Talos Energy Inc (TALO) 2018 Q3 法說會逐字稿

Good day, and welcome to the Talos Energy Third Quarter 2018 Earnings Conference Call and Webcast. (Operator Instructions) Please note this event is being recorded.

I would now like to turn the conference over to Mr. Sergio Maiworm, Investor Relations. Mr. Maiworm, the floor is yours, sir.

Thank you, operator.

Good morning, everyone, and welcome to our third quarter 2018 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, our Form 10-Q for the quarter ended on June 30 filed with the SEC on August 9, 2018, and on Form 10-Q for the quarter ended on September 30, 2018, which we filed with the SEC yesterday. Any forward-looking statements that we make on this call are based on assumptions as of today, and we undertake no obligation to update these statements as a result of new information or future events.

During this call, we may present both GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday's press release, which was filed with the SEC yesterday, and which is also available on our website at talosenergy.com.

And now, I'd like to turn the call over to Tim.

Thanks, Sergio, and thank you, everyone, for joining our call.

It has been 6 months from closing the Stone Energy merger, so it's been exceptionally busy, not only continuing to integrate the companies organizationally, but bringing forward the potential of the 2 companies operationally. I think the third quarter showed that potential, which included increased production, drill bit success, prospect inventory growth and multiple value-adding transactions while continuing to generate free cash flow and decreasing our annualized leverage ratio.

As a reminder, and Mike will discuss specifics as he walks through the information, we continue to show 2 sets of values in our earnings release. One, year-to-date -- one is on a year-to-date basis. You'll see GAAP values and pro forma values. And the GAAP values include the legacy Talos assets for the entire year together with the Stone assets from May forward, including the Ram Powell asset. However, the most 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 on a pro forma basis from the beginning of the year, adding Ram Powell from May forward. The good news is all these assets were -- in the May closing are in the third quarter values, so it's a good, clean quarter from a reporting perspective.

The 2018 annual guidance that we provided upon closing the Stone transaction was provided on a pro forma basis. So for example, our annual net production guidance on a pro forma basis was 49,000 to 53,000 barrels equivalent a day for 2018 and our net pro forma production for the first 9 months of the year has averaged 52,100 barrels equivalent a day, with the third quarter averaging 54,900 barrels equivalent a day.

In the 6 months post-closing, which represents Talos' first 6 months as a public company, we've enjoyed meeting with current and potential investors and research analysts around the country. We posted a link to the investor deck upon closing in May and we'll update that presentation later this week. Like the first deck, and because of the still brief history as a public company, it's a lengthy deck and will hopefully provide more color around how we think about our core areas in the project inventory, both in and around our U.S. Gulf of Mexico assets and the exciting discovery and additional inventory we put together on offshore Mexico. So we would encourage you to take a look.

As we begin to discuss the third quarter, it's likely worth reminding listeners of our expectations for the year, keeping in mind that these are all pro forma values.

Our annual guidance of expected production was 49,000 to 53,000 barrels equivalent a day with a capital program of $430 million to $450 million and the expectation of generating free cash flow throughout the year.

We will discuss our current expectation versus guidance further in the call, but I'd just like to say here that we expect to finish there year towards the upper part of our production guidance and the bottom part of our CapEx guidance.

In the first 9 months of 2018, we've averaged 52,100 barrels equivalent a day with the adjusted EBITDA after hedges of approximately $425 million and CapEx of $310 million, inclusive of P&A in the first 3 quarters. So solid execution so far, but as I've mentioned, I think the third quarter show great examples of what we're trying to achieve as a firm. So some high-level highlights of the third quarter and then we'll get into more detail.

Production in the third quarter was 54,900 barrels equivalent a day, which is 78% oil liquids. That value does include 400, so 400, barrels equivalent a day for the quarter, which represents only 1 month from the recent Whistler transaction, which we'll discuss in more detail. However, it does not include 3,100 barrels equivalent a day of production that was deferred due to a tropical storm in the third quarter and an unplanned downtime event in the Helix-Producer 1, which is the host facility for our Phoenix Complex in the Green Canyon area. Although any downtime in our biggest asset is certainly felt, we account for some downtime, particularly during hurricane season as part of our guidance.

