Helix Energy Solutions Group Inc (HLX) 2010 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the review of the third-quarter 2010 results with investors conference call. During the presentation, all participants will be in a listen-only mode.

Afterwards we will conduct a question-and answer session. (Operator Instructions)

As a reminder, this conference is being recorded Thursday, October 28, 2010. It is now my pleasure to introduce Mr. Tony Tripodo, Chief Financial Officer. You may proceed, sir.

Thank you, France. Good morning, everyone, and thanks for joining us today. Joining me today here at Helix is Owen Kratz, our CEO; Bart Heijermans, our Chief Operating Officer; Johnny Edwards, our Executive Vice President of Oil and Gas; Alisa Johnson, our General Counsel; Lloyd Hajdik, our Senior VP of Finance. And let me also introduce to everyone Stephen Powers who reports to Lloyd and he will be taking over the IR duties from Cameron Wallace as we have asked Cameron to devote 100% of his time to marketing which is his primary responsibility.

At the end of this call, Stephen will provide you with his contact information. Hopefully you have had a chance to review our press release and related slide presentation released last night.

If you do not have a copy of these materials, both can be accessed through the investor relations tab on our website at www.Helixesg.com. The press release can be accessed under recent news 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 Private 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 2 and in our Annual Report on Form 10-K for the year ended December 31, 2009 and any subsequent Form 10-Q.

Also during this call, certain non-GAAP financial disclosures might 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 the presentation, earnings press release, our Annual Report and a replay of this broadcast are available on our website. Tony will now make some opening remarks.

Okay, moving on to slide 4 which summarizes our second-quarter results and our commentary will focus on sequential quarter results, comparing quarter three to quarter two. Quarter three's revenues increased 31% to $393 million in revenues from $299 million into quarter two, primarily owing to a substantial increase in subsea construction activity, both pipelay and ROV, as well as the deployment of the Helix Producer I on the Macondo's spill containment activities.

Gross operating margins were flat quarter to quarter at 22% as high margins earned by the Helix Producer I were offset by negative margins realized by both the Caesar and the Normand Clough on their initial jobs.

Quarter three produced EPS of $0.25 per share which was up from the $0.18 of operating EPS in the second quarter. Moving to slides five and six, along with the earnings improvement, we generated $143 million of EBITDAX in the third quarter, up from the $131 million in the second quarter.

Furthermore, we improved our bottom-line results despite the fact that we incurred $20 million of losses combined on the Caesar's first pipelay job and the Normand Clough first well intervention job. We expect the performance of these vessels to improve in the future.

In addition, the Well Enhancer was was out of service for 61 days during quarter three, undergoing a core tubing upgrade and we absorbed $9 million of hurricane risk premiums related to our weather derivative instrument. Bart will add some color on these mentioned projects later.

I will defer discussion to you on the gas side of the business to Johnny Edwards later. Obviously the big news here is the commencement of Phoenix production which began on October 19.

We're also pleased to report that our liquidity position increased to $700 million by the end of quarter three as our cash balances increased to $325 million at quarter-end and our revolving credit facility remains unused. Moving on to slide seven, and looking forward to quarter four, you should expect the contracting service business to step down from Q3 levels.

Primary reasons included the return of the Helix Producer I to the Phoenix field and thus for intercompany use, slower ROV business as the significant trenching jobs we worked on during quarter three have been completed, and we have seen activity levels in this subsector taper off, and again, normal season activity declines in the winter season as well as Caesar downtime due to vessel upgrade work.

In contrast, with the startup of production in the Phoenix field in mid-October, we expect Oil and Gas production to increase from Q3 levels and thus a corresponding increase in revenues for this segment. Bart will get into the contracting service business again later in more detail.

Over to slide eight. Slide eight updates the guidance we provided on our last conference call. With the [nine] hurricane season behind us and Phoenix production now online, we have now moved our production up to a higher end of last quarter's guidance to 45 billion cubic feet equivalent for the full year.

