Ladies and gentlemen, thank you for standing by. Welcome to the Helix Energy Solutions Group Inc. Third Quarter 2016 Earnings Conference Call. During the presentation, all participants will be in a listen-only mode. [Operator Instructions] As a reminder, this conference is being recorded Thursday, October 20, 2016. Now I would now like to turn over to Mr. Erik Staffeldt, Vice President, Finance and Accounting. Please go ahead, sir.

Good morning everyone and thanks for joining us today for our conference call for our Q3 2016 earnings release. Participating on this call for Helix today is Owen Kratz, our CEO; Tony Tripodo, our CFO; Alisa Johnson, our General Counsel, and Scotty Sparks, our COO. Hopefully, you’ve had an opportunity to review our press release and the related slide presentation released last night. If you do not have a copy of these materials, both can be accessed through the Investor Relations page on our website at www.helixesg.com. The press release can be accessed under the Press Releases tab and the slide presentation can be accessed by clicking on today’s webcast icon. Before we begin our prepared remarks, Alisa Johnson will make a statement regarding forward-looking information. Alisa?

During this conference call, we anticipate making certain projections and forward-looking statements based on our current expectations. All statements in this conference call or in the associated presentation, other than statements of historical fact, are forward-looking statements and are made under the Safe Harbor provisions of the Securities Litigation Reform Act of 1995. Our actual future results may differ materially from our projections and forward-looking statements due to a number and variety of factors, including those set forth in our slide two and in our annual report on Form 10-K for the year ended December 31, 2015. Also during this call, certain non-GAAP financial disclosures may be made. In accordance with SEC rules, the final slides of our presentation materials provide a reconciliation of certain non-GAAP measures to comparable GAAP financial measures. The reconciliation, along with this presentation, the earnings press release, our annual report and a replay of this broadcast are available on our website. Owen?

Good morning everyone. Moving to the slide five, which is a high level summary of Q3 results. As we suggested last quarter, Q3 results came in significantly better than the prior two quarters. Revenues increased from $107 million to $161 million, and EBITDA improved from $15 million to $47 million on a sequential quarterly basis. The improvement occurred across the board with better utilization on the Q5000, a seasonal pick-up in activity in the North Seawell intervention business as well as in the Robotics business. We experienced relatively high utilization across our active well intervention fleet with the exception of the Skandi Constructor and the H534. Turning to slide six, earnings per share came in at a positive $0.10 per share in quarter three flipping from a loss of $0.10 per share in quarter two with EBITDA coming in at $47 million. The Q4000 continue to see high levels of utilization in the Gulf of Mexico while the Q5000 did incur 15 plus days of downtime earlier in the quarter due to IRS repairs and modifications. We expected the Q4000 to continue to see high levels of utilization for the rest of the year, while the Q5000 is under contract for BP the remainder of the year. Revenues for work schedules on the Q4000 quarter four were accelerated into quarter three as a take or pay contract was invoked. In the North Sea the Well Enhancer and the Seawell realized 91% to 98% utilization respectively, but the Skandi Constructor saw only 15% utilization. Higher utilization in the North Sea is due in large part to seasonal factors. The same is true on the Robotics side with our robotics support vessel fleet booking 81% utilization and we even had a bit of spot market vessel utilization. The Siem Helix 1 arrived…

Thanks, Owen. Moving onto slide nine. Revenue in the third quarter increased to $161 million from $107 in the second quarter. Gross profit margin increased to 25% compared to 5% in Q2 resulting in a profit of $40 million. Looking at take or pay contract in Q3 contributed to the gross margin uptick. Throughout the period, we gained high seasonal utilization across all of our operational vessels in both the well intervention and the robotics fleet. To mitigate costs in the Gulf of Mexico, the H534 remained stacked and down. In the U.K. the Skandi Constructor was warm stacked for the quarter. Our alliance with Schlumberger is continuing to gain momentum. We have now completed four projects under the combined efficiency terms. We contracted three new clients for Helix. Combined Helix Schlumberger sales efforts have increased globally. The alliance jointly owned 15K IRS system running to build process and on schedule for Q3 2017. We also commenced work on another jointly owned subsea system named ROAM, Riserless Open-water Abandonment Module. It is expected to be available between Q2 and Q3 of 2017. Slide 10 provides an overview of our Well Intervention business in the Gulf of Mexico. Q4000 work the entire quarter for three clients with 93% utilization and did have a small period of repair time to conduct wire change outs on the vessel cranes. All of the work undertaken was related to production enhancement scopes and contracted with combined efficiency terms with our alliance partner Schlumberger. The schedule for Q4000 remainder 2016 is nearly full. The Q5000 continued under long-term BP contract and the vessel at 84% uptime. The unit was on zero rates for 15 days downtime relating to the IRS system. We have now completed three work scopes and recently commenced the fourth scope. The Q5000…

