Talos Energy Inc (TALO) 2018 Q2 法說會逐字稿

Good morning and welcome to the Talos Energy second-quarter 2018 earnings conference call. (Operator Instructions). Please note this event is being recorded. I would now like to turn the conference over to Sergio Maiworm. Please go ahead.

Thank you, operator. Good morning, everyone and welcome to our second-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 would like to take this opportunity to remind you that our remarks today will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements.

Factors that could cause these results to differ materially are set forth in yesterday's press release, in our consent solicitation statement and prospectus that was filed with the SEC earlier this year on April 9, and in our quarterly reports on Form 10-Q for this quarter ended June 30, 2018, which we expect to file with the SEC subsequent to this call.

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 earnings press release which was filed with the SEC and which is also available on our website at TalosEnergy.com. And now I would like to turn the call over to Tim.

Thanks, Sergio, and thank you, everyone, for joining our call. Certainly the second quarter was historic for Talos simply for the fact that we're having our first public earnings call following the completion of the Stone combination as we integrate two strong offshore portfolios and two talented groups of professionals.

Just prior to closing the merger, we helped negotiate and approve Stone's transaction of the Ram Powell field, adding another core asset and giving the combined Company more scale, diversity and the ability to generate positive free cash flow after our capital program and current interest payment.

As Sergio mentioned, this earnings release will be different than those we will post in the future. You will see two discussions: a GAAP discussion which focuses on Talos only through January, through April, and then the combined assets for May and June and forward; and the pro forma discussions where we are focused on the legacy Talos and Stone assets as if they were combined for the full year.

As a reference on a pro forma basis from these assets, Talos and Stone's combined net daily production was 47,800 barrels equivalent a day for the full year in 2017. As previously announced by Stone at the time of the transaction, Ram Powell averaged 6,100 net barrels of oil equivalent a day for the full year of 2017. So that allows you to level set these assets.

In all cases, GAAP net pro forma for 2018, we only include the volumes of Ram Powell asset from May forward, so two months in the second quarter. All the assets will be fully accounted for in the third quarter moving on from there.

I would encourage you, as you have time, to take a look at the Talos introductory corporate presentation we posted to our website shortly after we closed the Stone transaction. It's a more detailed look into the history of the management teams we front, two previously privately held companies offshore with Talos now being our third company together.

The investment deck also provides details into the key assets and it provides production expense and CapEx guidance for 2018 and it sets several anchors for 2019. We expect to post an updated corporate deck this month ahead of our next round of conferences.

Referencing the deck and, because it's our first call, it's probably worth resetting the asset base. Year-end combined pro forma proved reserves from our assets is 151 million barrels, 80% in deepwater with a proved reserve value of $2.4 billion at year-end SEC prices. I remind you the yearend SEC price was $53.49, so, as you can imagine, the assets are more valuable with an updated strip.

80% of production in the pro forma assets are from deepwater with the remainder from our shallow water assets and over 90% of our production is operated. Not included in these reserves or production is our operated Zama discovery in offshore Mexico, which is viewed as a contingent resource at this point of its lifecycle.

Our core strategy in the US Gulf of Mexico is to use our infrastructure and more moderate seismic and reprocessing techniques to generate new asset management and drilling opportunities either on our lease position or within a reasonable distance that allows us to achieve superior economics by using our infrastructure to reduce the development cost in running high-margin barrels across what is generally fixed cost within our infrastructure base.

We have over 660,000 acres under lease in the US Gulf of Mexico with the key -- key assets are as follows: the Phoenix Field and the Tornado Field in the Green Canyon area, this is a series of subsea wells that flows back to the Helix Producer 1, otherwise known as the HP-1, which is a floating production unit; the Pompano and Amberjack Fields in Mississippi Canyon, which both are fixed platforms with dry trees and subsea infrastructure; and the Ram Powell field, which is a tension leg facility and has dry trees and subsea infrastructure.

We also have a series of shallow water assets including: Ewing Bank 305 and 306, South Marsh Island 130, East Cameron 346 and an assortment of other assets. And again, we highlight these assets in our introductory deck that you can find on our website.

In offshore Mexico we have approximately 165,000 acres through two production sharing contracts that are called Block 7 and Block 2 that we acquired after being the winner of the very first historic leasing round post energy reforms in 2015. We drove the world recognized Zama discovery in July of 2017 and we will discuss our efforts to appraise that discovery on this call.