While there is opportunity for us to beat this number, given that unforeseen circumstances always seem to arise in this business, we believe it's prudent to stick with the 45 Bcfe. For the same reasons we cited for production, our EBITDA guidance has now been refined to $450 million compared to our previous guidance of (inaudible)

Our CapEx is projected at $200 million for the year and that assumes some E&P projects got underway, so it may not hit that level. With our hedges in place, we're forecasting realization on commodity prices to be approximately $76 for oil and slightly under $6 for natural gas and with our hedges in place, we have projected fourth-quarter production fully hedged. Now for some color on the contracting services business, I will turn the next few slides over to Bart.

Thanks, Tony, and good morning, everybody. Let's move to slide nine. Helix Contracting Services' 13 owned and chartered vessels enjoyed strong utilization in the quarter.

Three of our vessels, the the Q4000, Helix Producer I and Express worked exclusively for BP on the Macondo response in the Gulf of Mexico. The Caesar completed its first project, 47 miles of 20-inch pipeline in shallow water in the Gulf of Mexico.

This project was bid very competitively in a weak market by various pipelay contractors. Helix was successful in securing this work with the main objective of establishing a track record for the Caesar.

Lower than expected productivity of the third-party supplied automatic welding system and some vessels startup issues with a new marine crew caused Helix to incur a loss on this project. The pipelay work was completed in the third week of September and this project is thankfully behind us.

Helix's robotics subsidiary (inaudible) offshore performed very well in the quarter and so did the Seawell well intervention vessel in the North Sea. The Well Enhancer was out of service the majority of the quarter which was planned and required to complete the coiled tubing upgrades. The vessel entered its first North Sea well with coiled tubing in early October and is currently working in the North Sea deploying this technology.

[Well of Southeast Asia] is using the Normand Clough on the Lufeng well P&A project for CNOOC. The main objective of this job was to seek utilization for the Normand Clough and to introduce [deep well] through light well intervention to offshore China. With several setbacks in the field, weather downtime and some [down low] issues and equipment problems have caused this project to take longer than scheduled and hence we have booked a loss in the quarter.

Moving to slide 10. Slide 10 shows the various operating modes of the Q4000 on the Macondo response. The vessel played a key role in all the response activities and we're very proud of the work performed by our employees on our three vessels involved in the response and our employees who were active in the unified (inaudible) center and in the Helix offices.

Slide 11, Helix Contracting Services delivered record revenues of $313 million and a gross profit of $87 million for the quarter despite the mentioned losses on the Anaconda and Lufeng projects and two months of scheduled downtime for the Well Enhancer.

Slide 12 shows the equity and earnings contribution of Independence Hub, Marco Polo TLP and CloughHelix JV companies. The Normand Clough achieved in excess of 80% utilization for the quarter, (inaudible) Southeast Asia on the Lufeng projects.

Slide 13, as commented earlier, our vessel utilization was high in a relatively weak market. Credit to our employees in our service business units.

On slide 14, Contracting Services fourth-quarter outlook is shown. We expect a high utilization for our well op vessels but lower margins mainly due to the Q4000 performing lower margin well P&A work in the flex trend area of the Gulf of Mexico where the vessel competes with cheaper rigs.

The ROV support vessel will experience a seasonal slowdown. The Caesar is expected to complete her second five-day project, an 18 mile long, 18-inch pipeline for EOG Trinidad in early November after which the vessel will return to Ingleside for some equipment upgrades. The vessel is performing better on this project than she was on the Anaconda project. The Express and the Intrepid are fully booked for the remaining of the quarter. Now for our Oil and Gas business, I will turn it over to Johnny.

Good morning. Please turn to slide 15. Both slides 15 and 16 provide the financial highlights for the third quarter for Oil and Gas.