Adjusted EBITDA for the quarter, inclusive our hedge settlement, was $157 million for a netback EBITDA margin of $31.08 per BOE, while our unhedged adjusted EBITDA was $198 million for a netback margin of $39.15 per BOE, both an increase from the second quarter.

Capital expenditures for the quarter was $110 million, inclusive of P&A. Our liquidity position remains strong at $419 million at the end of the third quarter. And the third quarter adjusted EBITDA-to-debt ratio is 1.1x.

Both wells drilled in the third quarter were successful, and we will receive 2 more rigs in the fourth quarter.

In the August federal Gulf of Mexico-wide lease sale, we were the fifth most active bidder, gathering a total of 75,000 additional acres at an average acreage cost of $71 an acre in both deep and shallow waters with an emphasis of adding drilling inventory that can produce through our owned infrastructure or infrastructure we have access to, to enhance the prospect economic.

We bought another key asset in infrastructure in our Green Canyon core area. We announced a historical Pre-Unitization Agreement ahead of the approval of the appraisal plan for our Zama discovery in offshore Mexico. And also in offshore Mexico, we announced the first cross-assignment between 2 offshore production-sharing contracts as we traded 25% of our participating interest in Block 2 for a 25% participating interest in Block 31 immediately through the south of our block which will allow for more efficient development of the combined acreage.

We have 4 core areas, and I'm going to walk through these operational highlights in a little more detail by each core area.

The Mississippi Canyon core area includes the Pompano, Amberjack and Ram Powell field, and had a total net production of 22,000 barrels equivalent a day in the third quarter. We brought on our Mt. Providence well in the third quarter, which was drilled in the first quarter. This well came online at 4,200 barrels equivalent a day gross, 3,700 barrels equivalent a day net, ahead of our guidance.

We continue to be very excited about the Ram Powell asset, which we bought in the second quarter. It averaged 6,100 barrels equivalent a day net in 2017, but averaged 8,400 barrels equivalent a day net in the third quarter of 2018 after positive responses to several asset management projects, which include acid work and tubing changeouts. We also recently picked up additional exploration acreage around the asset as we begin to develop drilling inventory that can be tied into the facility. Also, we're participating in the potentially high-impact King Cake prospect in the fourth quarter where Murphy is the operator and we have a 12.5% interest.

The Green Canyon area, which includes the Tornado field and the broader Phoenix Complex, accounted for net daily production of 16,800 barrels equivalent a day net to our interest, taking into account the HP-1-related shut-in which deferred 2,400 barrels equivalent a day.

On the M&A front, we bought a small operator called Whistler Energy whose principal asset is in the Green Canyon 18 Field which we will now operate approximately 15 miles north of our Phoenix Complex. Green Canyon 18 was an old Exxon field that has produced over 100 million barrels equivalent and is currently producing 1,800 barrels a day, gross -- equivalent a day gross and 1,500 barrels equivalent a day, net. Keep in mind, only 400 barrels equivalent a day net was accounted for in the third quarter as the transaction closed at the end of August.

Our net acquisition costs were $14.5 million, and we added 3.1 million barrels equivalent of 100% proved developed reserves. So the transaction metrics are attractive. We're adding reserves for under $5 a barrel proved, and in this case, proved developed, and production for under 10,000 of flowing barrel equivalent.

More importantly, we pick up an underutilized facility with a capacity of 30,000 barrels a day and 30 million cubic feet a day, which can also be upgraded in an area where we have quality 3D and recent reprocessing. So we're actively pulling together new prospects with this facility, including drilling ideas in the purchase lease position and also a series of prospects we recently picked up in the federal lease sale.

On the drilling side, we recently took delivery of the Noble Don Taylor drillship to drill 2 low-risk opportunities, the Tornado 3 and the Boris 3 wells. Those wells will be drilled and completed at subsea tiebacks and hooked up to the HP-1 facility by the beginning of the second quarter.

Gross unrisked rate expectations for Tornado 3 well is between 10,000 and 15,000 barrels equivalent a day. Net would be 5,000 to 7,500 barrels equivalent a day. And the Boris 3 well, our gross unrisked expectation is 3,000 to 5,000 barrels equivalent a day net to our interest 2,800 to 4,600 barrels equivalent a day.