If you look at the full-year guidance, we guided 49,000 to 53,000 barrels equivalent a day of net daily production for 2018 on a pro forma basis with Talos and Stone for the full year and Ram Powell assets from May on. We also guided our capital program between $430 million and $450 million on a pro forma basis for 2018.

The capital program consists of several key components. First, we always have plugging obligations we manage in the Gulf of Mexico. They were a little more than we like in 2018 as a result of the combination with Stone, but we expect that that value as a percent of our total capital will decrease with time.

We also have normal leasing costs, [GAG] infrastructure cost and capitalized G&A. Beyond that we have three levels of capital that we focus on adding production and value. First are what we call our asset management activities, which is our first line of defense in managing our corporate [decline]. It can be adding new production through changing out submersible pumps, gas lift design or recompleting wells to a shallower zone.

All activities expected to add rate reserves and we typically try to do 10 to 12 of the 20 of these activities a year. They are typically smaller impact projects than drilling projects but they have good rate of return and low production conversion costs. And then we have two types of drilling opportunities, those that can turn into production quickly, some are PUD locations and others are low risk. But outside proven and probable they can tie back to our own infrastructure or infrastructure we have access to.

Finally, we'll use part of our capital program to drill moderate risk but high-impact projects that have strong economics and can materially increase our NAV.

So with all of this information as a backdrop, we are going to talk about what we averaged and what our results were in the second quarter and year to date. So in the second quarter we averaged 51,600 barrels equivalent a day, and year to date we've averaged 50,700 barrels equivalent to date net to our interest. On an EBITDA basis in the second quarter we had $128 million of EBITDA and year to date we've had $269 million of EBITDA.

And the second quarter was impacted from a new well in our shallow water drilling program and then a series of recompletions which are PDNP conversions to PDP. We call that asset management, again, talked about that earlier; we're going to talk about that here in just a minute as well.

Now some of the things that we have done that are not in the second quarter or year to date that will be reflected in the third quarter going forward are some of the activities that we would consider recent development. For example, we took advantage of a window in the rig market and, because of some good planning and quick response by our operations team; we were able to bring online the Mt. Providence subsea well which flows back to our Pompano facility.

This well came online at an initial gross rate of close to 4,000 barrels equivalent a day and a net rate of 3,370 barrels equivalent a day, which was on the high-end of our guidance, so we're pretty happy about that. The well turned into production six months after it was drilled, which is exactly the kind of turnaround we want from these near infrastructure subsea projects.

It's also important to note, as with generally all of our assets, that we sell this oil at a premium to WTI so it has a nice impact. We have several other deepwater projects that we will start this year. We expect to drill two wells in our Phoenix/Tornado area in the fourth quarter of 2018 and into the first quarter of 2019. The first well will be Tornado 3, which is the third well of our Tornado discovery, followed by the Boris 3 development well in the Phoenix Field.

Both these wells should be online in early second quarter of 2019. So again, subsea drilling infrastructure is available to us. We will drill those wells in the third -- excuse me, in the fourth quarter of 2018, two wells back to back with production online in the second quarter of 2019, which is, again, what we hope for when we are utilizing our own infrastructure. We are also partnering with Murphy at 12.5% working interest at their high impact [Kincaid] prospect which will begin late third quarter or early fourth quarter.

In shallow water we continue to be active with the Ensco 75 rig. After it drilled the first successful well in Ship Shoal 224 we then moved into and drilled a well in Ewing Bank 306 that turned out better than we expected, finding three development targets and then we took the well deeper and found two deeper pool exploration targets.

We expect to bring on the first completion, which is in the deepest sand, in the third quarter at a rate between 1,250 and 1,500 barrels a day -- barrels equivalent a day gross, which would be 1,000 to 1,200 barrels equivalent a day net to our interest. The project reflects exactly what we're trying to do in these assets. We bought this field in July of 2014 and production was as low as 500 barrels a day equivalent gross that year.

So through our own asset management projects, which are those projects I described earlier that don't include drilling wells, we were able to increase production in this field to over 2,500 barrels a day equivalent gross last year. We reprocessed seismic data, we developed some drilling targets and the Ewing Bank 306 A20 well, which I just discussed earlier, was the first of those drilling targets and it looks like it could set up several more drilling targets over the next several years.