Moving beyond those financial highlights in these slides, the highlight for Oil and Gas is really the Phoenix field starting up on October 19 across the HP I floating production unit. This is an historic event for the ERT and Helix teams.

The HP I is the first deepsea floating production unit to operate in the Gulf of Mexico. And as you may remember, earlier this year, the [Danny oil well] started up the Bushwood field and is the longest oil tieback in the Gulf of Mexico. These two events this year are things that the ERT and Helix teams are very proud of.

The startup of the Phoenix field has progressed very well considering the field has been shut in for over five years when Hurricane Rita destroyed the TLP. After about a week here of what I call normal startup activity, the field is currently producing today from two wells, producing over 10,000 barrels of oil and 14 million.

And with that, our BOE net is about 7250 per day. We have a third well expected to come on and we have been up and down but we'll have that third well on in early November and the fourth well should begin producing in late November, bringing the total fill rate on a net basis to over 10,000 barrels of oil a day equivalent net to ERT.

And even with a scheduled gas pipeline shut-in for (inaudible) moved to the first -- to early December and normal field startup problems, the Phoenix field should add at least 2.5 Bcfe net to ERT in the fourth quarter of 2010. With the addition of the Phoenix production, ERT should produce more than the 45 Bcfe Tony mentioned as an estimate for 2010.

The Phoenix field has considerable development opportunity remaining beyond the four existing producible wells. Our Little Burn well was drilled and cased and only needs to be completed and tied into the HP I.

The Little Burn completion should add another 5000 barrels of oil equivalent net to ERT. And beyond Little Burn, there are additional wells to be drilled to recover updip added PUD reserves.

ERT plans to file for permits in 2010 to complete Little Burn in 2011 and drill at least one additional Phoenix well in 2011 if permitting and rig availability allows. The completion of Little Burn and the drilling opportunities in the field should provide strong oil production rates from the Phoenix field for at least three years.

The BOEMRE replacement for the MMS has released new rules on acceleration of P&A liabilities in the Gulf of Mexico which will have some impact on the timing of our platform and well abandonments. We are preparing our initial response to the BOE but we do not expect to be significantly impacted in 2011 by the new rules.

We have been very proactive in taking care of abandonment obligations over the past three years and we were already planning another aggressive abandonment program in 2011. Many of the additional wells that P&A required in 2011 under the new rules will be covered by an escrow fund already in place and fully funded for the abandonment of one of our major shelf fields.

Moving over to slide 17, slide 17 represents our hedge position, both volumes and prices, for the remainder of 2010 and 2011. The 11.7 Bcfe hedge for the remainder of 2010 reflects an almost fully hedged position for the fourth quarter 2010 and we have now hedged 22.3 Bcfe for 2011. Now I'll turn it over to you, Lloyd.

Thanks, Johnny. Slide 18 reflects the synopsis of our debt to liquidity position [and even] our cash position since the beginning of the year. We've reduced net debt levels since the beginning of 2010 by some $60 million to currently about $1.03 billion.

We expect further reductions in net debt by the end of this year. As Tony mentioned earlier, our liquidity level at September 30 now stands at approximately $700 million.

Slides 20 and 21 are the non-GAAP reconciliation schedules presented for your reference, and I'll not go over those schedules in detail on the call. At this time, I'd like to turn the call back over to Owen for his closing comments.

Good morning, everyone. We continue to operate in some pretty interesting times. Helix continues to improve both financially and operationally and we still have significant room for further improvement.

With regard to our efforts to market our Oil and Gas business, we are presently evaluating the response to our [data room] process and thus feel it's inappropriate to comment at this stage on the process. Obviously market dynamics and economic conditions have not been ideal. However, we remain committed to the divestiture of our Oil and Gas at a price we believe provides full value to our shareholders.

This quarter reflects the fact that we can generate earnings even without earnings contribution from production and in spite of the current debt service as well as some project losses we feel we will be able to resolve going forward and on top of all that, the Enhancer being out of service. I would like to say though that the production is generating positive cash and the cost of our debt overall is very good.