Thanks, Scotty. Moving over to slide 16, it outlines our debt instrument and maturity profile. I'll leave this slide for your reference and move to the next slide. Slide 17 provides an update on some key balance sheet metrics including our year end gross and net debt levels as of September 30th. Our net debt position decreased to $196 million in the third quarter from $219 million in the second quarter. Our funded debt as of September 30th decreased to $698 million, reflecting quarterly principal payments of $15.5 million on our term loan including an $8 million prepayment of the loan, $8.9 million on our Q5000 loan, $3 million on our MARAD debt and the repurchase of $8 million of convertible notes due 2032 during the quarter. Our cash position decrease this quarter by $10 million to $482 million. The decrease in cash was driven by our debt repayments of $35 million, capital expenditures of $22 million and the cash use in operations partially offset by the receipt of $56 million of net proceeds from our ATM offering program. Our liquidity at September 30th was approximately $499 million comprised of cash balance of $482 million and revolver availability of $17 million. I will now turn over the call to Tony for discussion on our 2016 outlook. Tony?

Thanks, Erik. Moving over to slide 19, now that we are three quarters of the way through the year, we have narrowed our 2016 EBITDA forecast range to $100 million -- to a $110 million of EBITDA. We moved the bottom end of the range up from $90 million in the top end of the range down from $120 million. While we still have some contracted revenues remaining for Q4, the biggest variable lap is really operational risk and timing on start-up of operations in Brazil with the Siem Helix 1. On a positive note, our backlog actually increased from $1.7 billion last quarter to $1.9 billion at the end of quarter three. This increase is directly attributable to a contract extension for the Helix Producer I with this FPU now firmly contracted through 2023. The CapEx forecast for the year is slightly lower at $220 million with most of this capital for the build-out of the two Siem Helix vessels and continuing construction of the Q7. On a more granular note and as Owen suggested earlier, we expect high utilization for both the Q5 -- Q4 in the Gulf of Mexico in quarter four, but expect to keep the H534 stacked. In the North Sea, both the Seawell and Well Enhancer are working today with utilization likely into November, but seasonal factors will come into play thereafter impacting utilization. On slide 23, on our balance sheet outlook, our gross debt is set to decrease approximately $94 million in 2016 due to scheduled principal payments on our debt instruments, as well as the aforementioned repurchases of our convertible notes in quarters two and three and the additional $8 million of principal repayment made in our term loan in September. Our net debt levels are forecast at the end of the year somewhere between $275 million and $325 million. This range is based on a number of assumptions, which could vary significantly, including the actual amount of EBITDA that is generated, working capital changes, tax refunds, et cetera, et cetera. However, this updated range is positively lower than the guidance we provided last quarter. In other words, our balance sheet looks to be better at the end of the year than we previously forecasted. So, with that, I’ll turn the call over to Owen for closing remarks.

Thanks, Tony. At this point in the year, 2017 comes more into focus. While it’s still too early in the budgeting process both to our customers and us to provide specific guidance, I can try to provide you with some color on a high level basis. Last year, commodity prices fell sharply, as the customers' budgeting process was concluding. This created an environment where the projects that were likely to be sanctioned or approved were required to be resubmitted for approval. Cash preservation became the overriding factor for customer behavior. Many projects failed to move forward due to one or more partners declining the sanction. Other projects failed to meet commercial hurdles at the lower commodity prices, and rigs on current contracts had no drilling to do, 2016 became a scramble with many uncertainties. Looking forward, we’re closely watching the following developments; first, commodity price stability during this budgeting process; second, rig contracts rolling off in 2016 and 2017; third, higher commodity pricing making more cash available to the clients. I believe that the work is there to be done. I also believe that Helix is one of very few service providers that can handle [indiscernible] that our EBITDA should grow over the next couple of years. But besides the items we’re watching that I just mentioned, we should have a full year with the Q5000 and hopefully, have the start-up issues behind us that so negatively affected our EBITDA in 2016. With BP’s commitment to 270 days, we'll also have an additional 90 days versus 2016 available to contract the vessel over the time. It was available this year. We should have a full year of the Siem Helix 1 versus just a partial quarter in 2016, and this is our first of two vessels contracted to Petrobras in…

Operator, this time will be taking questions.

[Operator Instructions] The first questions from line of Greg Lewis with Credit Suisse. Please go ahead.

Yes, thank you and good morning. I guess, Owen, you touched on the fact that you have put the -- you said congratulations first, I guess, on the two successful ATMs. And you mentioned that, that has sort of been -- there is no need to go for that any more. What is driving that decision? Is that just you had conversations with your lenders and at this point we are comfortable in sort of how 2017 plays out in terms of refinancing? Is it sort of a -- obviously, there is -- it's given the success I am just wondering why not maybe potentially do another one?

We're at the heart of it is we look at our cash balance and our outstanding credit for our capital obligations going forward. And then we take our EBITDA projections and we risk them to arrive at a load case, and then we look at the cushion that we have on liquidity for getting through that. And when we do that we feel like we're in a really strong position right now without any further need to raise additional capital.

