should deliver between 3,000 and 5,000 barrels equivalent a day gross, which is 2.8 to 4.6 thousand barrels equivalent a day net to our 100% working interest. Both subsea tiebacks have very quick turnarounds by utilizing our infrastructure in place. In the third quarter, we announced our Green Canyon 18 transaction from Whistler Energy II. The Green Canyon 18 field was producing approximately 1.9 thousand barrels equivalent a day gross at the time, 1,500 barrels equivalent a day net to our 100% interest.
A low entry transaction where our $14.5 million acquisition cost translates to just a little over $9,000 a flowing barrel. More interestingly, the Green Canyon 18 facility has 30,000 barrels a day of oil capacity, it's largely underutilized. While we work to develop a drilling program to revitalize the asset itself, which has produced over 100 million barrels equivalent to date, we quickly pulled together multiple business development opportunities with our regional seismic that we can tie back to this facility where the fixed costs are paid for. Of those, we've entered into a participation agreement with EnVen to drill the Bulleit prospect. We will have an initial working interest of 67%, and we'll be the operator. Operations will begin late in the second quarter of 2019, utilizing the rig we have working for us in the Phoenix Complex.
Bulleit is 10 miles away from the Green Canyon 18 field, the prospect is set up by amplitude supported Pliocene objectives similar to the production in Green Canyon 18. If drilling is successful, Bulleit will be a subsea tieback to Green Canyon 18, utilizing part of the unused capacity on the platform. We also entered into an agreement to purchase Exxon's Antrim discovery, 30 miles southwest of the Green Canyon 18 field. Antrim found subsalt pay from a Miocene reservoir in Green Canyon Block 364. We will appraise the discovery with a new well, possibly as early as 2020, if successful, those volumes could be tied back to the Green Canyon 18 field. To quickly pull these opportunities together within months of closing a bolt-on transaction is a great representation of how we want to execute our business model.
We've entered into a participation agreement to drill the Orlov subsea project with Fieldwood, where we'll have a 30% non-op interest. This prospect is very similar to our recent success in the Boris field and the Phoenix Complex, a project that we've had interest in for some time. If that project is successful, it'll be a subsea tieback to Fieldwood's Bullwinkle facility for a short turnaround to first oil. The Mississippi Canyon core area includes the Pompano, Amberjack, and Ram Powell fields and has a total net production of 19,300 barrels equivalent a day in the fourth quarter net to our interest, which was impacted by shut-in production related to Hurricane Michael in the fourth quarter. We're excited about the foundation these assets represent for the future.
In 2018, we had a successful subsea well come online in the Pompano field called Mount Providence, which continues to outperform and was one of the larger positive revisions for us this year. Shortly after closing our Ram Powell transaction, LLOG Exploration announced they will develop their Stonefly project as a subsea tieback to our Ram Powell facility, therefore paying Talos a production handling tariff. These types of deals represent a balanced approach to acquiring mature assets in deepwater, not only developing new drilling opportunities within that required resource base, but also utilizing these assets as business development vehicles. We also announced in January we closed a small bolt-on transaction by buying a 9.6% non-operated interest in the Gunflint field from Samson Offshore. Transaction cost total $29.6 million for 2.2 million barrels equivalent of proved reserves.
80% of those reserves were proved developed. The transaction represents $13.45 a BOE on a 1P basis. The asset averaged between 1.5-1.8 thousand barrels equivalent a day net in the months leading up to closing. We believe there are potential several drilling locations within the asset and the surrounding areas that will provide upside to the transaction. Our shallow water and other core areas accounts for both our legacy shallow water assets and some small deepwater assets, both operated and non-operated. This core area accounted for 16,100 barrels equivalent a day of net production in the fourth quarter. As we discussed in previous calls, we like to keep one rig running continuously on our shallow water acreage set and will continue to do so throughout 2019.
This allows us to add quick production and manage the long-term profitability of these assets, which helps us manage our P&A spending as well. We brought on two new wells late in the fourth quarter and early first quarter of 2019 in our Main Pass 72 field, which together totaled approximately 2,000 barrels equivalent a day gross and 1.6 thousand barrels equivalent a day net. The ENSCO 75 rig is currently working in our Ewing Bank 306 field, where drilling success last year allowed this asset to reach production levels it hadn't seen in 15 years. We will drill three new wells in this field in 2019, which includes some lower risk field pays, then an offset to our deeper Miocene discovery that we announced last year, all off of the same production platform for a quick turnaround.
In offshore Mexico, after absorbing the data from our discovery well in Zama, which we guided between 400-800 million barrels of gross recoverable contingent resource, it was time to get back to operations in the fourth quarter and drill these three appraisal penetrations. We announced recently that the first appraisal location, called the Zama-2 well, penetrated the oil water contact slightly deeper than expected and consistent with our geological and geophysical models. The first leg of our appraisal was completed safely and efficiently, 28 days ahead of schedule and 25% under the AFE as we continue to learn more about and become more comfortable with the drilling environment in offshore Mexico. We're currently active in our second appraisal, the Zama-2 sidetrack, which is a straight hole north of the original Zama-1 location.