We've curtailed capital spending on the oil and gas side for the past two years as we focused on our balance sheet. Going into 2011 and assuming we continued on the E&P business, we will look to spend capital on the producing fields but only where we must.

Our goal will be to constrain capital spending to within the cash flow generated by the production, while holding annual production levels and proved reserve levels relatively flat. We believe this points to the positive value in our portfolio to have this -- be able to have this kind of a goal requires some real value in the portfolio.

We believe this is possible and we should still be able to generate free cash flow due to the high levels of oil production which should be going to 60/40 oil to gas with Phoenix online. Some of this result depends on what unfolds with the government regulatory uncertainties.

The drilling moratorium has been lifted but that's largely a sideshow to the real issue which is permitting. We intend to seek a drilling permit for one completion and one new exploratory well as well as some non-op interest in one or two other wells.

The permitting process could impact our production rates and our stated goals for 2011. It is still uncertain as to when permitting will resume at a level consistent with historic trends.

I personally believe that it is at least the second quarter before we see a meaningful level of permitting occurring as the regulatory requirements for the permits are worked through. One but not the only issue for permitting is the requirement for blowout containment.

The BOEMRE has not yet clearly stated what that requirement is to be in detail. Other permitting and regulatory uncertainties exist around worst-case discharge calculations, oil spill cleanup capacity, EPA study requirements as well as new requirements on drillers and equipment. It's a matter of just working through these issues with the BOEMRE.

On the service side given our heavy involvement in the Macondo well, Helix should be well positioned to offer an acceptable containment solution with the Q4000 and the HP I both for ourselves and the industry. We've been making efforts with the MWCC, BP, the independents as well as presentations in Washington with regard to this.

The high profile given to the Q4000 and HP I capabilities during the Macondo incident does have at the very least indirect positive implications for Helix. Hopefully our credibility has been greatly enhanced with regard to well intervention in the Gulf of Mexico and elsewhere.

This is important because we've been in a competition for the Statoil Cat B vessel tender. This is essentially an enhanced version of the Q4000 vessel for use on an eight-year contract by Statoil in Norway. The technical submissions are in and commercial submissions are due on November 15 with awards stated to be around year-end.

Well intervention is -- expansion is the direction that we would like to take Helix in. And if we win this award, this new vessel would be a significant step forward, clearly establishing the business identity that we are working towards, maintaining and extending our clear leadership in the deepwater well intervention service market.

Moving forward, the outlook for Helix is mixed but not as bad as some who view Helix as a Gulf of Mexico centric contractor might think. Actually 60% of Helix service revenues are generated outside of the Gulf of Mexico.

The global market is oversupplied with lower demand than usual. So, it's probably best described as being active but with some pressure on margins. We may see some margin compression in our robotics business, but we don't expect it to be severe.

Second point, our well intervention business is especially niche business. Near term it's not affected by cyclicality as it's a life of field service and producers are more and more recognizing the value of intervention for production enhancement. There are interested new competitors lurking, but the learning curve is steep and regulatory issues may be a further barrier to entry. Helix is the clear leader.

The greater near-term threat for our well intervention for the Q4000 would be from rig pricing pressures. However, even with lower rig rates given the greater efficiency of Helix methodologies, we don't see imminent pressure on our rates.

Quality of service will still be the most important factor governing rates going forward in our opinion. We anticipate a strong 2011 in our well intervention business.

Now our Production Facilities business is totally unaffected by the current Gulf of Mexico situation which leaves our significant exposure to the Gulf of Mexico other than the production issues that I mentioned on permitting being our three pipelay assets which were a fair amount in the Gulf of Mexico. Our options for pipelay in response to any potential softening in demand in the Gulf are first to seek more international work, second to seek alternative service.

