Talos Energy Inc. (TALO) Q2 2018 Earnings Report, Transcript and Summary

Good morning, and welcome to the Talos Energy Second Quarter 2018 Earnings Conference Call. All participants will be in a listen-only mode. [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 & 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 in our consent solicitation statement and perspectives 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'd 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 an approved Stone's transaction of the Rampart 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 payments. As Sergio mentioned, this earnings release will be different than those we'll post in the future. You'll see two discussions; a GAAP discussion which focuses on Talos only through January through April, and then the combined assets from 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 has combined net daily production with 47,800 barrels equivalent a day for the full year in 2017. As previously announced by Stone at the time of the transaction, Rampart 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 and pro forma, for 2018 we only include the volumes of Rampart assets 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. To more detail look into the history of the management teams; we've run 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 has several linkers 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 approved 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've remind you that year-end SEC price was $53.49 as you can imagine these assets are more valuable with an updated strip. 80% of the 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 it's lifecycle. Our core strategy in the U.S. Gulf of Mexico is use our infrastructure and more modern 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 and running high margin barrels across what is generally fixed cost within our infrastructure base. We have over 660,000 acres under lease in the U.S. Gulf of Mexico with the key being - key assets are as follows; the Phoenix field and the Tornado field in the Green Canyon area, this is a series of sub-sea wells that flows back to the Helix Producer 1 otherwise known as the HP1 which is a floating production unit, the Pompano and Amberjack field to Mississippi Canyon which features both our Flix fixed platforms with dry-tree's and subsea infrastructure in the Rampart field which is tension-leg facility and has dry-tree's 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 of post-synergy reforms in 2015. We drove the world recognized Zama Discovery in July 2017 and we'll discuss our efforts to a praise at Discovery on this call. If you look at the full year guidance, we 49,000 to 53,000 barrels equivalent a day of net daily production for 2018 on a pro forma with Talos and Stone for the full year, and Rampart 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 plaguing [ph] obligations we manage in the Gulf of Mexico, they are a little more than we like in 2018 as a result of the combination with Stone but we expected that value as a percent of our total capital will decrease with time. In normal leasing - we also have normal leasing cost, G&G [ph] infrastructure cost and capitalized G&A. Beyond that we have three levels of capital that we focus on adding production and value; first, what we call our asset management activities which is our first line of defense in managing our corporate client. It can be adding new production to changing out submersible pumps, gasless designer or recompleting wells with [indiscernible]; all activity is expected to add rate reserves and we typically try to do 10 to 12 with 20 of these activities a year. They are typically smaller impact projects and drilling projects but they have good rate of returns and low production conversion costs. And then we have two types of drilling opportunities, those that can turn into production quickly; some were location [ph] and others are low-risk but outside proves it 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 in economic and can materially increase our NAV. So with all of this information as a backdrop we're 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 a day 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 second quarter has impacted from a new well in our shallow water drilling program and then a series of recompletions which are PDMP [ph] conversions to PDP, we call that asset management; again, we talked about that earlier, we're going to talk about that here in just a minute as well. And 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 [indiscernible] providence of sea well which flows back to our Pompina facility. This well came online at an initial growth rate of close to 4,000 barrels equivalent a day and a net rate of 3,370 barrels equipment a day which was on the high-end of our guidance and 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 asset did 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 fourth quarter of 2018, two wells back-to-back with production online in the second quarter of 2019 which is again what we hoped for when we're utilizing our own infrastructure. We're also partnering with Murphy at 12.5% working interest of their high impact Kinki [ph] prospect which will begin in the late third quarter or early fourth quarter. In shallow water, we continue to be active of the ASCO75 [ph] rig after it drilled the first successful well in Ship Shell 224 [ph], we then moved into and drilled a well in Ewing Bank 306, it 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 equivalent a day gross which would be a 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 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 drilled - 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 and praising our Zama Discovery. As a reminder, the Zama Discovery, we logged over 1,100 feet of gross pay with U.S. Gulf of Mexico type rock properties as this is an upper Miocene target, city upper Miocene is a geological interval that has been prolific on the U.S. 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 INSCO 85-03 [ph] rig which is the same rig that drilled the original Zama Discovery. Our goal in the appraisal wells to drill a location down dip of our original location will look for an oil water contact there, we'll 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 too 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, NFID, by the end of 2019, maybe early in 2020. Once we've reached FID, we think we can get production online between two and two and a half years from that decision and that milestone point. What enables us and our minds to be able to do this fairly quickly is the fact that we have such a 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've done in the past and other development projects where we've also talked about in our earnings release and what's been discussed generally is we are - we negotiated the first pre-unitization agreement, as some of you know, Pemex owns [indiscernible] 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 that will require some appraisal but the pre-unitization agreement allows us to sit at the table and has 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 of other activities related to Mexico and our first appraisal well 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 marked-up prospect. The targets 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 the high impact project. We're also making plans on Block 2, that's 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've identified what we think is a very interesting prospect, we call the Bacalt [ph] prospect, we'll 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 onetime integration expenses slow down or start to pull the synergies in from the combination. As you know, we're headquartered in Houston while the Stone was headquartered in Lafayette; so there's some synergy 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; running new projects online, we're managing an appraisal of a worldclass discovery, working through some onetime cost but we're still doing all of this inside cash flow. We're confident we can meet our guidance and expect great things from the organization we're building. We also believe our balance sheet with a pro forma leverage stat annualized for the first half of the year drop in at 1.2x 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're making, the team is working very hard, and we're excited about some things to come. So with that, I'll hand it over to Mike Harding who will 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 RBO 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 2019. These derivatives are primarily swapped in sort of 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 our no call 1 [ph] to $102 million 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 continued 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 the U.S. GAAP and as 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 at Tallis 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-K filing and/or contained in footnote three of this set of financials. Our balance sheet reflects fair value of the combined businesses as of June 30, 2018. One thing that I'll point out on the Talos balance sheet is that Talos used cash from the business combination to paydown 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 their processes and sending invoices to Stone, I mean 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 an average rate of 25,900 barrels a day inclusive of Rampart 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 '17 or 114%. Oil revenue increased a $101.4 million or a 129% resulting from a $21.98 increase in realized oil price and 103,000 barrels of equivalent a day. The increase from Stone's volumes amounted to 96,000 barrels of equivalent 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 increased partially is offset by a $0.29 per mcf decrease in a realized gas price. NGLs increased 3.9 million or a 112% with a $0.063 per barrel increase in realized price and a 12,000 barrel a day increase in volume which primarily came from the Stone combination. Lease operating expenses, LOE at 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 effective 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 cost 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 work overs and accretion this also increased 13.7 million or 101%, 4.5 million of the increases maintenance cost from the Stone assets, 4.1 million AERO accretion expense and 5 million of repairs and maintenance inclusive of 1.8 million and BSE [indiscernible] required maintenance and 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 noncash 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 that 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]. Our first question will come from Marshall Carver with Heineken Energy Advisors. Please go ahead.