We've recently completed coring operations there. We expect to start our flow testing in the coming weeks. We will announce more details when those operations are complete. We will move to the Zama-3 location, which is south of the first discovery well, where we will repeat those coring operations. The appraisal program should be completed by mid-year, at which point the resource range will be narrowed, when we get closer to FID and book these reserves into proved and probable. Again, as a reminder, it's currently booked as a contingent resource. Concurrent with these activities, we'll continue to work diligently on our pre-FEED efforts, with the goal of pushing this project toward FID in the first half of 2020, which could allow us to have production online in the second half of 2022.
Again, what makes these economics of this project so unique is the size of this resource in shallow water depths. We have around 550 feet of water here, which allows for fixed structures, dry trees, and maximum flexibility in fully developing the asset. In our last call, we discussed the historic cross assignment trade in our Block 2 acreage, the first of its kind in offshore Mexico, where we traded out of 25% of our participating interest in Block 2 for a 25% participating interest in Block 31 directly to the south, giving us a 25% participating interest in both blocks, which are located in very shallow waters. Hokchi Energy, a subsidiary of Pan American Energy, will be the operator of both blocks.
This deal allows us to aggregate a larger depth of drilling opportunities into one development plan, facilitating operational synergies and quicker production, which is consistent with our goals and those of Mexico and the country's energy reform. Four wells will be drilled in 2019 in this area, two on each block. Block 2 is anchored by Talos' Zacán prospect, while Block 31 is anchored by Pan American's Olmeca project. The Olmeca project is aided by pay found in the previous PEMEX well, the Xaxamani-1 well. Both projects are amplitude supported and aided by Talos' proprietary seismic reprocessing in the area, which we're contributing to the partnership.
By pulling this inventory together and specifically focusing on Olmeca on Block 31 as part of this initial drilling campaign, our hope is to reach FID on a development plan for this area in 2020 and this project to complement our efforts in Block 7, allowing us to put together an impactful business in offshore Mexico in the near future. In my closing remarks, I'm extremely proud of our team's efforts in 2018. We asked a lot of our professionals. We needed to integrate two companies. We need to balance a series of growth projects that will further stabilize the business, while also executing some residual one-time maintenance and P&A projects that lingered from the Stone bankruptcy days.
We also wanted to quickly execute some bolt-on business development opportunities and show our new public shareholders that we can reliably generate positive free cash flow, which we certainly did this year, and we expect to continue to do so in the current commodity price environment. We're excited about where we go from here, and you should expect us to continue to deliver these results. I'll hand it over to Mike Harding to walk through additional full year 2018 and fourth quarter results.
Thank you, Tim. As Tim referenced, Talos continues to be focused on generating positive free cash flow. For the full year of 2018, our pro forma adjusted EBITDA was $585 million, with a $452 million capital program. It's clear we generated positive free cash flow in 2018. As we stated in our 2019 guidance earlier this year, we also expect to be free cash flow positive in 2019 and beyond. Another focus for Talos continues to be to maintain a strong balance sheet, credit metrics, and leverage metrics. Based on the annualized results for the second half of 2018, which is the period stated in our credit facility agreement, net debt to annualized adjusted EBITDA was 1x, and we have no debt maturities until 2022. At year-end, our liquidity was $460 million, which represents a 10% increase from the third quarter of this year.
Our liquidity consists of $140 million of unrestricted cash and $320 million available under our credit facility. It's worth noting that this liquidity position excludes the $250 million increase in our borrowing base in November. Before I go into the fourth quarter and full year results, I'll say that the company ticks all the boxes we think investors are currently looking for. We generate positive free cash flow, have an oil-weighted portfolio close to 80% liquids with premium pricing, low leverage with no near-term maturities, and we currently trade at a meaningful discount to PV-10 of our PDP reserves. This reflects what I believe to be a very compelling investment case. Furthermore, we have a globally recognized generational discovery in our Zama asset in Mexico, which is not yet priced into our stock. I'll turn to the results of the fourth quarter and full year for 2018.
For production, Talos averaged daily production in the fourth quarter of 53.4 thousand barrels of oil equivalent per day, or 4.9 million barrels of oil equivalent, 73% of which was oil. Compared to the third quarter, production was down slightly, mainly due to the shut-in resulting from Hurricane Michael and other small third-party downtime instances. For the full year on a pro forma basis, our daily production was 52.4 thousand barrels of oil equivalent per day, which is at the higher end of our guidance, which ranged 49 to 53 thousand barrels of oil equivalent per day. The 2018 production also represents an approximate increase of 5% from what Stone and Talos produced individually in 2017. On the commodity price side, despite the oil price decline in the fourth quarter, our basis differential has widened significantly in the same time period.