For example, the Intrepid is an excellent MSV and it can be a light well intervention vessel as well. And then the final point there on the Express, we feel very confident that there will be enough workload for us to keep the Express fully utilized.

I said potential softening because we have a solid client base and it's also possible that we see less competition in the construction pipelay market from foreign contractors deciding to focus elsewhere. We have strong stable businesses in well intervention, robotics and facilities.

We feel we have our oil and gas production issues under good control, subject of course to the regulatory uncertainty. Financially we are comfortable.

We are aware that sustained growth will require capital and at the same time, we must continue to reduce debt levels. Our most fundamental strategy going forward is to grow well intervention while lowering debt which is accomplished by selling off our oil and gas assets. Our intent is to execute this strategy as the market opportunities allow us to.

With that, I will turn it back over to Stephen (multiple speakers) I'm sorry, we will go to questions first and then we'll give Stephen a chance to provide his contact information.

(Operator Instructions) Jim Rollyson, Raymond James.

Owen, I guess just to start with, the Q4000 pre-Macondo had a fair amount of work in backlog for it running through much of 2010. I think kind of last quarter, your update commentary was there's -- a lot of that work was still around and you weren't sure if you would lose some during the course of when you guys were working for BP on the Macondo project. Can you give us kind of an update on how the backlog stretches out into next year for the Q and how that looks?

Why don't I let Bart do that since he is the -- he's probably closest to the most recent update on the backlog?

Yes, the backlog is still there. We didn't lose anything. We have added additional backlog. So at this moment, I mean, the Q looks pretty good until mid-2011 and the visibility is there that we feel pretty comfortable that 2011 is going to be another good year for the Q4000.

Great, thanks for that. On the HP I, now that this quarter transitions from getting paid as a non-third party to working on Phoenix, Tony, maybe you can give us some kind of guidance on how revenues and margins look as we go -- you know, you are going to have bigger eliminations and what have you, but just kind of trying to understand how that flows from 3Q to 4Q from an income statement perspective.

Okay, very good. That's a good question, Jim.

Obviously, the trade-off here is HP I revenues turning to intercompany for the most part here is they're still 30% of the HP I's revenues because of 30% non-op interest, how it flows to the bottom line. But still the trade-off is the loss of 100% of the HP I revenues versus Phoenix production. And from a P&L standpoint, I'll just say that that's a negative trade-off mainly because of high DD&A rates on the Phoenix field.

I mean, you don't lose all of the profitability, but you lose some, I'll say that. From a cash standpoint though, it's fairly neutral. Phoenix field will generate a fair amount of cash flow.

Sure, and then just my last question, I guess. Given Phoenix is on, you've got a couple wells ramping up hopefully to four.

When you think about that in terms of your big picture production profile, since you guys are spending kind of minimal CapEx these days, do we look at a scenario where Q4 kind of Q1 production is the peak and then it kind of rolls steadily lower over time, assuming you don't ramp up CapEx? Is that a fair assessment?

Well, I'll answer that, Jim. I think number one, we are going to ramp up CapEx next year in the E&P business. As Owen said, within the confines of the cash flow we're generating for the business, we want to spend some more CapEx and again, assuming we continue to own the business.

We really look at 2011 at this point, we're not done with our budgeting process, but we are looking at it as being probably a fairly neutral year in terms of production year on year; a lot of ups and downs, it depends on hurricanes etc., etc. but it should be fairly neutral.

Perfect. Good quarter, guys.

Roger Read, Natixis Bleichroeder.

I guess -- and I apologize because I got pulled away for just a second. But when you were talking about well intervention expansion potential, can you give me a little more of an idea of what that is?

Is it acquiring a vessel? Is it just more work for the Q4000 or are we talking about even potentially building kind of a next-generation Q4000 there?

Well, we've just recently added the coiled tubing onto the Enhancer, so that should have positive implications on next year's rates from our North Sea assets. As I mentioned also, we are looking at the potential of putting light well intervention on the Intrepid for the Gulf of Mexico and we are currently -- we're not in the light intervention market there.