Okay. Great. And then just on the OneSubsea 15K, I guess that's being delivered in Q3. Is that going to be something that is jointly owned in this between Helix and Subsea? And just -- was the driver of this coming from customers or it was something that as the joint venture alliance looks at the potential work scope in 2017 and beyond, it's something that, that piece of equipment is just really going to be needed? And then as we think about deploying it, where should we -- is there a specific vessel that, that is going to be targeted for?

Okay. I will take that one. The unit is jointly owned. It will be delivered to us in July and available to the market in August/September of next year. Primarily the market for it will be Gulf of Mexico there is a number of 15K wells also in the Gulf -- in Brazil and the East -- West Africa arena, sorry. The reason the building it is mainly client driven. A lot of 15K wells that are out there now coming to ensure you have a requirement for well intervention. So it's client-driven. Like we said earlier our alliance is gaining momentum. Some of those clients are now coming to Helix and Schlumberger's alliance. So we see the need for it.

So on the last note the system can be deployed from any of our heavy intervention assets. It can also be deployed from drilling rigs. So as a rental unit, it would be available to all the assets and all of the producers.

Perfect. Thank you very much.

The next question is from line of Vaibhav Vaishnav with Cowen and Company. Please go ahead.

Thanks for taking my question. I was trying to get a better handle on the amount of the cancellation that payment that you got in 3Q.

Well, let me take -- I will start this and Tony may want to add something. But from – constantly, you know, our well intervention project is about 20 days long typical duration. We're in the spot market primarily. All through the year we constantly have shipping schedule due to partner approvals not coming through of regulatory permits, not coming through for clients just changing the scope for producing scope. This is a constant occurrence for us. Periodically, there will be one that occurs that’s of a meaningful amount. I think we announced one back in 2015 with Anadarko. We've also -- we also then announced the BP issues, so start up. So that's why we made the disclosure of the acceleration of the revenues here. But taken in this entirety and it would be a complex exercise for us to quantify, but if you if you look at all of the shifting events through the quarter net-net the impact from the accelerated revenue is probably, you know, a wag, but it's probably less than $5 million on the quarter. Now having said that we -- again we have a schedule to remanage for the Q4 -- for the fourth quarter. We do so. Then we look at the likelihood of what that schedule is going to be and we revise our fourth quarter accordingly, and that's how we derived of the final results of -- seeing no need to revise our annual guidance.

Okay. Thank you. On the Seawell and Enhancer, you guys have work into November. How likely that work or another work can be opt-in, in December? Just trying to think about the near-term risk to those two vessels in December.

I think right now it's likely we'll keep the Well Enhancer busy through November and the Seawell to mid-November possibly longer, but right now it looks good through mid-November. I say beyond that it's awfully speculative. There's opportunities out there, but we're not counting on it. So I think in terms of how you might want to think about those two vessels, think about work into November and if anything happens beyond that it will be gravy. There is a chance that we might enter into some liner drydock exercises during December because if the vessels are idle we might as well do while it's idle, but they're pretty minor drydocks. Scotty about two weeks duration would you say.

Two weeks.

So even though we like the performance in Q3 I think we're going to see the normal seasonal factors start to happen as short quarter for drags on.

Okay. One last, if I may, on Canyon II, which I believe is in Gulf of Mexico. How should we think about -- or what's a good utilization number to put as a placeholder? Is 25% a good number, or am I being too pessimistic around that?

I would say at the moment a lot of work we are chasing to the fourth quarter for the Grand Canyon II is speculative. We generally get 42% to 50% utilization going into the fourth quarter for this region. Along those lines is what we would expect.

Okay. That's very helpful. Thank you for taking my question.

We have a question from the line of Ole Slorer with Morgan Stanley. Please go ahead.

Thank you very much. And I want to just ask a little bit -- more about the alliance with OneSubsea and Schlumberger towards what kind of tangible benefits you can point to, if any, of having had this relationship in place now for a little while. You mentioned something about four projects, four new projects. Could you elaborate on that? Are these new customers for you, or are they new types of products? What do you mean by new projects?

Well, under the alliance for Helix we have now achieved three new clients, target clients due to the alliance and what I am saying is on four of the projects that have recently been completed they've been under of the joint alliance efficiency terms whereas we're going to take risk on our services, so the clients pays one price for our vessel, our SubSea systems, our ROVs and the service equipment from Schlumberger and then we derisk the client from taking joint downtime.

And these three new clients, could you shed some light on who they are?

Yes. Recently, we've worked for Hess, for BHP and Chevron, and two of those have been target clients over the last few years.

And are all new clients for you, or clients that previously would use a drilling rig instead?

Yes. I would say so. They’re all new clients, primarily, in the Gulf of Mexico. We had previously in Africa.