In Mexico we've made a great deal of progress in praising our Zama discovery. As a reminder, the Zama discovery, we logged over 1,100 feet of gross pay with US Gulf of Mexico type of rock properties as this is an upper Miocene target. The upper Miocene is a geological interval that has been prolific on the US side of the Gulf of Mexico.

The discovery is 90% oil. We expect our appraisal plan to be approved in the third quarter and drilling operations will commence before year-end. We will use the Ensco 8503 rig, which is the same rig that drilled the original Zama discovery.

Our goal in the appraisal well is to drill a location down dip of our original location. We will look for an oil water contact there. We will then move up dip and drill two wells generally on strike geologically but to the North and South of our original location. The goal here is obviously to narrow in our expectations of reserves, be able to provide better data for our feed study and ultimately get closer to a final investment decision, an FID, by the end of 2019, maybe early in 2020.

Once we reach FID we think we can get production online between 2 and 2.5 years from that decision and that milestone point. What enables us in our minds to be able to do this fairly quickly is the fact that we have such prolific discovery in 520 feet of water, which certainly allows us to think about putting fixed infrastructure here and doing so in a way we have done in the past in other development projects.

What we've also talked about in our earnings release and what's been discussed generally is we negotiated the first pre-unitization agreement. As some of you know, Pemex owns the lease next-door. The federal government of Mexico put some general unitization guidelines out there for operators to look to. What our pre-unitization agreement does is it tightens up the framework in which we will start unitization discussions.

There has not been any agreement on equity splits here. That will take some time and it will require some appraisal. But the pre-unitization agreement allows us to sit at the table and have some distinct rules that will govern how we have these conversations. And that agreement is in review with the Mexican federal government before it is finally approved.

A couple other activities related to Mexico. In our first appraisal well we will also -- beyond looking for the oil water contact of the original Zama discovery, when we drill that first appraisal well we're going to take it deeper to test a second idea we call the [Marta] prospect. The target is close enough that we can see this by deepening the first appraisal well. And it's a great way to try to save some costs and test a high-impact project.

We are also making plans on Block 2, that is our other lease, another production sharing contract -- excuse me -- that we won in the round 1.1 auction. That well needs to be drilled in the second quarter of 2019. We have identified what we think is a very interesting prospect we call the Bacab prospect. We will start that permitting process this year and prepare ourselves to have that well executed by the second quarter of next year.

As we continue to integrate the teams and assets in the combination with Stone, I think we will see some of these one-time integration expenses slow down and we'll start to pull the synergies in from the combination. As you know, we are headquartered in Houston while Stone was headquartered in Lafayette. So there are some synergies certainly on the G&A side and we see some synergies that are going to come through on the operating side.

We do expect it will take the bulk of this year to pull those savings through, so you'd expect the run rate of the business by the end of the year to be the most reflective run rate of the combination.

To conclude this, we are very pleased with where we are. Bringing new projects online, we're managing an appraisal of a world-class discovery, working through some one-time costs but we are still doing all of this inside cash flow. We are confident we can meet our guidance and expect great things from the organization we are building.

We also believe our balance sheet, with the pro forma leverage stat annualized for the first half of the year dropping to 1.2 times, puts us in a competitive position as we also think about other opportunities in the Gulf of Mexico from a business development perspective.

So, we continue to be happy with the progress we are making, the team is working very hard and we're excited about some things to come. So with that I will hand it over to Michael Harding to walk through the second quarter.

Thank you, Tim. Talos Energy continues to focus on bringing shareholder value as demonstrated in the financial results being reviewed on this call. As of June 30, 2018 our available liquidity was approximately $433 million having reconstituted our RBL credit facility upon the close of the business combination with Stone Energy Corporation in May. The face value of this facility is $1 billion with an initial borrowing base of $600 million.

We continue to have an active and consistent hedge program as a key financial strategy of the Company. We have approximately 14 million barrels of oil and 9 BCF of gas with an average floor price of $54 for oil and $3 for natural gas and these go for the remainder of 2018 and into 2019.

These derivatives are primarily swaps and set a floor to secure our ability to execute our capital expenditure plan, debt service and still allow for annualized free cash flow generation when forecasted out at current strip.