We're in the heavy intervention market with the Q4000. The main focus of expansion though is for the last year, we've been working in competition on a feed study project for Statoil in competition with [Auker] and [Sitam] for building what is essentially a Q4000 on steroids for the Norwegian market to an eight-year contract.

When we first built the Q4000, it was always our intention to have multiple copies because we really believed that that is the vessel of the future for our industry. So this is sort of a renewed effort in that direction.

Okay, so not necessarily a change to the way you've been looking at the market?

No, no, but the Statoil vessel would be a new-build vessel.

Right, right. Okay. And then as you look at -- and I understand when you talked earlier about your amount of business outside of the Gulf. As you look at 2011, kind of the crystal ball here for where work is most likely to be, is there a potential for you to move anything into Brazil, West Africa, kind of two markets you haven't really been in all that much historically? Something beyond I guess the Southeast Asian market where you've got the joint venture and you've worked a lot historically.

Bart, you want to address that?

Yes, in West Africa, we have been active this year. We had one of our ROV support vessels working for (inaudible) Anadarko on the Jubilee project. We just completed that work.

So, this year we spent eight months of time there. We also have a couple of ROVs working on the a third-party boat in the area.

I mean, we see opportunities in West Africa to deploy one ROV support vessel on a full-time basis. So we are working towards securing that work.

So, we really haven't been active in Brazil. And at this moment, we don't -- for our fleet of vessels, we don't see a lot of opportunity there.

We still lag the North Sea where we have been very active with well ops and also with our trenching business offshore Norway. There's also a renewable energy market for offshore wind farms where we have been growing our market share from a trenching perspective. So, that's the color I can share.

Okay, thanks. Then the final question, the P&A work that will be done on the shelf fields, you mentioned an escrow number. Can you just give us an idea of how that flows through? Do we see that in CapEx or is it simply a balance sheet change?

That's just a balance sheet change, Roger. We have our P&A obligations booked as a liability. So it comes off as a liability. The field that Johnny was talking about, we have -- and it's not reflected in our cash balance and escrow account for the South Marsh Island field and we have $35 million in escrow for that. So for the most part, that's just trade and balance sheet accounts.

So it's a cash impact but it's cash that's already set aside?

For that particular field, yes. And that's probably our largest P&A obligation for next year, right, Johnny?

The largest well P&A obligation.

Yes.

Okay, so that's basically half of the P&A expenditure next year, right?

Probably not, less than that (multiple speakers)

A little less than that, okay. All right, thank you.

Martin Malloy, Johnson Rice.

Could you talk a little bit about the impact on your DD&A rate and your listing costs from Phoenix coming online? Maybe if you could give it in a dollar per BOE or dollar per Mcfe?

Let me just talk about, Marty, on Phoenix, our DD&A rate is over 5 dollars an M -- OpEx excluding the HP I, Johnny?

That's about 700,000 a month. So that's going to add another $0.50 or so, that's oil.

The LOE is not big if you exclude the intercompany charge for the HP I, Marty.

And it's an oil price (inaudible)

Could you talk a little bit about the Caesar and going into dry dock or to get the thrusters put on, I guess not in dry dock? But is that going to fix the issues that you feel negatively impacted the vessel during the third quarter?

This is Bart. Really what's caused the negative impact to me was the ramp-up. We are on the learning curve with this vessel.

This vessel is a complicated offshore welding factory. And so, the main setback was -- you got new welders, you got the new marine crew, so the welding productivity was lower but it ramped up through the project and we have seen -- continued to see that ramp-up on the EOG project that we are doing at this moment offshore Trinidad where we still have around five days of pipelay work left. So that's a learning curve that we have seen.