Our average realized crude oil price after transportation and quality deducts was $63.04 per barrel, or approximately $4 per barrel higher than the average WTI Cushing spot price. The demand for our oil continues to be robust, which continues to provide favorable basis differentials into 2019. On the revenue side, fourth quarter revenues were $258.7 million. For the full year, on a pro forma basis, they were just over $1 billion. While oil continues to represent approximately 73% of our production, it accounts for around 87% of our overall revenues. As we continue to allocate capital to our organic drilling project, we expect our oil exposure to continue to grow. As we look at direct lease operating expenses, these expenses were $49.7 million for the fourth quarter.
For the full year, on a pro forma basis, our LOE was $177.9 million, or $9.28 per barrel of oil equivalent. General administrative expenses were $23.1 million for the quarter, which is inclusive of approximately $4.9 million of transaction costs, mainly related to the Stone combination and the Whistler acquisition. It is also inclusive of non-cash equity-based compensation. As reported, G&A is $4.70 per barrel of oil equivalent, but $3.54 per barrel of oil equivalent when transaction costs and non-cash equity-based compensation are normalized. For the full year on a pro forma basis, our G&A per barrel of oil equivalent is $3.35. Other operating expenses include workover and maintenance expenses, which were $15.3 million for the quarter.
These costs include approximately $7.5 million of non-recurring expenses, primarily related to structural maintenance, and include the preparation for the HP-1 dry dock. Our net income for the fourth quarter was $306.3 million or $5.66 per share. For the full year on a pro forma basis, Talos generated a net income of $275 million or $5.96 per share. Excluding unrealized commodity gains and other items, our fourth quarter adjusted net income was $49.3 million or $0.91 per share. Talos' pro forma full-year adjusted net income was $173.8 million or $3.77 per share. Adjusted EBITDA for the fourth quarter was $158.8 million, whereas adjusted EBITDA for the full year on a pro forma basis was $585 million. Capital expenditures for the fourth quarter were $142.2 million, inclusive of P&A, and the full-year pro forma CapEx was $452 million.
As part of the Stone merger, as we mentioned, we were required to spend more capital in P&A than we normally would have. As stated in our 2019 guidance, we expect to cut this P&A spending in 2019 by approximately half. This concludes the prepared remarks for the quarter financial data and the year. I'll now turn the call back over to Tim.
Thanks, Mike. Let's turn it back over to the operator and queue up some questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, we ask that you 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. Today's first question comes from John White of Roth Capital. Please go ahead.
Good morning. Thanks for taking my call.
Morning, John.
Congratulations on such a very nice year of meaningful accomplishments. Everything looks really nice.
Well, we appreciate it. It's a busy first year trying to integrate and still execute, but we're happy with the result.
Yeah, you had a lot going on. Mike, two questions mainly on trying to get some more comments. Do you want to talk about the timing of Zama-3?
I think it's all fairly well laid out in the guidance. We are in the middle of the coring operation. I think we've mentioned we successfully completed that. Those are tricky operations. Those are things we don't always do in the U.S. Gulf of Mexico side. With this type of discovery, that's something we wanted to do here. We get into the drill stem test, and we have several spots we want to go try to perforate and flow back to the surface and look at deliverability. We may add one. There's some things you might have to adjust on the fly, and all that needs to be completed, and then we go down to the Zama-3 location, which again, is south of the first location.
There's a lot that goes on there, and we think the most appropriate thing to do is complete each operation and then let you guys know how things are going. I would suspect, again, everything done by mid-year is still a very reasonable goal, and so I think you're going to see a couple announcements between now and then.
Appreciate that. You and your team are showing your experience by piling up the geologic information on the Zama block. Follow-up on, again, a timing question, the Exxon Green Canyon 364.
Right.
Any timing comments on that?
Not just yet. I think that lease has some life left in it. It's got some term left in it. I think it's 2023. I've got a couple of colleagues in here. 2025. Okay. It has some time. We like it. We like the fact that it fits right into the strategy. It could be into the program in 2020. It could be in 2021. I think as we get later in the year, and we look at the results from this year, and we look at the type of portfolio we want next year, we'll make that decision. I think one thing you should think about is we don't try to take on longer rig commitments than we really need to. We've been layering on some hedges. I think that's summarized in the K or certainly summarized in the release.
We've been layering on some hedges for 2020. As we layer those hedges on, we think it's appropriate to start thinking about our rig program for 2020. It certainly could be a part of that program. It could be in 2021. I think the broader message for us is we did a transaction in Green Canyon 18 that wasn't a lot of barrels, and it wasn't a lot of money. You can stand back from that and ask, is that really strategic? Is that really interesting? Keep in mind that asset in Green Canyon 18 is 15 miles north of our Phoenix field. Just that by itself is interesting to us. That means we have a good foundation of the geological opportunities we think are around that area.
We see this as an excellent opportunity to not only develop something that may not be as material to Exxon, and that's understandable, but could be material to us. I think we just have to sort out the capital program for next year, what can come online quickly, what we're willing to have a little more patience on, and then work through that. As we develop that, we'll come back and be in touch.