Okay. And what has the feedback been with these one-off projects have been testing your system or are they likely to come back for more work now that -- these are presumably three clients that you have worked for in the Gulf before?

I would say that all of those three clients were very satisfied with the service and how the contract terms worked for them. And I would like to think there will be repeat work. There's nothing -- well, actually, one of them has contracted repeat work and we're in discussion with the others for further works.

And is a client who previously -- the previous -- or previously would have used a drilling rig instead?

Yes. All three of those clients would have previously used drilling rigs in Gulf of Mexico, yes.

Okay. Well, interesting. On the -- turning second question to Brazil. The Siem Helix 1 1st of November, that's a slightly earlier start of business than your prior guidance?

Well, our partner got totally -- we just said sometime in Q4. So, now that we're down there and far enough along in the inspection process, we believe November 1st is a reasonable date for start-up here in terms of modeling. I mean, there is certainly there are things that could go wrong, but certainly there are things that could go right that could accelerate that date. Right now in our own thinking we are -- and in our forecast assumptions, we have assumed a November 1st start-up date. We're down there. We're well-advanced through the inspection protocols. So, you never know with Petrobras, but there is no reason why we shouldn't meet the November 1st date. On the other hand, we still don't have the final sign-off either.

Okay. But 10 days away, that means that you are practically ready to go?

Yes, all of the clients, third-party services equipment, their own equipment and all of their personnel are on board the vessel now. We expect in the coming days to sail to the first well location. So, we're getting close.

Okay. Well, that will be a good one to get under the belt. So, with all of that, how come you're taking down the high end of the guidance for the fourth quarter? I understand why you're taking up the low end, but I'm not really sure what brings the high end down. Is it the North Sea that's a little bit more shaky than your prior thought, or are there other -- is it just an insurance policy in case something does slip? But I can't see what incrementally got the risk to the upside.

A couple of things that drove the upper end of the guidance down. A, we hooked a reserve in the third quarter, $2.7 million. We didn't anticipate that last time, accounts receivable reserve. Some of the uncontracted work that was in our prior forecast in the North Sea is now highly unlikely to materialize. I mean there's still a possibility and we had more down days on the Q5 really and Q3 which impacted our EBITDA to a significant nature. And we've also booked some non-cash stock comp cost that was not previously forecasted as our stock price rose. So, there's a number of factors that drove the top end down.

Well, I am happy about the non-cash stock comp costs. I think you guys still have a bit on that after what you've done. But the rest of it sounds a little bit suspicious, but I'll leave you at that. I'll hand back. Thank you.

The next question comes from the line of Joe Gibney with Capital One. Please go ahead.

Thanks, good morning, guys. Just a couple quick clarifications on the vessel side. On the Skandi, this short-term stub of work you picked up on the construction side, but you still characterize that visibility is obviously poor. Trying to understand. Is there work scope spilling into 4Q at all or is that a quick short-term job that happened in the third quarter and that was it?

Yeah. That's just a very quick two-week short term low revenue project. We don't expect any work for the vessel in Q4 at this time.

Okay. On the Siem 2, could you re-characterize when it's available for work? I think you referenced 2Q 2017 could potentially be in the fleet and marketed for other customers? Is that accurate, and if so, where would you maybe target Gulf of Mexico? Trying to understand how that vessel shakes out before it potentially goes down to Brazil.

Yes, I'll take that. There’s a couple of options. Number one, we're tendering some West Africa work. Two, with the back -- with the visibility we have on the Q4000 and Q5000, should that 90 days on the Q5000 become booked up, we wouldn't have additional capacity in the Gulf of Mexico. So, that's a potential. But I think our preference would be to find some to test wells in the North Sea, deploy our new 18 3/4 inch ROAM system and demonstrate the technology. That would be our -- probably our preferred route. So, we have multiple options on finding work for it, but the North Sea being our first preference.

Okay. And last one for me. Just trying to touch a little bit on robotics outlook. It's a lot of moving pieces, a lot of which are obviously still pretty murky. Sounds like the trenching not oil and gas out of the business, looks like it has better visibility, but comes with competition and price, Subsea construction obviously lower. So, it all, in some respects, comes down to the R&M side of the piece, which just trying to get your sense. You sit here now today versus maybe where we were last year on that side of the business, is it reasonable to think about the repair and maintenance scope of work within robotics being higher next year in 2017? Obviously, a lot of moving pieces there. Trying to get a sense of maybe that stub of the business.

I think you're right. There are an awful lot of moving pieces. We do have visibility into the trenching scopes that are out there. We also know where the competition has picked up work and what works we should be targeting and we have some awards for trenching for next year. Repair and maintenance run type scopes, I believe, there will be more clients for us to go after, but there will be an awful lot more competition. I don't necessarily see that is going to be a vast uptick in that work and we will be scraping around at low rates trying to win it. And we see the construction market dropping off considerably for the Robotics side.

Okay, fair enough. I appreciate it, guys. I'll turn it back.