On the marine side of the vessel, there are a couple of things that we need to do to make the vessel a little bit more reliable. Again, when you start working on a vessel like this, I mean on this first big job, we were lucky to have 47 miles of 20-inch pipelay job. So we found out -- we identified the areas where we need to work on and that's what we will be doing really for the second half of November and December, is to make it a more reliable vessel with higher productivity. So that's our focus for the rest of the year.

Philip Dodge, Tuohy Brothers Investments Research.

You talked a little bit about the -- looking forward on the Q4000. Can you tell us your total intervention fleet, including the Seawell and the Enhancer, how much is booked at this point for 2011?

As I mentioned, the Q4000, we have backlog until the middle of the year. We see there's quite some bidding activity, so we feel comfortable that next year we will be witnessing another year of good utilization.

The same story applies to the Seawell and the Well Enhancer where we've got a couple of gaps in our schedule for the Well Enhancer for early 2011. But then especially because of the coiled tubing upgrades, that's going to be used to decommission several wells and fields in the North Sea.

We think that's going to help with the rates as Owen mentioned, but also with the utilization of the vessel. So, overall for the Seawell and the Well Enhancer, we're pretty positive for 2011.

And then we've got a fourth vessel which is the Normand Clough which is a multiservice vessel that can be used for well intervention (inaudible) well intervention projects offshore Australia that we are bidding on. So we hope to secure that work.

If not, that vessel can also be used as a DSV, as a dive support vessel or as a light construction vessel. And so we together with our partner, Clough, are actively marketing that vessel in the Southeast Asia region. So overall on the well intervention side, we have the backlog and we have the visibility.

Okay, just related to that, if I knew this, I have forgotten. But how much is the uplift on the Enhancer for the coiled tubing capability?

I don't have the number here right in front of me. I think it's -- it depends also if you capitalize the cost of the marine crew etc. during that period. But I think it was somewhere around the 10 to 15 million.

Fine, thanks. And then (multiple speakers)

Sorry, that was the CapEx required.

Phil, let us get back to you because I don't think that we -- we have got some contracts here and varying rates. Let us get back to you with the exact uplift number on the rate.

All right, Owen. Just the final one on the idle iron, looking ahead with the new BOEMRE pronouncement, can you give us a metric on that of what you see in the next two or three years in terms of well and platform shutdowns, say, compared to 2010 as a base?

Yes, I could talk a little bit about that. This is Johnny Edwards.

We are in the process of putting together the final submission of the information to the BOE and it appears we have about 200 wells that will move forward in the schedule for a couple of years. So that -- in 2011 most of those wells will be as I mentioned on South Marsh 130 and 2012 and 2013, we will have some more well accelerations.

So we are talking maybe -- we're not increasing our ARO, we're just moving it forward in the 60 million or -- 50 million to 60 million which part of that is covered by the South Marsh 130 (multiple speakers)

I was also thinking of the industry as a whole and how you might be able to participate in that with the Intrepid or some other --

This is Owen. I think the hockey stick projection of abandonment work driven by this latest NTL is perhaps a little overstated.

I think the industry since Rita and Katrina have been working overtime to get caught up on ARO issues. I know certainly we have.

But having said that, keep in mind that the NTL allows you three years to get this work done. So to the extent you see producers out there that have a lot of work, I would not expect it to ramp up right away which gives us time to really consider putting the light intervention on the Intrepid.

And as you said, the Intrepid is a very, very capable construction asset with a 400-ton crane. So there's an awful lot of small salvage and P&A work that it would then be suited to do. That's one of the mechanisms by which we are making our plans so that we feel a little more comfortable about her full utilization next year.

All right, that's all I had. Thank you very much.

(Operator Instructions) Stephen Gengaro, Jefferies & Co.

Can you give us sort of just an overall view of how you see sort of the contracting service market evolving over the next several quarters? There's been a lot of noise obviously with the drilling ban.

You had a good quarter which was obviously boosted by some of the BP stuff. But how should we think about the pricing and utilization and how you think this thing plays out over the next couple of quarters?