I appreciate that extra detail. I'll follow up with Sergio later today and look forward to seeing you guys next week.
Okay. Thanks so much.
Ladies and gentlemen, our next question comes from John Aschenbeck of Seaport Global. Please go ahead.
Good morning, Tim, and thanks for taking my questions.
Sure, John.
For my first one, I just was hoping to get more color on Antrim. A lot of my questions you actually just addressed. Separately, was curious how significant is the future cash bonus payment to ExxonMobil, and then also, what is the override?
Yeah. I don't know if you've done a lot of deals with Exxon. You can expect there's a confidentiality provision on some of this stuff. I would just submit that if it was material, I would have stated. It's not a material amount. It's a reasonable amount. There's an earn-out structure. That's probably where I'll leave it. These are deals that obviously we're sensitive to two things that I would say as a foundation. We're sensitive to the strategy we've created, the expectations we create. I think we like to cut deals that are a win-win for both parties. I think Exxon had something that wasn't as material as they had hoped for. They're a company that would typically like to build out their infrastructure, and we're a company that had that infrastructure.
It made for the right opportunity to put this deal together. Obviously, if there was huge payments involved, you would've heard about it a lot sooner. I think it's a reasonable transaction for both sides. I think the rest of your details maybe I hit in my response to John.
Yeah, you did, Tim. Maybe I'll give you the opportunity to expand upon them a little bit. I was just curious if you could share any other information that has you excited about Antrim
Yeah
If you didn't already address it already.
Well, 2 things. Anytime you can calibrate subsalt pay, that's interesting for our geological team, for the broader area of what we do. I think any time that you can stick with what you're trying to accomplish in these transactions. Again, a lot of this is set up by doing a low entry transaction in Green Canyon 18. I think we spent $14.5 million of net cash for I think 1,500 barrels a day net to our interest. So under 10,000 a flowing barrel, we established something. We're working very hard in that Green Canyon 18 transaction to put a drilling program together for that resource base. While we're doing that, we expand that radius and look for other opportunities. We identified the Antrim opportunity. We think it needs another appraisal well to commit ourselves to pulling all that back up to Green Canyon 18.
We're excited about what that does. Now, that's a project that, unlike Phoenix, it's not going to turn around and you're going to drill the appraisal well, and it's going to produce in 6 months. It could take 18 months or so to pull all that online. We have to think about our capital program as we look into 2020 on what's the balance between things that can turn into production quickly, and what are the balance between things that might have more material production but take a little more time. We're going to spend some time digesting that. The first step is pulling that inventory together around the things that we purchased in a low entry way, and that's exactly what Antrim represents.
Okay, great. That's really helpful. For my follow-up, just regarding the 2 new deepwater projects that-
Yep
you're going to drill later this year. Just, I guess, first of all, how would you characterize the risk profile of those? More of a point of clarification, I was wondering if that drilling capital is included in the prior 2019 budget that you provided. Thanks.
Yeah. Well, let's start with the latter, and that's a good question, and we probably should've been a little clearer on that in the earnings release. If you go look at our guidance, we talked about four subsea projects. We were in some negotiations and conversations with both parties, and these are firms that we've worked with in the past. They're good, well-run companies. We were talking about those. We wanted to get those into a committed participation agreement, which we've done. Yes, the answer is they were in our guidance. I would characterize those as pays that have analogs. These are prospects that have analog pay sections somewhere in our core area, and that provides us comfort.
Sometimes you can operate those, which is in the case of Bulleit, and sometimes the operator is going to maintain that status, which is appropriate in the case in Fieldwood. What sets these up is the access to infrastructure that's in place that allows us to drill something that has some risk, but a very good looking analog that we might be familiar with. For example, in each of these instances, the analog is something we own. In the EnVen prospect Bulleit, the analog is in fact the pays at Green Canyon 18. In the Fieldwood prospect Orlov, the analog is actually in our Boris area. Similar analogs. We feel good about the direct hydrocarbon indication response out of the geophysics. We just got to go drill these wells and find out.
Because of the infrastructure, they can both come online fairly quickly for a subsea tieback, which again, I think fits right into part of our strategy. When you're appraising something like Zama, that's going to take a little more time, part of your capital has to be allocated on things that have what I would consider a lower risk profile.
Okay, got it. That's it for me. Thanks, Tim.
All right, bud. Thanks.
Today's next question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.
Morning, guys.
Hey, Jeff. How are you?
Good, thanks. Just sticking on Bulleit and Orlov here. Was curious, are there any kind of promote structure or anything that you guys can disclose, or are those done on a heads-up basis? I guess just when you guys take a step back and look at the broader opportunity set in the Gulf, Tim, can you just talk about are there more deals like this, I guess, to be done, or would you have an interest in them given kind of as you talked about balancing capital and risk profiles and things like that?