Our capital structure has been strengthened after the business combination whereby we refinanced $397 million of second lien notes due May 2022 and are no call one, $102 million of senior unsecured notes held by Apollo and Riverstone funds were exchanged for common stock in the process. Our strong balance sheet, capital structure and free cash flow generation continue to set us apart and allow us to execute our growth strategy going forward.

So now I'll turn to the financials for the quarter. The report is presented in accordance with US GAAP and is applied to interim financial statements and includes each subsidiary at the date of its inception. Talos Energy LLC was considered the accounting acquirer in the merger with Stone. Therefore the historical financial and operating data of Talos Energy Inc., which covers periods prior to the close, May 10, reflect the assets, liabilities and operations of Talos Energy LLC and not that of Stone.

Although the Stone financial information is included as of May 10 forward and fair value is given to the acquired balance sheet, as we disclosed in our 8-Ka filing and are contained in Footnote 3 of this set of financials. Our balance sheet reflects fair value of the combined businesses as of June 30, 2018.

One thing that I will point out on the Talos balance sheet is that Talos used cash from the business combination to pay down aged AP resulting in a lower than normal AP balance at the end of the quarter. And accrued liabilities are shown here which include accrued AP from Stone recorded after vendor invoices slowed as a result of their redirecting the processes and sending invoices to Talos instead of Stone in June.

So, those two categories are not necessarily reflective of the true run rate of Talos, but taken together accurately reflect the current incurred vendor liabilities.

Moving over to the income statement, our net loss for the second quarter of 2018 was $75 million and for the first six months of the year $98 million. The losses are primarily the result of non-cash mark-to-market expense associated with the unrealized commodity hedges. Adjusted EBITDA for the three months ended June 30, 2018 was $101 million and $187 million for the first six months of 2018.

Second-quarter production was 43,000 barrels in the second quarter and includes Stone volumes from May 10 forward. Stone Contributed at an average rate of 25,900 barrels a day inclusive of Ram Powell for that period.

On the revenue side, second-quarter revenues were $203.9 million for the quarter, which is 108.5 million higher than the second quarter of 2017 or 114%. Oil revenue increased $101.4 million or 129% resulting from a $21.98 increase in realized oil price and 10,300 barrels of equivalent a day. The increase from Stone's volumes amounted to 9,600 barrels equivalents per day.

Natural gas is 3.6 million higher than the quarter last year or 28%. This is reflective of a net increase in gas volumes of 19.1 MMcf per day. Stone contributed 22.6 MMcf per day and this volume increase partially is offset by a $0.29 per MCF decrease in realized gas price. NGLs increased 3.9 million or 112% with a $6.03 per barrel increase in realized price and a 1,200 barrel a day increase in volume, which primarily came from the Stone combination.

Lease operating expenses, LOE is 6.9 million higher or 22%. Stone contributed $9.9 million in expense partially offset by a $3 million increase in PHA expense reimbursement from our Phoenix Field, which has a 10% contract tied to commodity price, which had a $15 and 23% per Boe increase before the effect of hedges; and so we benefited from this uplift. LOE Expenses are $9.93 per barrel for the quarter.

Moving to G&A, G&A increased by $23.4 million or 313% year-over-year. The majority of this increase is transaction-related merger costs of $18.3 million. This G&A also includes the administrative G&A inherited from the Stone Company. G&A Is $7.89 per barrel of equivalent but $3.21 per barrel of equivalent when the transaction costs are normalized.

In other operating expenses, such as workovers and accretion, this also increased $13.7 million or 101%. $4.5 million of the increase is maintenance costs from the Stone assets, $4.1 million of ARO accretion expense and $5 million of repairs and maintenance inclusive of $1.8 million in BSEE required maintenance and a non-recurring charge of $1.2 million on the reconnection and inspection related to the Phoenix Field in June.

Other operating expenses were $4.52 per barrel of equivalent compared to $3.19 per barrel equivalent for Talos standalone in 2017.

Moving to our price risk management activities and derivatives. We recorded an unrealized non-cash expense of $91.2 million. This is primarily the result of an increase in strip price which had indications resulting in a decrease of our forward value of $87.4 million -- used in open derivatives. We realized a $27 million hedge settlement loss for the quarter. Our earnings release contains the annualized pro forma guidance and remains unchanged from previous ranges disclosed.