The next question is from line of Martin Malloy with Johnson Rice. Please go ahead.

Congratulations on the quarter. Just had a question on North Sea. It sounds like that could be a swing factor as you look out to 2017-2018. Just with your discussions with customers, is there a commodity price range that they have in mind where they might pick up the well intervention activities?

That's a hard question to answer. If we look back on 2016, the North Sea was a huge disappointment to us versus the visibility we thought we had on the work in talking to the operating groups in the North Sea. Going into 2017, the operating groups still have that same work, plus more. The problems are not just commodity price, it's balance sheet related to the producers in the North Sea. All the fields have multiple partners. If one partner doesn't sanction the process, it has knock-on effects to even the stronger partners. It really is a very uncertain market right now. So, we're going to be really digging into it. We've been spending a lot of time talking with the producers. But at the operating levels the things are looking more positive, but you just have to wait and see what happens at the corporate levels on the final sanctions.

Okay. The West African market, it seems like there would be a large enough installed base of mature trees to support a well intervention vessel, at least I would think part of the year. Why do you think that, that hasn't really taken hold?

Again that's another complex question. Number one, every country has its own laws governing -- contracting in the region, some require joint venture partners, others require partner presence. Then you have the issue that -- you have -- there is probably very few single clients that have sufficient work to employ an intervention, a non-rig intervention vessel on a full time basis. So, then you get into trying to put together a rig pool. And again that has certain government regulatory hurdles that you have to get over. Bottom-line is there's no permanently deployed vessel for rig alternative intervention in West Africa. And on a spot basis, with one client with one scope of work, it makes it very marginal on the commerciality to mobilize a vessel from outside the region. So, you got a number of things that’s just going to take a little time for the region to mature and get over these regulatory hurdles and have more cooperation between the producers.

I'll answer that. It's very complex to take a vessel between countries in Africa. There’s a different tax, NGTs and custom issues. Also, the clients there in Africa, they have large well counts that would require a permanent vessel. Still have a quite a lot of rig over hang at the moment in Angola, for instance.

Okay. If I could sneak one more question. The ROAM system, it seems like a pretty important extension of your capabilities. Could you maybe talk about how you see that fitting into your well intervention program next year?

Yes, we see it as an add to any of the fleets. The system will be able to go down back on to the well without a need for a riser and be able to deal with the upper parts of abandonment projects. They will be able to clean out the tubings and then we'll be able to recover the tubings open water. So, that efficiencies to the client where they don't need to bring a fuel module in an 18.5-inch BOT and riser deployments. We see that we should be able to offer solutions where a lighter intervention vessels can go in, undertake the latter part of the abandonment, do the prep work, and then we should be able to come in with the heavier vessel and then do the upper completions. So, it adds more to the heavy intervention vessels. It can be deployed from the lighter intervention vessels also because it's more aligned deployed.

Okay. Thank you.

The next question is from the line of Haithum Nokta with Clarksons Platou Securities. Please go ahead.

Hey, good morning, guys.

Good morning.

A couple of fleet questions here. On the Q5000, the 90 days that you guys will have available to -- for spot work, is that still likely to come up during the summer months?

More towards the end of the summer next year that it will be available.

Okay. On the termination revenues that you recognized during the third quarter, I presume that, that's related to the Q4000. And I guess I'm just curious, does that mean that you just basically recognized these revenues through the income statement, or was the Q4000 idle for a certain period -- idle for 42 days while it earned those revenues or was it working that entire period?

Actually, the contract was not specific to the Q4. The work could have been either Q4 or H534. So, the cancellation really just involved an acceleration of what we would have done on either the Q4 or the 534 in the fourth quarter. The Q4, as we previously stated was almost fully utilized in any event in Q3, but it’s work we had on the schedule in quarter four. The one thing the cancellation did impact is it’s unlikely we’ll bring out the 534 now, since some incremental work that we landed is strictly going to put on to Q4 now.

Okay. That is helpful. The Q4 was utilized for that full 93% period during the quarter. Okay. You mentioned the Skandi Constructer, a poor outlook for the near term. If I recall that charter comes up in about six months. Is that something that you guys have discussions on with the vessel owner? Do you anticipate redelivering that or giving it as part of your fleet to enhance your product offering? Have you -- just give us some thoughts around that.

I’d start it off by saying that we have a very good relationship with DOF around that charter. I think our interests are aligned in trying to find utilization and keep that vessel working. To that extent, we have a contractual commitment that expires April 1st and, thereafter, we’ve been in discussion with them about what we do. Other than that, I don’t know that there is a whole lot to say other than we’ll continue to seek -- my reference to expansion into other geographic markets such as Asia-Pacific and the broader North Sea probably are specific to the Skandi Constructor potential.

Understood. Okay. Just the last one, I believe you mentioned you chartered in some spot days in the robotics fleet. Can you give a sense of what magnitude of days that was?