Yeah. Again, there's confidentiality provisions in these participation agreements that I think especially right now, I think what we wanted to do is make sure that prevents me to really going through the details. Look, I think we do try to avoid some upfront promotes, but we've got to put a structure together that works for both sides. Sometimes you have some success-based earn outs and fees in that regard. The goal here is, I think for both sides when we do these deals, both us, whether who the seller is and us as a buyer and where we can fit in our operations, we try to do so. If it's appropriate for the seller to maintain operations, that's great too. I think we're all accomplishing the same goal, which is how do we create optionality in our inventory and utilize the infrastructure that we have?
That's what this is all about. I think as I've mentioned in conferences and on the road, we are looking for a full menu of business development options within the areas that we have seismic, and that we feel like we can add some value in, particularly if we can use infrastructure. That could be a stranded discovery. That's why we do the asset transactions. It's also why we show up at lease sales, and then we work on these business development activities as well. It's all part of how do we figure out how to aggregate the right opportunity set for what we're trying to do with our capital program that lends itself to maintaining that free cash flow position we've created. These types of deals help complement our inventory.
We might buy something like the Green Canyon 18, and we may need a year and a half to put together that drilling program. What can we do to complement that transaction in the nearer term? Bulleit's an example of something that could complement that transaction. Is that helpful?
No, that's perfect. I appreciate that. For my follow-up down on the Mexico assets, Pemex obviously been in the news quite a bit with their finances and whatnot. I know we're expecting them to drill a well adjacent to Zama here that was going to facilitate the unitization discussions. Just kind of wondering, relative to the last time you guys had a call, do you have a sense for could any of this impact unitization discussions, or do you guys feel pretty good about having those in the back half of the year and ultimately FID in 2020?
Yeah. Look, that is probably the variable that moves around the most, Jeff. I think that's fair. I think the good news is what we did in our pre-unitization agreement was made sure we didn't get disconnected technically with each other. We made that agreement that we would share the results and how we're doing, and that we would stay in touch with one another, and all that is in an effort to make sure we don't have delays when we get into the unitization discussions. They are a little bit delayed in their well. I think it's a focus for them. We are in communication with the team through that pre-unitization agreement, which spelled out having a work team that shares the data.
I do think we're trying to do everything we can to stay on pace with respect to our knowledge transfer and our communication. We would like to see them drill that well. Is it causing a large delay at this point? Maybe not. Is it possibly the variable that moves around a little bit? It could be. I think, again, I don't want to underscore the effort of what the pre-unitization agreement does for us. It allows us to make sure we're not waiting to build a depth of understanding, which is a large part of what holds up unitization discussions. Again, they have a little bit of a delay. Let's hope they can get back on track.
Okay. Understood. Appreciate the comments, a nice quarter, guys.
All right. Thanks. Appreciate it.
The next question comes from Shahin Amini of Pareto Securities. Please go ahead.
Thank you. Good morning, gentlemen, and congratulations on a solid quarter. Two questions. You had two unplanned downtimes last year. HP-1 disconnected unexpectedly, and Pompano, you had a compressor issue. I expect you've spent some time looking at it technically. Could you sort of give markets and investors confidence that these were very much one-off, or do you feel that you need to implement new procedures and processes? Is there anything that can be done to mitigate this in the future? The second question on Zama. On the back of the appraisal data you've gathered to date, can you provide any more color on the reservoir quality and how the second well compares to the first well? Thank you.
Yeah. Well, I'll actually go in that order. Thanks for both those questions, by the way. First, we'll talk about the downtime last year in the Helix Producer I. I would say generally, absent of those events, and those events are always difficult, and I do think Helix does a wonderful job as a steward and the operator of the vessel. Just so you understand how that works, they obviously operate the vessel, own the vessel. Their job is to try to keep that vessel stationed. It's a dynamically positioned vessel, and then we manage all the production facilities and are the designated operator of the block. We have this dry dock probably every two and a half years. You've got, I think, eight or nine thrusters around this vessel. Those thrusters inevitably over time get challenged. That's exactly why we go into dry dock.
We're going to be coming out of dry dock with brand-new thrusters. Typically there's some challenges as we get into that period going up to dry dock, and we saw a couple of those challenges. Then there's I think updating on software systems and things like that. I would submit, and I don't have it, that our uptime in the absence of those events is probably somewhere around 95%. It's very, very high. I think generally they do a good job there. It's difficult to see two in a year. It's not a huge surprise when you're doing it going into the dry dock. We're going to welcome the ship back with a fresh refurbishing of the thrusters and some other updated software systems and things like that. It's something they have to manage.
I want to underscore, I really do think Helix does a heck of a job. The Pompano compressor outage, look, we have mature assets out there. It's tricky. I think we have a maintenance team that runs around and works very, very hard trying to keep our production up. You're going to have those from time to time. We always revisit the action items. Again, I actually think in the absence of that field has pretty good uptime. Downtime with respect to offshore operations is probably one of the toughest variables to model through. We try to do our best to model those through as well. Again, it's just something that we have to stay focused on. The question on Zama, I think it was a rock property question. I think what we disclosed is-
Reservoir quality, yes.