This concludes the prepared remarks on the quarter financial data and I will now turn the call back over to the operator.

(Operator Instructions). Marshall Carver, Heikkinen Energy Advisors.

I see you maintained your guidance for the full year. Could you give us some commentary on expected production by quarter? Would that be slight growth in 3Q and then again in 4Q? Or is there some hurricane-related downtime you've factored into guidance? How should we think about those things?

Marshall, it is Tim and thanks for the question. I think one of the reasons we didn't guide by quarter yet are some of the things that you saw in the second quarter, where one thing you have to think about is you transition through pulling into companies. And in particularly with Ram Powell, when you buy an asset of that size from a major, typically the major in this case, Shell, as the operator will stay in for some transitional period as operator. That may be 90 days before we jump in.

And so, some of those expenses can be outside of our control, not with respect to those expenses being necessary but how you plan and timeout some of those expenses. And so, that was some of what was in our minds on why we kind of decided to go ahead and stick with an annual guidance.

Now we are reaffirming that guidance and when we talked about recent developments I think we talked about the activity in the Pompano area. That is additive in the third and fourth quarter with respect to the first half of the year. We talked about that Ewing Bank well that we are completing as we speak and then that well will come online in the third quarter.

So I think you're seeing the headwinds of integrating the assets in the second quarter. You are seeing some projects come online that should uplift production in the third and fourth quarter from the second quarter of 51.6 or the first half of the year of 50.7. So I think you see the building blocks on why we're certainly comfortable reaffirming and feeling like we'll hit that guidance and we will be in very good shape.

I think in terms of 2019, one thing that I want to just put the seed in your head we're spending quite a bit of time on is really digging back into all of these assets, rethinking about the portfolio itself and then reshuffling how we would rank the projects between the collective companies. That's a good problem to have. I think we want to be able to really put a fulsome list together. And then as time moves on later in the year we'll be prepared to talk about 2019 in a more full way.

Okay thank you.

You know what, hey Marshall, you asked about hurricane downtime. Yes, look, I think even behind some of those activities that we just talked about and the recent developments, this should be additive to our production base in the third and fourth quarter that weren't in the first half of the year.

Certainly the third quarter -- late in the third quarter is when historically we have our most active part of hurricane season. If you get on the website we would encourage you to look at the map. You will see how geographically spread out our assets are. And so, if you have a named store in the Gulf of Mexico there's no doubt something will be shut in.

I think we plan on that. That is generally baked into our guidance and it's hard to predict what that is. I think you've followed the Gulf of Mexico companies, downtime related to both hurricanes and potentially some third-party downtimes that's unplanned is something that we bake into our modeling and certainly you should bake into yours.

All right, thank you. And I had one follow-up, if you don't mind. You've made a couple of acquisitions this year. Do you see additional opportunities for more acquisitions later this year or early next year? Or do you need some more time to adjust what you just recently bought? How are you thinking about that?

Yes, no, one of the reasons we bought these companies together and why we think what we put together is so interesting is when you put the Talos stone combination together, and obviously with the Ram Powell asset that we just did, and you've created a company that has enough scale, a good balance sheet, a good liquidity position to try to be flexible in what I would call a broader business development market.

So you can think about our business, Marshall, in kind of three areas. We have the business that we're running and the business that we are integrating and we are working very hard and diligently on that. But then I've got a corporate development team that I keep away from the entire day-to-day operation.

And their job is to really go look for three types of business development opportunities: asset transactions like Ram Powell where you have infrastructure. In my view when you own infrastructure in deepwater you put an open for business sign on that thing and you are kind of putting a radius 25 miles to 30 miles around that infrastructure and looking for other business development opportunities that you can bring back to that infrastructure.

So, we want a team that's always focused on asset-related deals and then what I would call stranded, whether they are drilling locations or stranded discoveries. We are looking in the market for those all the time. And then occasionally you will see something like what was announced yesterday that are entity-based deals and we want to be aware of those, we want to understand those.

So, the answer is yes; we are hyper focused on the business, we're absolutely focused on the integration, but we want to take advantage of what this business created and we've got a team that is focused on that every day.

John White, ROTH Capital.