Keep in mind, though, the HP-1 goes in for its mandatory dry-dock in the first quarter of next year for 45 to 60 days.

Our shallow water and other core area accounts for both legacy shallow water assets and also some small deepwater assets. This core area accounted for 16,100 barrels equivalent a day, net to our interest in the third quarter. We like to keep one rig running continuously on this acreage set, and we'll continue to do so through 2019. This allows us to add quick production and manage the long-term profitability of these assets, which also helps us manage our P&A spending.

We announced in the second quarter the success of our Ewing Bank 305 A20 well, which targeted both shallow field pays and deeper exploration potential. That well came online in the third quarter at a rate of 2,200 barrels equivalent a day gross, 1,800 barrels equivalent a day net, ahead our expectations. The rate was from a deeper exploration target that worked which will set up an additional location potentially for 2019. We then moved the rig to drill 2 wells in the Main Pass 72 field. Both wells have worked, and we will complete and hookup both wells in the fourth quarter with an expected combined rate between 1,000 and 1,500 barrels equivalent a day gross, 800 to 1,200 barrels equivalent a day net to our interest.

So that finally takes us to our offshore Mexico core area, which is certainly an area of great interest and an area where we're very busy in the third quarter.

First, related to our Zama discovery. Keep in mind, Zama is part of Block 7 production sharing contract, which covers approximately 115,000 gross acres in 500 and 650 feet of water, and we have a 35% participating interest.

We signed the country's first Pre-Unitization Agreement with Pemex, which allows the companies to share data during the upcoming drilling campaigns, and as a mechanism to reach consensus on equity splits as we negotiate the broader unitization agreement next year. We also announced the approval of our appraisal plan, and we recently received our final drilling permits. So we're ready to kick off the appraisal program in the fourth quarter -- actually, in the coming weeks with the Ensco 8503 rig.

There are 3 penetrations expected in the appraisal program on Block 7. We will first go downdip to look for the oil-water contact and then drill 2 straight holes, one to the north of the original discovery well and one to the south. The program includes conventional coring, flow test and other data gathering that will allow us to build a working model used in our feed studies and allow us to get to a final decision -- investment decision regarding the development between the end of 2019 or early 2020.

In the first penetration of the appraisal plan, we will also take the well deeper and look for a deeper target called the Marte prospect, which has a geophysical response similar to the Zama discovery, although with a different trap style but can be tested inexpensively as part of the appraisal -- the initial appraisal well.

We expect to spend $75 million to $80 million net to our interest in capital in the appraisal plan from the fourth quarter of 2018 through the second quarter of 2019.

Finally, on Block 7, we recently completed another reprocessing project with the velocity information we received from the Zama well, and we're really excited about the breadth of opportunities we're putting together on the remainder of the acreage, some of which will be highlighted in the upcoming investor deck.

Our other acreage position in Mexico is called Block 2, which is a production-sharing contract that covers over 50,000 gross acres and is in much shallower water, between 100 and 150 feet. In this block, it took us a little -- lot longer to reprocess and condition the seismic we received from the government once we were awarded the block. But when we did finish, we quickly developed an inventory of prospects, some of which were solely on our block, but others which were on the neighboring block to the south. During that same time, as we were reprocessing the data, the acreage to the south of us was awarded in competitive bidding to Pan American Energy, who's also an active operator in offshore Mexico. This acreage is known as Block 31, and it covers an additional 60,000 gross acres. After extensive discussions with Pan American, we recently announced the first-ever offshore Mexico cross-assignment trade where we will help facilitate pulling together all of the ideas that our teams have put together into one potential development. We will go from owning 50% participating interest in Block 2 to owning a 25% participating interest in Block 2 and Block 31. Pan American, because of its -- because of their 75% interest in Block 31, will remain the operator of both blocks. This trade doubles the acreage set we can explore on and more than doubles our inventory. And if we have success, it really opens up the material upside between both parties. It also assures the acreage will be developed quicker and potentially in a more robust way than we would -- it would be if we were developing the acreage separately.

The first prospect called Acan will be drilled at the end of the second quarter, and we will continue to drill the inventory for the bulk of 2019.