Yeah, reservoir quality. I think what we disclosed in the down dip location are several things. One, a little more sand there than we thought, which is nice because you want more sand when you start going down dip and think about what the aquifer might look like and the energy support that that aquifer could provide. I think we had net to grosses within the expectation that we have here, keeping in mind it's a very large kind of column of oil in the pay section and then column of sand generally. The other thing I think we're talking about is the rock properties are consistent to what we see in the Upper Miocene section in the U.S. Gulf of Mexico, and that's important.
Typically, we have very good rock properties in the Upper Miocene in the U.S. Gulf of Mexico. Those rock properties respond to geophysics and some of the tools we use geophysically. I don't know if we disclosed specifically to rock properties, but I think as a general matter, Miocene rock in the U.S. Gulf of Mexico, which we look like here, have porosities between 23%-26% and perms in the hundreds of millidarcies. I think you've got a complex that we can expect good deliverability from. What we're going to do on our drill stem test is really try to kind of hone in on what to expect on that deliverability over different perforated intervals so we can think about how to fully develop this asset. We'll disclose the expectations going forward of deliverability once we complete those tests.
We haven't seen anything that's discouraging about the rock properties across our appraisals to date. I think all we've disclosed on number two is the fact that we've kind of maintained our coring operations. Again, no surprises with respect to rock properties.
That's very helpful. Thank you.
Okay. Thanks for the question.
Our next question today comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.
Yes, thank you. The two new partnerships with Fieldwood and EnVen, do you have a feel for the reserve potential on those projects?
Obviously, we do, Marshall, I probably have a lawyer in the room that reminds me I'm on a call and probably shouldn't submit that right here on this call. Look, they're the type of prospects that, kind of what we would say, looks similar to the things we're drilling in the other parts of our portfolio. The reason we like these is the time to first production. We didn't disclose reserves in this particular earnings release. I think as we get closer to drilling those wells, we might be able to kind of put some guidance out there. Right now, we're probably not disclosing that.
Okay, fair enough. You didn't have a lot of drill bit reserve adds in 2018, but saw an impressive amount of PUD conversions.
Yeah.
Could you talk about the nature of your 2019 drilling compared to 2018 in terms of PUD conversion potential versus new reserves?
Yeah. Let's go back to 2018. I think it's important to note that we didn't guide that 2018 was going to be a year where we tried to go too far outside the reserve report. I think part of the reason there is Stone had some lingering obligations, and that when we went into the merger, we knew those obligations were there. They also had some unrestricted cash in the combination that could help us work through those P&A obligations. We knew they were there, but they were still going to be a larger percentage of our capital program than we would want to have on a year-over-year basis. Our decision was, let's go execute some lower risk PUD conversions that frankly, we liked and were attractive, and that was Mount Providence on their side.
It was Tornado Three and Boris Three on our side to help really stabilize the business in 2019. We knew we had a dry dock coming up. That was the decision to kind of stay inside the report, which we did. Frankly, what that resulted in is a higher weighting of value in PDP, which I think you see today, and then an increase broadly improved developed reserves, which I think helps us from a credit perspective as well. You saw an increase in the borrowing base in the fall. I think part of that is related to the way we allocated capital last year and the first year of the merger. That puts kind of 2018 behind us. In 2019, you're going to see a little more activity outside the reserve report.
I think the combination of lower risk ideas, and then of course, everything we're doing down in Zama is outside the reserve report. We're highly proved developed now, I think around 75% proved developed. Still some things that we'll do inside PUD, but they're probably smaller in shallow water. In deeper water, most of what we're doing is outside the reserve report. Obviously Zama is outside the reserve report. You should think about Zama as something that over time will find its way into the reserve report on a proof basis, and when it does, it'll be material.
Thank you.
All right. Thanks, Marshall.
Our next question today comes from Richard Tullis of Capital One Securities. Please go ahead.
Hey, thanks. Good morning. Tim, the PV-10 versus the company enterprise value differential is interesting. I know Mike touched on it a little bit in his comments. Just to clarify, the PV-10 for the year-end 2018 PDP reserves, it does include the ARO associated with those properties as well.
Yeah. Let's make sure we kind of understand AROs as just as a general matter. All of our ARO that is associated with those proved reserves is in the proved reserve report. There is always some ARO. Typically, you'll see that in the current ARO, and I don't have the K directly in front of me, but I think it's between $60 million-$70 million of current, which coincides with what we guided in our 2019 guidance because those fields are offline. That's why we're plugging them. They're not in the reserve report. There's always a little bit of ARO, not in the reserve report, but All the P&A associated with the reserve report is absolutely in the reserve report, and then in those PV-10 values.