[Indiscernible]

In robotics.

Yes, we had a spot partner arrangement with Olympic for the Olympic Canyon in the Gulf of Mexico. We didn't take any costs associated with the vessel. It just was more trying to find work and to be honest with you we didn't really achieve much utilization for the vessel.

It was a couple of weeks.

14 days or so.

It was a couple weeks' worth of spot market work. And I think interesting thing is we really didn't expect any spot market work this year since we have capacity with our fleet. So, the fact that we got anything was a little bit of a bonus for us.

Yes, certainly surprising in this environment. All right. Now, that's all for me. Thank you.

The next question is from the line of Matthew Marietta with Stevens. Please go ahead.

Hey, good morning. Thanks for taking the questions. I really wanted to clarify some of the details on the Q4000 take-or-pay proceeds. I think you guys said about $5 million or just under $5 million of impact. I guess on 42 days, that implies kind of a daily payment of $120,000. Can you help us how that payment is determined? Is that a margin? Is that a day rate or how do we think about how that is determined?

So, Matt, the $5 million that I referred to earlier was net of a lot of items that you want to -- we consider special that happened during the quarter. So, if you take that as a plus and then the minuses that Owen referred to, the net effect of all those items were sub five. So, the sub five didn't relate just to the Q4 take or pay at impact, okay?

Got it. So there is really -- so we can't back into anything with that $5 million number, obviously?

Right.

That's what I'm trying to get to.

Yeah, that's right.

Okay. And then you noted the outlook for the utilization on the Q4 was strong. I guess does this mean you picked up a bunch of spot work after that termination for the fourth quarter?

Yes. An important point is, and it's somewhat complex here in terms of the entire impact of what happened with that take-or-pay situation, but we did land incremental work, which is good. We're putting it on the Q4. But we did lose -- we did lose the opportunity to bring the 534 out, which would have been a plus, too.

But then again, we didn't incur the cost of reinstating the vessel.

Right.

That's what makes it complex.

Right. It's fairly complex. And I think the better way to look at it from your perspective, Matt, is what happened to our outlook for the year. And I think our outlook for the year, despite all this -- the stuff, remained fairly intact.

Got it. Essentially, the work was just shifted as a result of that take-or-pay termination. Okay. That helps us understand it operationally, I think.

Yes, we would have booked it in Q4. It was pretty good margin work and all we did was we had the opportunity to accelerate it into Q3. Simple as that.

I might add. We had -- we have other scheduling shifts that occurred. The reason that we mentioned this one though is just because of the dollar amount of this one.

Got it. I guess when you -- if you pull the 534 back out, what would be the capital associated that reactivating that vessel to give us kind of an understanding if we want to run that sensitivity and think about that from a CapEx or sort of cash flow perspective?

I think to bring the vessel back out would take about six to eight weeks and we’d be looking at about $5 million to do so.

Okay, great. Thanks. And then--

So, still fleet certified. It still would have been flagged COC. It just would be a case of remanning the vessel and getting it going.

I should point out though that that's the current -- to reinstate it in the current market. I should point out that a situation that we're looking at as well as all the rig owners are looking at is that the longer vessels take stack at a certain point your reinstatement costs start increasing almost exponentially. So, there is a shelf life to the stacking period of a vessel.

And maybe to clarify that, at what point do you think the economics of reactivating the vessel become more challenging given the current day rate environment? Are we looking out a year from now or six months from now or kind of help us understand the timing of that step up in the reactivation.

It would step up cost-wise about a year from now, that's when we would be having some recertification for certain aspects of the vessel.

Thanks. And then last question out of me. With the Siem 2, is there any recourse or ability of the customer, Petrobras, to change the start-up? And I guess I ask that question in the context of the ongoing start-up of the Siem 1. If there are any operational hiccups, can that impact the Siem 2 or are these totally independent of each other in the way that the contracts are negotiated? I just want to understand maybe what risk there could be on the Siem 2, if any, if there are any issues with the Siem 1.

Firstly, we have no issues at the Siem 1 and it's starting its contract pretty much bang on time for what we expected. The two vessels are on totally separate contracts and will be undertaking totally different work scopes in Brazil. One will be working on well workers well intervention purposes and the other one will be working more on P&A type works.

Great.

I would add though that you're putting a vessel through the approval process in Brazil was a first-time experience for us. And having done it now with the Siem Helix 1 my expectations would be that there's lessons to be learned that could make the Siem Helix same 2 to go a little smoother. Not saying that this is gone badly, but there's room for improvement.

Is it more on the procedural front than anything operational? Is that what you're referring to?

Totally a matter of navigating through the bureaucracy of this procedure part approval process.

Got it. Well, great. Thanks for the color. Really appreciate that. That's helpful.

The next question is from Bill Dezellem with Tieton Capital Management. Please go ahead.

Thank you. A couple of questions here. First of all, what is the incremental cost, the start-up cost with the Petrobras contract?