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 factored in the guidance how should we think about those things?

I think one of the reasons we didn't guide by the quarter yet are some of the things you saw on the second quarter where you know one thing you have to think about is you transition through pulling two companies and in particularly with [indiscernible] 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 time out some of those expenses and so you know that was some of - what was in our minds and why we you know kind of decided to go and stick with a manual guidance. Now we are reaffirming that guidance and when we talked about recent development I think we talked about the activity in a Pompano area, that additive in the third quarter and fourth quarter with respect to the first half of the year. We talked about that UA [ph] bank well that we're 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're seeing some projects come online that should uplift production in the third and fourth quarter from the second quarter of 51.6 at the first half of the year 50.7, so I'm thinking you see the building blocks and while we're certainly comfortable reaffirming and feeling like we'll hit that guidance and we'll be in very good shape. I think we in terms of '19 one thing that I just kind of put the seed in your head we are spending quite a bit of time on is really digging back into all of these assets, rethinking about the portfolio itself and then really kind of shuffling how we rank the project between the collective companies that's a good problem to have. I think we want to be able to really put fullsome list together and then you know as time moves on later in the year we will be prepared to talk about 2019 in a more full way. You asked about hurricane down time, look I think even behind some of those activities that we just talked about in the recent developments that 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 we historically we have our most active part of hurricane season I mean you know if you get on the website we would encourage you to look at the map you'll see how geographically spread out our assets are and so if you have a named storm in the Gulf of Mexico there's no doubt something will be shut in, I think we plan on that that's generally baked into our guidance and it's hard to predict what that is and I think if you follow the Gulf of Mexico companies downtime related to both hurricanes and potentially some third party down times that's unplanned that's something that we bake into our modeling and certainly you should bake in yours.

And 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 digest what you just recently bought. How are you thinking about that?

I think one of the reasons we brought these companies together and why we think you know what we put together is so interesting is you know when you put the Talos Stone combination together and obviously with the Ram Powell asset that we just did you know you have created a company that has enough scale, a good balance sheet, a good liquidity position and 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're working very hard and diligently on that but then I've got a kind of a corporate development team that I keep kind of 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 deep water you put an open for business sign on that thing and you're 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 kind of stranded whether they're drilling locations or stranded discoveries. We're looking in the market for those all the time and then occasionally you'll see something like that what was announced yesterday that are entity based deals and we want to be aware of those who want to understand those. So the answer is yes you know we were hyper focused on the business, we are absolutely focused on the integration but we want to take advantage of what this business created and we've got a team that's focused on that every day.