So it was a busy quarter, one that we're very pleased with, both in terms of our operational execution. It's always critical for the first year after a transformative merger, but also our ability to stay focused on deal execution, maintaining a highly commercial approach that we construct production and exploration deals, so we'll be able to grow the business organically in a disciplined way going forward, which is by managing what we think are a nice mix of low-risk and high-impact projects.

By having production increase on a pro forma basis quarter-over-quarter, having our drilling inventory increase while we continue to produce free cash flow, we think the third quarter was an example of how we want to execute our strategy.

As an update on our guidance for the full year on a pro forma basis, we expect to be at the top of the 49,000 to 53,000 barrels equivalent a day production range for the year. For our direct operating expenses, we expect to be close to the midpoint of our $170 million to $180 million guided range. Work-over and maintenance expenses will likely be a little above our $49 million to $54 million guided range annually. G&A is also expected to be close to the midpoint of our guided range of $57 million to $62 million. And finally, we expect CapEx to be on the low end of our $430 million to $450 million range.

With that note, I'll hand it over to Mike Harding to walk through the third quarter.

Thank you, Tim.

Talos continues to focus on creating shareholder value and remains committed to continue to generate free cash flow, moderate organic growth, full cycle return, financial flexibility while maintaining robust liquidity.

As Tim mentioned, this quarter is the first full quarter we are reporting the results of the combined company as our combination with Stone closed in the middle of the second quarter and resulted in partial GAAP result.

Talos' consistent, exceptional operational execution continues to set us apart. We continue to organically increase production, manage our P&A obligation and underspend our capital program while consistently delivering on our project execution. Talos also continues to strengthen its balance sheet. Based on the annualized results of the third quarter, our net debt-to-EBITDA ratio is 1.1x. Also mentioned, at the end of the third quarter, we had $419 million of liquidity. This includes $329 million of available capacity on our credit facility and available cash on hand of $90 million.

We held our RBL redetermination meeting on October 31, and we expect to post the result of that redetermination the week of November 12.

Now I'll turn to the results of the quarter.

Talos' average daily production for the quarter was 54,900 barrels a day, which surpasses our expectations despite 2 downtime incidents, one involving the Helix-Producer 1 where the owner of the ship had to address operational issues on the vessel, and this required us to shut-in the Phoenix field for 12 days. The second downtime occurrence resulted from Talos' prudent decision to evacuate nonessential personnel and shut-in certain assets for 3 days during Tropical Storm Gordon.

Third quarter total revenues were $282.9 million, underpinned by robust production and a strong commodity price backdrop. Our average realized oil prices continue to be above WTI as our positive basis differentials more than offset gathering, transportation and other deduct from our realized prices.

Oil continues to be approximately 70% of our production, but accounts for around 88% of our overall revenues. As we continue to allocate capital to our organic drilling project, we expect our oil exposure to continue to grow in the future.

Our direct operating expenses were $8.33 per BOE for the quarter, which is down $0.37 per BOE from the second quarter of 2018 and $1.35 per BOE from 2017. Third quarter includes the Green Canyon 18 production facility which was added at the end of August as part of the Whistler acquisition.

We continue to be disciplined in our improvement processes and maintain a continued focus on efficiency. G&A for the quarter was $21.7 million, which is inclusive of approximately $7.4 million of transaction costs related to the Stone Combination and $2.5 million of additional personnel costs associated with the integration of Stone and Ram Powell.

As reported, G&A is $4.29 per BOE, but $2.87 per BOE when transaction-related costs are normalized.

Workover and maintenance came in a bit higher this quarter at $25 million. The expenses are primarily related to activities on our fixed structures, which included approximately $7.6 million in repairs on the South Marsh Island Block 130 and non-recurring expenses in the Phoenix field as a result of the buoy drop during the shut-in.

Maintenance projects are typically more prevalent in the second and third quarters of the year as we typically have better weather and more working daylight offshore.

On the price risk management side, we recorded an expense of $53.3 million for the quarter, which includes $40.7 million of cash settlement and $12.6 million of unrealized noncash expense resulting from the change in the fair value of our open derivatives at 9/30.

Capital expenditures for the quarter were $110 million, inclusive of plug and abandonment. On a year-to-date pro forma basis, our capital expenditures have been approximately $310 million.