Sorry. Once again.

The question is just -- we just want to make sure we answer it correctly.

Sure. In the Q3 and the Q4, what is the cost of bringing the vessel on for Petrobras?

Okay. So from an accounting standpoint, financial statement standpoint all those costs are the first amortized over the contract life as well as the mobilization see that we earned. So we take the mobilization fee that we build Petrobras and immobilization cost and the net impact of that is amortized over the four-year contract.

Am I not remembering correctly that there was a reference in the press release to some costs associated with the start-up that did impact the Q3?

Yeah, talking about the startup of our office facilities, our overhead in Brazil. Obviously, we have been ramping up this year, starting in the first quarter here in the third quarter with the vessel and we are starting its transit the cost of our overhead ramped up to much higher levels of the previous quarter. We got the storage facility in [indiscernible] and the warehouse. So all those things are now at play.

The accounting treatment of those costs is different from the accounting treatment of the vessel.

Yeah, those costs are expensed, and we have incurred somewhere between $3 million to $4 million of those costs this year.

That's quite helpful. Thank you. And then the Q5000 hiccups that you had earlier in the Q3, what was the financial statement impact from those?

The financial statement impact for those pretty significant. It was about $8 million.

Is that one of the costs that you are netting against the take or pay pull forward that you had referenced before to get to the less than $5 million number?

Yes.

And then lastly, I think it was referenced as dubious before, but the $2.7 million of uncollectible accounts, could you talk just the details behind what happened with that client, so that, that nearly $3 million you wrote off?

Well, we routinely review our accounts receivable and we have a process of looking at our accounts receivable and making judgment calls as to the ultimate collectability. We made one of those judgment calls this quarter. I don't want to get too deep into the circumstances of a specific client, but it's just really a part of our ongoing process of reviewing accounts receivable.

May be fair to say to add though that there was in robotics.

Yeah.

On Well Intervention, knock on wood, we work primarily for the majors and, therefore, have had a relatively low recurrence of doubtful receivable analysis to undertake. Every now and then, though, in the robotics market you do work for the smaller contractors and this is one of the multiple smaller contractors that are struggling.

Yeah, that's good point. And if you look at historically where we had booked reserves for accounts receivable they have historically been on the robotics and in the business.

That's helpful. I just want to -- for clarity, I am not trying to put you in a box here, but that write-off was a function of the client's financial status rather than some disagreement that you and they had over the work that was done?

That is correct. It's really -- it was an assessment of their financial status.

And it's probably too early to ask this question, but as you look out over the scope of work that you are seeing, have seen and are projecting, are you seeing anything that's happening faster or better than you anticipated?

Sort of nuanced question, so let me give you a nuanced answer. The downturn is deeper than we expected. The visibility of the work is probably as expected because we're in the life of field business and therefore the work is pretty predictable that needs to be done. The number of different reasons and the amount of work that has been impacted by the commodity prices dropping during the budgeting process, the cash constraint, the partnership issues and the permitting process has probably been a little more severe than what we anticipated. The impact of rig overhangs on us from open market competition with rigs is probably as expected which is probably less than what the industry probably expected it to be. The impact to us from rig overhang of rigs that are remaining on contract with clients, but have had canceled drilling programs has probably been greater impact on us than what our expectations were.

Thank you. I appreciate all the answers.

The next question is from the line of Marshall Adkins with Raymond James. Please go ahead.

Hey, guys. Owen, a couple of big picture questions just to close this out. You have always been had one of the better insights in the offshore markets I think than most. You talked about the competitive landscape a year ago not being as bad as people thought with the influx of availability of extra deepwater rigs. It seems like that's not really showing up on the competitive horizon as you predicted. So two questions. Update us on the competitive landscape, and I would be also very curious to hear your opinion on the impact -- what you think the impact of activity would be if we get to $60 or $70 crude in terms of the mindset of the customer.

Thanks for the compliment, but I have a feeling I'm going to let you down on this. There is a lot in that. If the market goes back to 60, it depends on what happens in the shales as to what the knock-on effect is going to be offshore, but certainly 60 revives a lot of the commerciality in the projects. I think the first commercial projects that come back on stream for the deepwater are the intervention production enhancement projects. Of course, that -- the $60, then makes the net asset value on a lot of the marginal fields more positive and therefore, defers P&A work. So, $60, I don't know if it really moves the needle that much for our expectations. The rigs, the drilling programs, again it depends on the drilling programs and that again depends on the knock-on effect from what the shales do. So, it's very hard for me to predict. The way we're managing the company is just assume that we're going to have tough times for a while. The competitive landscape, as you can see from the discussion on the acceleration of this take-or-pay contract and the plus and minuses that we constantly deal with, I think that gives you a really firsthand insight as to why the rigs are ill-suited to come and compete in this spot market, because you are constantly changing your schedule. You're constantly moving things around and that's what gives us a competitive advantage. That extends beyond just the drillers to the competitors in the non-rig intervention market. We had a joint venture between FMC and Suez called FTO that looked like it could have been a viable competitor. Since the announcement of the merger, they decided to close that effort down. I don't think that it's a…

We’ve seen the benefit with the alliance now. Like we said earlier, there’s three new clients to Helix and we are offering those joint risk/de-risk terms to all of the clients. We'll also see that starting to move into the North Sea. So, the alliance has a big factor to us.