Specific to PDP, typically that will encompass all of the P&A and those assets that don't have maybe a PDNP case or a PUD case. Keeping in mind that, again, we're 75% proved developed, and so most of our ARO are in those cases. We put the ARO in that kind of last proved case, again, which is oftentimes in the PDP case.
Okay.
It's all in the report.
That's helpful, Tim. Have you, perhaps internally estimated what the PDP, PV-10 would be using, say, current pricing? I know you have the $2.5 billion for the SEC pricing.
Yeah. Right. I haven't, nor have we disclosed that. I don't want to miss on a guess here on this call. I would suggest it still might be higher than where we're trading, or at least that where we're trading. We can probably run some math and work through that. As we get out on the road, you might slip that into a slide. We're going to have to work with counsel on that. I think the broader message is we're in a pretty good spot. Basically, we were taking projects last year that already had a fixed cost associated with them in the Phoenix, in the Pompano area, and we were pushing in new volumes on a fixed cost structure.
When you push those volumes into PDP, and by the way, take the capital out, which that capital resided in the reserve report last year, you're going to get a pop on the PV-10 aspect of it. I think that's what you saw here. I think it's going to be able to withstand $5, $6 of an oil price drop or $10 of an oil price drop on that PDP layer.
Sure. I know you outlined in the earnings release some of the larger projects expected online over the next several months. What about the ongoing workover and recompletion projects? How much additional production could those activities add, say, per quarter throughout 2019?
Again, something else we didn't guide. I don't want to guide today. I will just tell you that our expectation is typically, we spend probably around 15% of our capital program on those projects. I think there's been years where that can deliver annually 4,000 barrels a day. There's been years where that delivers annually 2,000 barrels a day. Its goal is to do two things. One, offset our corporate decline generally, then help us manage the profitability of those assets, which ultimately helps us manage the P&A. We haven't put out quarter-to-quarter guidance. We can think about, I think as we move into the year, we can talk about looking back and seeing how that program's gone. It's a little early to kind of address what we're doing in 2019. Our team works very hard on that.
I mean, for example, they're working very hard on some of the assets we bought in Ram Powell and in Green Canyon 18 in the last year. I think as we get further into the year, Richard, we might come back and revisit how some of those projects are going so you have a better sense of how they can affect the model. I think we've always gotten a pretty good bang for our buck on that asset management program.
Well, good, Tim. That's all from me. Thanks a bunch.
All right. Thank you for your questions. All right, Richard. Thank you.
Our next question today comes from Subash Chandra of Guggenheim. Please go ahead.
Good morning, Tim. I was just curious if we could use a placeholder assumption for a typical Zama well in terms of productivity or EUR, or do we need to wait for the DST?
We're going to need to wait. I mean, that's exactly why we're doing it. I think, you've been out here a while, I think understand and modeled Gulf of Mexico companies before. What I would submit is a couple things. When you think about the economic model here, being in shallow water is really the gift of the project. It allows us to have physical platforms. It allows us to have dry trees. Then we'll still sort out as we do the pre-FEED, what's the right way to get that oil and gas off the physical platforms and dry trees, and we're working through that. The point of all that is, you ultimately will see a development program that has a drilling rig, a platform rig, I think these wells are going to get quicker and quicker.
There's one thing that I mentioned in my remarks that I think I really want you to hone in on, is our team is sorting out how to drill wells out here. We really think when we get this thing developed, they're going to go quicker and quicker. Look, you can go get on our website, you can see the log, you can think about that section, appropriating that section in 80-foot intervals, in 100-foot intervals, in 120-foot intervals, whatever it requires each time we drill a well. Then the question is, what's going to be the deliverability of those intervals? We know we have good rock properties. I mean, we're in a pretty good spot just because it's in, A, I think we're going to have good deliverability results, really, B, we're in shallow water, dry trees.
There's nothing that's going to have a serial number of 001 on this project. I mean, it really is like going back in time in the U.S. Gulf of Mexico, I think that's what makes the economic model exciting. As we get those results, we'll pass them along, obviously a little too early. That's exactly the goal of the appraisal, to be able to come back and help you build out those, for us to provide that guidance and for you to build out those models.
Yeah, terrific. Just a question on FID, your first half 2020. What is sort of out of your control in order to deliver that timing? For instance, what do we need PEMEX to do? You talked some things on unitization, just some color there.
Yeah. That question came up earlier, and it's a good question. Obviously, again, we'd like to see them drill a well here that we know they're working hard on that. I think the good news about what we're trying to do here is this wasn't one where it's adversarial. It's not something where we're holding our information close to the vest, and we would expect them to hold their information close to the vest. I would just reiterate that working with our partners and putting together the pre-unitization agreement was a very important milestone, so that while we had a sense there might be some delays on their side, they have a lot of leases, a big capital program. We didn't want to delay what we were doing.