The majority of our remaining capital budget for this year is expected to be utilized on our U.S. drilling and completion activities, which are primarily the drilling of Tornado 3, Boris 3 and King Cake deepwater wells, the drilling and completion of 2 Main Pass 72 shelf wells, and then we will commence the Zama appraisal campaign in Mexico in the fourth quarter.

Talos expects to come in at the low end of guidance as previously discussed, between the ranges of $430 million and $450 million.

This concludes the prepared remarks on the quarter's financial data, and I'll now turn the call back over to Tim.

Okay, operator, if we could, let's open up for questions.

(Operator Instructions) The first question we have will come from Jeff Grampp of Northland Capital Markets.

I was curious, Tim, maybe if I can kind of front run a little bit the slide deck that you guys will be putting out with an updated inventory or some color there. But as you guys kind of look into '19 on the deepwater side of things in the U.S., any particular areas that are exciting to you that you guys are kind of maybe primed to go after as you guys look in the '19 deepwater program?

Yes, so we've -- I think we talked about in the call that we've got the Don Taylor drillship for at least 2 wells. We've got an option to do something else with that ship. And I think a lot of it is -- I would tell you one of the reasons we don't want to guide that too soon is if you were sitting in my shop right now, you would see the tug of war that goes between new leases we picked up in the lease sale. I'd tell you, the Ram Powell area that we're excited about, even the Whistler idea has some ideas right around that leasehold. And so kind of as we speak -- and then there's also a little business development on the exploration side. I think we've talked about that's an area where we're very active in the business development space. So we're -- as we speak and as we prepare for our fourth quarter board meeting, we're trying to figure out what's the right optionality, when and where to allocate dollars against those ideas. And so, a little premature. Again, I think what you can rely on with us is -- and you can see it in the deck that's out there right now and you'll see it in the upcoming deck is we've got -- we try to stay within the knitting of obviously where we have a lot of seismic and where we have facilities. And that's something you can count on. And then we really just look at rig optionality, permitting, that has a lot to do with it, Jeff. I mean, we just picked up these leases, even though we've got an idea how quickly can we do -- get the permits ready, but we've got probably a little more than we could say grace over. So we're excited about putting that out there. But again, we'll probably get through this year to firm up those plans and then come out with that guidance in early January.

Okay, great. That's really helpful. And I guess, by our model, looking into '19, you guys will be in great shape to continue generating some nice free cash flow. Any particular plans, should we just generically think about continued leverage reduction, maybe paying down the bank line with that or just generically wondering how you guys view potential uses of that free cash.

Yes, I mean, look, the ship goes in every 2.5 years. Obviously, we had a little downtime events. So arguably, it's time for the ship to go in and get some upgrades. And that's an event that although painful when it happens for the quarter, it happens and it helps the long-term value of that asset. It's an asset we believe in for years to come. But because of that, it's hard for me to kind of envision where that really -- obviously, we think we're going to manage this thing inside free cash flow, but will I be in a situation where I have a material more amount, if you will, of that free cash flow. I'd like to make sure that ship comes back and then we hook up the 2 wells we're drilling in the Phoenix field, and then I think we're in a better position to have that discussion. As a general matter, I think it's a good time to be thinking about the M&A market. Obviously, we've done 2 transactions this year. We might want to do a little more in Mexico. Certainly, we can always think about debt reduction. I think we've got a nice group of options to think about what to do with that available cash. And I think we're in a position where we want to try to continue to build diversity around our assets. And so I think we would focus on where we can make those investments, if not paying down a little bit of the revolver.

Okay. Great. And if I sneak can one more, and you kind of touched on the M&A side. You guys have obviously had a very busy year, but would you say you're largely kind of past the integration phase of a lot of the things you want to have accomplished and you guys are now kind of back in the game and can continue to look at accretive acquisition opportunities of scale for you guys?