So, the bottom-line, Marshall, I think both rigs and rig-less competitors will constantly look at this market. It's a very complex market to get your head around. We've got over 25 years of doing. So, I feel very good about our position. We have some new technology such as this throne ROAM system which we do have the IP on, and I know there’s others that have probably looked at something similar, but we'll see how strong our IP is on that. And we're expanding through our alliance, our technical capabilities, the integration of the contracting styles, supplementing our service offerings with those of Schlumberger and OneSubsea. So I'm feeling pretty good about where we're sitting in the market.

That's hugely helpful. That's a good overview. But it sounds like bottom-line here is that you're not just holding your own in terms of share. That would certainly help in Schlumberger deal. You may even be creeping a little bit higher giving the moving parts of the landscape. Is that a fair summary?

Yeah. And keep in mind, historically, the work that we do was done 100% by drill rigs in the past. So, there is a lot of talk about drill rigs taking our market, but actually what's happening over the past decade here is that we've been encroaching on the drilling rig market. Now, this downturn may slow the pace of that encroachment, but I think it's a step change in technology that is becoming embraced by their producers on a broader and broader scale, and I believe going forward, Oceaneering's investment into the non-rig alternative shows the viability of the market and that it has that.

Right. Thanks guys.

The next question is from line of Chase Mulvehill with Wolfe Research. Please go ahead.

Hey. Thanks for squeezing me in. I'll try to make it quick. I guess first, a kind of a point of clarification. The less than $5 million benefit in 3Q, can we assume that, that's an EBITDA benefit? That's not a revenue number or anything like that? That's what drops to bottom-line to EBITDA, right?

Yeah, it's an EBITDA number.

Okay. All right. Were there any other kind of big items other than the Q5000 and take-or-pay termination that affected that number?

No, I think we mentioned them all.

Okay.

The rest were a multitude of smaller items.

Yes.

Okay. Awesome.

I think we still got big ones there, Chase.

Okay. All right. And then as we think about your cash position and we think about what you've done with the ATM to kind of give you more optionality. And so we look at the debt amortization payments that you have coming over the next few years, but just to exclude that, how much cash do you think you need on your balance sheet to kind of run the business just operationally?

Chase, I think we have to tie the cash to the debt. So, I think our cash needs ratchet down when our debt goes down, right? And the other variable is also CapEx. So, I think once we get through our -- this CapEx program, then our cash needs start to lighten up as well. So, there are….

So, I guess…

Those variables impact, how much cash, we'll feel we need. I think those are the biggest impacts. Obviously, we have two debt maturities coming up in 2018 that we intend to deal with sooner than that. We’re looking into that. But I don't think there’s a pad answer we can give you today on how much cash we should run our business with.

Okay. I guess what I was trying to get at is, how much cushion do you have in your cash to be able to accelerate debt payments?

Time will tell based on the EBITDA generation.

Yeah. I think EBITDA affects…

Okay.

EBITDA affects our access to our revolver as well, Chase. So, as you can see, I don't think there’s a rule of thumb answer we can give you.

I can tell you, I look at it very simplicity, we have enough cash to meet our capital obligations, which means EBITDA needs to cover our earnings through amortization. And then as long as we’re there, which is what drove the decision on the ATM being sufficient, once we get to that level, how much additional EBITDA we generate will then go long-term our strategic objective would be to lower debt once we get through the capital obligations.

Right. Okay. All right. Where do you stand about terming out or replacing some of the debt 2018 that's coming due?

Yes. First of all, the term loan, we've historically and always seek to kind of replace a rollover that facility year plus prior to maturity. That's still our plan. So, we plan to go out in 2017 and try to accomplish that. As you note from our convert repurchases, we want to do something with the converts. I mean, that's still up, that's still something we're looking -- seeking to do.

Okay. All right. Last one and then I will turn it back over. Have any of your bigger customers that have these longer term contracts come to you and tried to renegotiate price again on these contracts?

I would say last year and earlier in the year they did. We haven't had negotiations along those lines in the last six months.

Okay. All right.

I think that's what prompted my comment in the color section to say that I think we've given all on rates that we can.

Okay. All right. Thanks for all the additional color. I'll turn it back over.

There are no other questions.

Okay. Thanks for joining us today. We very much appreciate your interest and participation and look forward to having you on our fourth quarter 2016 call in February.

Ladies and gentlemen, that will conclude the conference call for today. We thank you for your participation. And you can now disconnect your lines.