That is a little outside of our control, but I think we're managing that well through the work group that we've set up together, through our active communications with our partners and PEMEX, and the data sharing that the pre-unitization agreement requires. I'd put that out there. From a development plan perspective, we would submit a development plan to the federal government. Working on that development plan and working on unitization are concurrent activities. They're not sequential. We need to submit that and have that get approved. We've seen those development plans get approved. Hokchi Energy's had one approved. Eni's had one approved. Fieldwood's had one approved. We've seen the approval of those plans in both administrations. Again, not inside our control. There's a couple things that aren't as in our control as what we're doing right now.
We haven't been delayed. I get questions from time to time, and I would almost throw one out there. Do we have delays with the change in administration? We have not had any. We anticipate that everyone's working in the best interest of the goal, which is to achieve production as fast as possible. Can all that come together in what we hope will be the first half of the year 2020? It certainly could. Could some of those things outside of our control create a small delay? Again, it might as well. That's balanced by the fact, though, that we are in shallow water, and what we're going to be doing on the development scheme isn't as complicated as maybe some other water depths. All of that's kind of out there as you think about that distance to first production.
All right. Yeah. Gotcha. A lot of ways, I guess, to mitigate the risk. Just a final follow-up on that. I'm just sort of curious how much of it's dependent on the PEMEX well. It sounds like-
Well-
you can do a lot of stuff around it, but you know.
Yeah. Look, if you're asking the question, do I think amplitudes work, do we think that after we have four penetrations, do we need to see it to know what we have? I think we would suggest the answer is no. I think the question is, what's the appropriateness of having that well in play when you work on a unitization? Is there a workaround? We'll cross those bridges as we get there. Again, we have a good work team. We have a lot of confidence in what this discovery is and what it ultimately will provide for the partnership provide for the government, and how meaningful it is in the economic reforms. Our focus is getting it on first production. I think when you work on unitizations, you've got different elements of what are the initial equity splits and what are the redeterminations.
We'll just have to work through the timing of the data collection and how all that fits into a unitization discussion. Generally, you like both sides to bring that active data to the table so that we can develop this in a responsible, combined way. Admittedly, with four penetrations on our side, you start to get pretty confident in what you have. We're just going to have to go through the year and see where PEMEX ends up.
Sounds good, Tim. Thanks.
All right. Thanks for the question.
Our next question comes from Gail Nicholson of Stephens. Please go ahead.
Good morning, everybody. Thanks for squeezing me in. I'm just looking at your price realizations, definitely stronger in the four Q. Was that all just driven by Brent- WTI being wider than the previous three quarters, or is there something other factors that are contributing to better realizations in the fourth quarter?
Yeah.
It's primarily due to the increase in commodity price in general. Year-over-year, quarter-over-quarter, our production has continued to hold in. Kind of the combined of that.
Yeah. We might have been a touch oilier
Yeah
in the fourth quarter than previous quarters, I think it's right. It's really more a widening of the basis differential.
Again, if there's
That's been great.
Yeah. There's some mitigating factors back there on why there's widening and what the demands of the oil. You've got sanctions in Venezuela, we certainly don't want to comment on that. I do think you've seen a little more of that widening in the first quarter. How long that stays with us is not something that we would pretend to guide or forecast, but I think it's interesting that we have it, and we're always happy to have it.
Along those lines, thoughts of seeing that widening. Is there any thought about trying to hedge that specifically in order to capture that, or just in general, looking at your philosophy on hedging strategy, has any of that changed since you guys have become a public entity?
Actually, in general, our hedge policy really hasn't changed. We've always basically hedged to secure our capital projects and what we've got planned for the year. We usually do that ahead of time. Like I think we've disclosed, we're hedged this year north of $55, which is the pricing that we've used in our guidance. As far as basis differential hedging, we are looking into that. It's a risk that you take when you go down that road. However, I think the risk-reward is something that we need to look at closely as we find ourselves consistently in a positive position.
Yeah. I would compliment on as well. Again, our hedging philosophy is just to beat the underlying plan that helps us maintain the capital program and maintain the free cash position we want to have. If we can beat that, then we're in the market. In terms of basis differential, you also want to make sure you have a liquid market.
That's right.
I think that it needs to evolve to where you're comfortable that there's a liquid market. To be sure, if we think it benefits our base philosophies, we absolutely look into it.
Okay, great. Thank you.
All right. Thanks, Gail.
Ladies and gentlemen, this concludes the question and answer session. I'd like to turn the conference back over to the management team for any final remarks.
Thanks, operator. Look, we appreciate all those questions, and thank you for having interest in the firm. The team will reiterate 2018 was transformative just in the fact of not only moving from our historical private status into the public domain, but really more importantly, integrating the companies, integrating the opportunity set, pooling folks together in the culture that we think we've created at Talos that focuses on shareholder value and generating free cash flow. We're hyper-focused on maintaining the discipline that got us to this point, moving that forward. We appreciate everybody's interest. We look forward to continuing down the road of how we turn out in 2019 and beyond. We look forward to talking to everybody next time.
Thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.