Yes, look, I think we did 2 of them while we're in the integration stage. So the integrating of the businesses didn't stop us. And I think I made that note in the call, it didn't stop us from trying to be commercial and trying to focus on deals and focus on transactions and not allow ourselves to be on the sidelines at a time where we think there's good opportunity in the marketplace. So I think where these guys probably could use a little bit of a Thanksgiving holiday, and I want my team to get out there and have a Thanksgiving holiday, is they've done a hell of a job kind of combining the real duties of integration and getting it right and then maintaining a presence in the marketplace. You still saw some transaction costs in the third quarter. We're not done yet. Obviously, we integrated the business that had a different corporate headquarters in a different town, and that's not always easy. But I think we've plowed through that. I think everybody's done a great job. We've got some great employees that came over from the Stone side. So we'll be in that market. I mean, my first focus is always to build this business organically, but there's things to do in that market. We have faith in our ability to use our seismic find upside. And so we're just going to kind of continue to be in that market. But I do think you see the integration, we're starting to be on the tail end of that integration, and we're very happy with what we have as a result of it.

Next, we have Marshall Carver of Heikkinen Energy Advisors.

Regarding the production at the high-end of the range, if you had to say what that was due to, would that be better well performance, lower downtime, better well timing? Could you give some qualifiers around that?

Yes, so I think it's probably more -- but I think it's probably more on the performance side. Obviously, the Mt. Providence well came in a little better than we thought. Look, if you drill a shallow water well off of a shelf platform, it probably hasn't seen a well drilled in a good chunk of years and it comes in at 2,000 barrels a day, that's a pretty darn pleasant surprise. And so I think a little more on the well performance side. The downtime is just something that we always have to account for. It is one of the bigger challenges operating offshore assets. There is -- we're lucky to have a ton of infrastructure, but that does cause some downtime on some of those flow lines. And so you never know where that's going to end up. If you do a little better than that, you'll probably do a little better for the quarter. Obviously, we had a bigger event in the Phoenix field. But I would say the beat was really on some of the well performance on the new -- related to the capital program.

Okay. And a follow-up, with regards to the successful Gulf of Mexico shelf drilling, were those PUD locations or probable locations? And what would be the reserves associated with those 3 different wells?

Well, yes, so I think what I talked about in the call is we like to -- we have some shelf assets. A lot of those are legacy assets. We have a heritage of knowing exactly kind of what areas we like and where we think we can reprocess seismic data and have it be responsive to our efforts. And look, it's -- and one of the quickest ways to get production online is to drill wells off of those assets. And so I would say, we've drilled 4 wells this year. We talked about keeping a shallow water rig going really throughout next year. All 4 wells have worked so far this year. Two of those were PUDs, Marshall. Two of those we decided not to put on the books. So sometimes, it's just a judgment call, how many PUDs do we have on the books, do we want to maintain some flexibility, are we doing something that's maybe a little deeper, has just a touch more risk. It's appropriate to keep it off the books and just see how it comes in. We typically are looking for a shelf target. If we're off the platform between 1 million and 2 million barrels, regardless of whether it's a PUD, if we have a little deeper target, then maybe it's a little more than that. But I think the 2 PUDs were between 1 million and 1.5 million barrels gross. I think what's interesting about what we're doing in shallow water is where we can, we're looking for something deeper to go test. And so in that Ewing Bank well, yes, we were drilling through some field pays, and those field pays worked. But then we found that deeper target. That's the one that came in, in a couple of thousand barrels a day. And now, the team's got a couple more ideas related to that deeper interval. And as we think about our rig program, we might just shift some of what we're doing and go back to that asset in 2019 and look for that. So I think if we can debunk a myth that there's not things left to do on the shelf, hopefully, that program, so far, is doing that.

And next, we have John White with Roth Capital.

So you had quite a bit higher NGL price realizations in 3Q compared to 2Q. Is that a contribution from the Stone properties?

I don't know if we were -- we were, what -- 8%? And so typically, we've been running around 8% or 9%. So I don't know if the pricing, and I'd have to -- do we have any idea on kind of why the pricing's a little higher? From a content perspective, I think we've been running 8% to 9% consistently. Look, the Phoenix assets are rich on NGLs, the Ewing Bank asset might have been a little rich on NGLs as well, but Mike, is there any other...

And I think another factor is the fact that the second quarter only had Stone in it for just 2 of the months in the quarter. So yes, the combination of Stone, Ram Powell, and then in the third quarter, we also had a month of Whistler, I think that's contributing to the...

Yes, yes, I think you're exactly right. So Mike, I think, hit it there. So a full contribution of Ram Powell, which has got some rich gas in it and a full contribution of Stone's probably why you saw that tick up, John.