Our next question comes from John White with Roth Capital. Please go ahead.

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 have followed your successful career in the private arena and now you're in - you're in my world and we're looking forward to staying in touch.

Well I appreciate it John, you know it's great to be on this first call. I sometimes think of a funny response but you're getting it very serious from here - me here today John but look you know we are here to make sure everybody understands what our core business is doing, we're going to be on the road, some conference you know 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 then John you among them. So you know 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.

Our next question comes from [indiscernible]. Please go ahead.

I'm a relative newbie at your story so on a steep learning curve. Two questions, first one on your unitization agreements I just want to I mean obviously given what you've done these kind of historic for Mexico I'm just wondering whether that in itself is going to pose you challenges when you are going through this process to reach a unitization agreement which is amicable to all parties and what you see as challenges in that process, is this going to be in-line with international standards on volume metric basis or do you think that your counterpart is could also look at the reservoir quality and distribution and how importance 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 base lending, your credit facilities and how much it's really just down to you trying to manage your exposure. Thank you.

Yes, let's do the last one first because I think we as a company and thanks for following us and welcome you know to the group you know as a company and this now spans a long time again I would again 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 who are based in do have to manage some plugging obligations, you want to distance yourself from that capital outlay and provide room to make without you would obviously feel are more interesting investments that production and add to our core AV if we're going to have the available capital to do that we have to lock down our budget in some level and so 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're in a more bullish market some previous hedges can be out of the money but oftentimes those hedges we're able to preserve us during the downturns of the commodity cycle. So we try not to over guess it and we try to do the right thing. Certainly when you have some debt even though right now we've got you know very good leverage stats we do want to hedge to protect that obviously the RVL is part of that but it really comes down to the core of tenants 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 and 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 and 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 and around 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 the first we filed the first social impact survey we filed that 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 will respond and we had to have some faith that we would be 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 that so far that's worked out. Now with respect to the unitization I would say before we move into the unitization as the basin has grown and it sounds like you follow the activity down there has become one of the hottest basins it's been from with respect to leasing activities over the last three years through around 3.1 again for those who follow our history we were successful on 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 them [indiscernible] they care about these issues you've got the credibility of Shell now having more offshore acreage in offshore Mexico than the U.S. Gulf of Mexico. So we have a breath 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 is 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 you know [indiscernible] CNH and all of those involved wanted to get that right they study 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 and trying to get a framework set in place that you could use and set expectations regarding redeterminations, things you would expect in any good unit position agreement that provides some flexibility on what you do early and then how you'd read determined late you know from that perspective. What we're 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 the negotiations on both sides you know that's confidential, we're not going to talk about that till that documents 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 time set up just a little bit and I think look you can see my colleagues are not partner Premier [ph] has commented on that I think the previous CEO [indiscernible] commented on that, they've been good conversations and I think we're all doing the right thing.

Just a follow-up on, you also talked about two prospects mostly. Are there any - slide deck on these two catalyst is that something that we could especially get more information ahead of the drilling?

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

[Operator Instructions]. Our next question comes from Mark Wilson with Jefferies. Please go ahead.

Is there any update you can give on Pemex the first well on their site of Block 7 and then secondly just wondering why there wasn't any floor test as part of the appraisal plans? What kind of assurance you have got there?

Right, so let's clear that up they are absolutely we have flow test is part of our appraisal plan. We will do that likely the first well just to kind of 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 will bring it back to the original surface location and drill a straight a hole where we will catch whole conventional cores and we'll do a flow test. So there is no question we want to understand flow assurance, we want to go get a lot more reservoir modeling efforts you know, get some hard rock in our hands that we can put into the labs and so now 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 you know 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 your appraisal planning and again we will continue to educate the market on what we're trying to do and as well our partners particularly Premier. Your first question remind me of your first question, I'm sorry.

If there is any update on--

You know certainly I mean we are intimately involved in what Pemex is doing, there are a couple of things that I think you know we understand with in terms of what Pemex is trying to do. If you go back and remember how this Pemex had this acreage in the first place and I think the nomenclature they use 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 they're able to retain that they essentially were primary term blocks and that 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've already gotten an extension on and they're in the extension period. What I think they're 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 you know which is why and frankly in our perspective we've always been fine and never had a problem with this with Pemex testing their discovery on their side of the lease because they have an obligation to do something with that lease that goes back to the terminal lease itself. I know they're trying to do other things with a rig and that type of water depth and keep in mind this is a water depth where you have to take a deep water 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're focused on one specific operation. So you know again better question for them but I think that's most likely the answer.

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

I want to thank everybody for joining the call. We're very proud of where we are. We're 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.