Good morning, everybody. Thanks for taking my call. I really don't have a question. I just wanted to say welcome to the public markets and congratulations on the merger. As you know, I've followed your successful career in the private arena and now you're in my world and looking forward to staying in touch.

Well I appreciate it, John. Look, it's great to be on this first call. I sometimes think of a funny response, but you're getting a very serious me here today, John. But look, we are here to make sure everybody understands what our core business is doing. We are going to be on the road to some conferences. Sergio will have that schedule up on the website. We would encourage everybody to look at that and seek us out at some of these conferences and contact Sergio and, John, you among them. So thanks for the kind remarks.

Sergio has been great and we'll look forward to more one-liners and humor on some of the future calls.

Shahin Amini, Pareto Securities.

I am a relative newbie to your story, so on a steep learning curve. Two questions, the first one on your unitization agreements. I just want to -- I mean obviously what you've done is kind of historic for Mexico. I'm just wondering whether that in itself is going to cause you challenges when you are going through this process to reach a unitization agreement which is amicable to all parties. And what do you see as challenges in that process?

Is this going to be in line with the international standards on a volumetric basis? Or do you think that your counterparties could also look at the reservoir quality and distribution? And how important is the appraisal program to that?

And my second question is on your hedging policies. And I just want to understand how much of your hedging decision-making is driven by your reserve based lending, your credit facilities and how much is really just down to you trying to manage your exposure? Thank you.

Yes, well, look, let's to the last one first because I think we as a Company -- and thanks for following us and welcome to the group. As a company this now spans a long time. Again I would encourage you to go look at our corporate deck. Our management team has been together, the core members, for some 18 years and we've managed through multiple commodity cycles and we try not to over guess the market.

I think in our basin, because the operators in our basin do have to manage some plugging obligations, you want to distance yourselves from that capital outlay and provide room to make what you would obviously feel are more interesting investments that add production and add to our core NAV. If we are going to have the available capital to do that we have to lock down our budget in some level.

So you know our hedging starts there, our ability to continue to drive returns by making the right investments and having the free cash flow available to make those investments. And sometimes when we are in a more bullish market some previous hedges can be out of the money, but often times those hedges were able to preserve us during the downturns of commodity cycle.

So, we try not to over guess it, we try to do the right thing. Certainly when you have some debt, even though right now we've got very good leveraged stats, we do want to hedge to protect that. Obviously the RBL is part of that. But it really comes down to the core tenets of how do you want to run your business and how do you want to have free cash flow available to make the right capital allocation decisions. So that's generally my philosophy on hedging.

Let's move to Mexico because that's a great question and it's an interesting question. The first thing I would try to remind you is everything we've done on an exploration perspective as a member of the private sector has been the first in that country. Look, I'm not saying we deserve any more or less credit than any other operator down there for that.

I think it's worth at least remembering that we were that first bidder in round 1.1. There were only two competitive bids. We were lucky enough to secure those bids, very proud of that. We drilled the first private sector exploration well in the history of the country offshore. And so, we filed the first social impact survey. Most of our permits were the first of their kind by the private sector.

So we went into that not knowing how the federal government would respond and we had to have some faith that we would be fulsome in our efforts and we would give them everything they needed. We would be very transparent with them and hope they would be transparent with us and so far that's worked out.

Now with respect to the unitization -- now, I would say before we move into the unitization, as the basin has grown, and it sounds like you've followed the activity down there, and it's become one of the hottest basins with respect to leasing activities over the last three years through rounds 3.1. Again, for those who follow our history, we were successful in our first two bids. Our last five bids we were not successful and they were all competitive bids.

So as the operator community has grown down there we have more folks trying to do the same things we're doing. There's actually comfort in that. We've got a very structured trade group we call [Amexi] and they care about these issues. You've got the credibility of Shell now having more offshore acreage in offshore Mexico than the US Gulf of Mexico.

So we have a breadth of operators that we are working alongside to make sure that we are all doing the best we can and talking to the new government -- it's certainly still the old government -- to get some of these policies right.

Now with respect to the unitization policy, that's a perfect example where [Sener] and CNH and all those involved wanted to get that right. They studied multiple jurisdictions around the world. They took a lot of white papers from various operators.

There was an open session to present those white papers. So they were very thoughtful on trying to get a framework set in place that you could use and set expectations regarding redeterminations, things you would expect in any good unitization agreement to provide some flexibility on what you should do early and then how you redetermine late from that perspective.