Yes, it's nice to have those heavier barrels. And on Block 2 offshore Mexico, when do you think that well will reach TD?

Well -- so what we're going to do on -- if you think about Mexico, obviously, the appraisal plan, we're going to have delivery of that rig here in the coming weeks. And admittedly, that's a lot of the focus, and we know why, and we're thrilled and always grateful for that discovery. But I think the Block 2 trade actually, to me, is a fascinating trade. We're in the last year of our primary term lease there. The block to the south is in the first year of its primary term lease, and we really have a nice mix of opportunities that go across both of those leases. The first well will be drilled in the second quarter. So we're working on that rig tender right now with Pan American. We'll wrap up that rig tender, then that well needs to be drilled probably sometime in the second quarter of next year. Then that rig stays there and executes a couple of things on our block and may go execute a couple things on Block 31. And that's really where you see the benefit of pulling everything together. So it would be a second quarter, late second quarter event, John.

(Operator Instructions) Next, we have Richard Tullis of Capital One.

I know it's not time for 2019 CapEx final budget yet, but given that you're at the low end of this year's guidance range, how do you see 2019 shaping up at this point?

Yes, well, again, like I mentioned in an earlier comment, I always -- when that ship leaves, you kind of wave at it and you really start counting the days down until it comes back. And although, in a typical dry-dock -- this is now our third dry-dock with this ship over the 6 or -- 5 or 6 years we've been out here. And in both times, we've got the ship back within the range, but I think you want -- the prudent thing to do is to make sure you're back and make sure you're running and then you can kind of adjust your plans. And that's exactly why we have the Don Taylor out there drilling 2 wells right now to have those ready to hook up so you can kind of come back with an immediate bang, if you will, on production. So we're going to take a cautious approach to making sure we have our plan set. We've got a good kind of initial first half of the year capital plans set, and we're having active conversations about the second half of the year. And so I think that's why, like I mentioned earlier, I kind of want to get through the rest of the year and look at the rest of the inventory. What's different in our combination, Richard, compared to maybe other calls you've listened to this week is we've really spent a lot of time in the last 6 months integrating Stone's portfolio and trying to make what makes the most sense on how to attack these ideas over the next 2 or 3 years. And I think we're going to roll all that out in Canyon. But needless to say, we've had a good quarter. We have a heck of a lot more confidence and faith on what this organization can do together. We're excited about what we're going to put together. So I think we feel pretty good about where we are.

That's fine, Tim. So January, you're looking to put out the full budget?

Yes, right. Right. That's exactly right.

Okay. You talked a little bit about the M&A landscape, and just trying to get an indication of what level of producing properties could be coming to the markets, say, in the next year. I mean, how do you see that plan out in the Gulf of Mexico over, say, the next 4, 6 quarters?

Yes, it's interesting. I think the Gulf is a place where certainly, there's still exploration activity. All the bigger companies are still exploring, they're still looking for targets. I do think, as we see some operators -- the traditional operators offshore make more commitments to launch or I think it leaves with a question of where do some of these properties that are producing sit in their portfolio, Richard. And our job is just to be available and be a very good potential counterparty to any offering that comes up. And sometimes you think a company may be in it for the long haul, and then they realize they're rationalizing 2 or 3 assets, you need to be available for that. So we -- we're just trying to make sure we understand the landscape, and we're not alone in that. Obviously, there's some good companies out there that are interested in buying assets in the Gulf of Mexico. And so we try to look at a full diversification of opportunities. It could be an expanded exploration opportunity, it could be an asset that's in our dataset, so it's in an area where we really have faith in what we're doing seismically. And so we'll take on maybe a smaller asset, and obviously, you can look at some bigger deals. But I do think there are potentially more assets on the market than there could be buyers for them. But look, I mean, there's -- yes, I think you've probably been on several calls this week and there's other folks looking at these assets. But the Gulf of Mexico universe has shrunk. I think there's good, really good companies out there participating on the M&A front, and we just have to stay patient and make sure we find the right set of assets.

Okay, Tim. And then just the last one for me. Any updates on what rough estimate might be for your PV-10 values, say, using midyear reserve numbers and current strip pricing considering where you're trading right now?

On the reserves?

As far as the PV-10 value goes associated with the, say, midyear reserves and current strip pricing.

Yes, well, look, I mean -- yes, I don't know if I didn't disclose it in a previous deck. I don't know if I'm prepared to disclose it on this call, Richard. But I think as you remember, at the beginning of the year, 151 million barrels, and the SEC proved number which, by the way, is $53, was $2.4 billion. I think if we use -- on that reserve set, which is 150 million barrels, if we use 65 and 3, you'll be somewhere around $3.2 billion. And so I think we'll just roll that forward and put in the adds and put in the revisions and kind of guide that later. But just going back to year-end, again, at $53, you were $2.4 billion, and at 65 and $3, just at normal flat price, again, at year-end '17 reserves, I think that's $3.2 billion. And you can go look at the enterprise value and make an estimate on where you think the value is. But anyway, that just takes you back to year-end.

Next, we have Sean Sneeden of Guggenheim.

Tim, I know you highlighted the economic value and uplift with infrastructure and how it helps to differentiate you on the M&A front, but could you talk a little bit about how -- any kind of potential need for more infrastructure as you go through the development program here?

Well, I mean I think as we look at -- as you can imagine, as we look at allocating capital next year, I think we start to ask the question of, "Hey, look, where do we have inventory? And where do we have some meaningful assurance that we can get this thing hooked up and hit the time lines?" And that's where -- as I'm thinking about a budget, if you can imagine, we've got a host of ideas. Where am I willing to take a little bit of risk on timing certainty because maybe the prospect's more impactful? That would be at an area maybe where I don't have access to the infrastructure. And where am I not willing to take that risk, and I want to make sure I can hit the timing mark. And so where infrastructure helps is in the planning process. It certainly helps with the economies of scale. And I think you've seen the chart. Obviously, if you own the infrastructure, you're drilling something with 10, 15 miles in the deepwater case or you're drilling it right off the platform in the shallow water case. The benefits of that are obvious, and we don't have to state those. At the same time, we may want to invest in something that's a little more higher impact that's going to take a little longer and have a little more breadth of uncertainty on when you're going to see those volumes. And so having an inventory that covers both of those types of ideas allows us to kind of make some decisions on where we can see certainty of timing and where we're willing to take a little risk because maybe it's a little more high impact. So again, as -- we like having the infrastructure, we don't have to have the infrastructure, but having that infrastructure helps us from a planning perspective.

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Okay. All right. Just make sure that wasn't on our end. Any other questions?

Sure. Maybe just one last one just on rig utilization. I think, obviously, that's kind of picked up since the beginning of the year. Are you guys seeing, I guess, any inflationary pressures, specifically on the rig side? And any concern around rig availability as you kind of start your forward planning for '19 and beyond?

Yes, look, so we -- if I go right now to last year, not a lot of inflationary pressure, and that's fine. I think that's allowed the offshore environment to recover a little bit. And look, I think we could use a little runway in that regard. As we move forward, I do think you're seeing the backlog grow. Obviously, there's less rigs in the Gulf of Mexico than there was. So yes, I'm a little more concerned about utilization. I think we can handle a little inflationary pressure. Obviously, we've got a bit of a commodity uptick, if you think about where we were a year ago, 18 months ago and a rig rate that isn't too dissimilar to where we were 12 months ago. So we can handle a little inflationary pressure. I think you can expect that. I think -- I'm more concerned about rig utilization. Look, offshore Mexico is picking up. I think you're seeing the rig we have -- with the Ensco 8503 rig we're using down there, very well could stay down there. Another rig can move down there. And so I think we have to be mindful of that and it's something we're trying to keep our eyes on.

At this time, it looks like we have no further questions.

Okay, so look, I want to thank -- yes, thank you. So I'd like to thank everybody for joining on the call.

Again, I think the third quarter kind of represents the potential of this business. We continue to be happy with the progress we're making and certainly happy about the integration process and pulling the Stone team over and getting them incorporated into the culture of Talos. And we're really excited about where we're going to be in the quarters and years to come. So thanks, everyone, again for joining and taking the time.

And we thank you, sir, and to the rest of the management team for your time also today.

Again, the conference call has now concluded. At this time, you may disconnect your line. Thank you again, everyone. Take care, and have a great day.