What we are doing in the pre-unitization is we're taking that framework and we're just tightening up some of the things that we want to have control over within negotiations on both sides. That's confidential, we're not going to talk about that until that document is public, but I think it's the natural extension of a framework provided by the government where they studied and analyzed multiple jurisdictions and took comments from industry.

And then we're putting something underneath that that tightens that up just a little bit. And I think, look, you can see my colleague and our non-op partner Premier has commented on that. I think the previous CEO of Pemex commented on that. They've been good conversations and I think we are all doing the right thing.

Excellent. Thank you very much. And just a follow on, Tim also talked about two prospects, Marta and (inaudible). I don't recall seeing anything in your slide deck on these two catalysts. Is that something that we could potentially get more information on ahead of the drilling?

We haven't disclosed those yet and on this call we won't. I will tell you that you'll see some of that if you go to our corporate deck. You will see at least some visual areas of where those prospects are on Block 2 and Box 7. So I think there's a little bit you can see there. And as we get closer we'll probably put a little more information to let you take a deeper dive into those prospects.

(Operator Instructions). Mark Wilson, Jefferies.

Is there any update you can give on Pemex's -- the timing to Pemex's Asab-1, the first well on their side of Block 7? And then secondly, just wondering why there isn't any flow test as part of the appraisal plans. And what kind of (multiple speakers) assurance have you got there?

Right so it's clear that up. There absolutely will be a flow test as part of our appraisal plan. We will do that likely in the first well, just to talk about that quickly. The first well, although it's going down dip to go test the oil water contact, once we do that we'll bring it back to the original surface location and drill a straight hole where we'll catch whole conventional cores and we'll do a flow test.

So there's no question; we want to understand flow assurance, we want to go get a lot more reservoir modeling efforts, get some hard rock in our hands that we can put into the labs. And so, no, you're going to see the same type of appraisal you would expect to see on a discovery of this scale.

Now we are benefiting from the fact that because we are in shallow water I do think there is potentially some diminishing returns on how much appraisal you need to do because of the economies of scale of being in this water depth. But to be sure, we want to make sure we get all the right information both on understanding the limits and understanding the flow assurance, flow capacity, getting more samples, getting more physical rock.

So, you can expect all of that in the appraisal plan. And again, we will continue to educate the market on what we are trying to do and as well our partners, particularly Premier. Your first question -- remind me of your first question, I'm sorry.

If there was any update on there with Pemex.

I mean certainly we [aren't] intimately involved in what Pemex is doing. There are a couple things that I think we understand in terms of what Pemex is trying to do. If you go back and remember how does Pemex have this acreage in the first place. And I think the nomenclature they used was around 0.5. There are different terminologies for the process of the federal government deciding what Pemex could retain unrelated to their producing reservoir outlines.

And so, they had a series of blocks that there were able to retain. They essentially were primary term blocks and with the expectation that they would go drill on these primary term tracks. The block that's next-door to us is one of those primary term tracks that they have already gotten an extension on and they are in the extension period.

What I think they are trying to do -- and again this is a better question for Pemex, but I think I've read this in their public comments -- is find a rig that can do multiple things, not just test this project. And so -- which is why and frankly in our perspective we've always been fine and never had a problem with Pemex testing the discovery on their side of the lease because they have an obligation to do something with that lease that goes back to the term of the lease itself.

I know they are trying to do other things with a rig in that type of water depth. And keep in mind this is a water depth where you have to take a deepwater rig and anchor it. So it's a little tricky, there's not as many rigs that can do the anchoring or the mooring. So there are several variables that I think Pemex is navigating that we don't have to navigate because we are focused on one specific operation. So again, better question for them but I think that's most likely the answer.

Okay, very clear. Good luck with it, guys. Great story.

And this will conclude our question-and-answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.

Look, I want to thank everybody for joining the call. We are very proud of where we are. Where excited about integrating the Company. Still some work to do on the integration. We remind you that most of the synergies we think will pull through by the end of the year, but a lot of positive things and a lot of momentum as we go into the second half of the year; certainly a ton of momentum as we go into 2019.

Continue to go to the website. We will post where we are in conferences. We are looking forward to meeting many of you as you get yourself introduced to the story. And we thank you today for your participation.

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