I'll take a shot. You know, we've always told investment community that the downstream construction market lags drilling by 12 to 24 months.

If you take that as an assumption and drilling ceased in May and has not yet resumed really because of the permitting issues, and assuming permitting does start to move again by May, you're looking at a one-year hiatus from drilling which then should start to see impact sometime late in 2011 running through 2012. Now that's on the construction side.

Having said that though, when we saw the drilling moratorium put in place, pipeline permits also were frozen for some inexplicable reason. So there is a certain amount of backlog in the system waiting to be done which could carry the first part of 2011.

But I do think you're going to see a slower Gulf of Mexico construction market late 2011 through 2012. But then that is going to put more emphasis on production enhancement and well intervention as a means of increasing production and capturing greater reserves. So all in all, that's my read on it.

That's helpful, that's all I had. Thank you.

Vance Shaw, Credit Suisse.

I just wanted to ask a question on the portable converts and sort of what financing options you guys are taking a look at. I guess it's [portable] in December 2012, so you have some time, but I was wondering if you had any thoughts.

Well, I think we've got several options at this point. Number one, we're carrying a fair amount of cash balances and we expect to build cash balances over the next two years.

Number two, our credit facility is unused. That's a $425 million facility. So we have plenty of liquidity in the event of a put by the holders.

And then there's always the option of refinancing which I don't think we want to consider today given that it's over two years out and we're in such a strong liquidity position. But, I will say that's one of the reasons why we're building liquidity. In the event that it is put, we will be prepared.

Super, thanks very much. And congratulations on a good quarter.

[Sindry Survai], Orkla.

This is [Sindry Survai] from Orkla in Oslo. Congratulations with good results.

I just wondered if you could elaborate a little on the status on the divestment on the E&P portfolio especially in the light of to -- at least to my surprise, there is already a few deals going on there, most recently there is the PXP deal announced in September and they also speak to their schedule of divesting their deep well server assets by later this year. So, how is the outlook for your divestments?

I'll take that. As Owen mentioned, I think our process is still an ongoing process. We're at a stage where we really don't feel appropriate to comment on it.

I think the Plains transaction was a particular transaction that had certain attributes that made it go that don't apply to the rest of the industry. But overall, I don't think we're in a position to comment right now.

Okay, thank you.

Michael Marino, Stephens.

Quick question on the Normand Clough or the project there. When does that wrap up?

Yes, this is Bart. We expect that will wrap up at the end of this quarter.

Okay and everything to date is still going as planned?

As I mentioned earlier, we have had -- we booked a loss in the quarter, so that's an indication that it didn't go exactly as per plan because we had some [down low] issues and we had some equipment problems. I mean, we're still trying to get some variation orders signed with the customer but that hasn't (multiple speakers)

Which quarter is -- I guess a quarter (multiple speakers)

It hasn't happened.

(multiple speakers) Michael, just to clarify, we have taken a look out to the completion of the project in quarter four and booked the entire loss in quarter three. So we projected out what the loss on the project is and the way accounting rules work, you have to book it if you feel like you're going to have a loss. So it's really -- it's all been absorbed in Q3.

Yes, just wanted to make sure. And then on the Caesar, will that be fully available for 2011 or does that dry dock spill into 2011?

We will have some downtime that -- we will have some vessel downtime in early 2011. But for the majority of the year, the vessel will be available.

And I guess, remind us again, that vessel was very underutilized in 2010, so kind of year over year, the outlook is still pretty good for that vessel even in the current market environment.

Yes, it joined the fleet in I think it was June of this year. We've been working her since early July. And of course we have introduced this asset in a weak market, so I mean, hopefully the market will get stronger in the next couple of years.

Okay, thank you.

Maybe it is fair to say that the Caesar is probably the singular asset that presents the greatest challenge to us next year on finding utilization on it.

Phyllis Camara, Pax Growth Funds.

You mentioned I think that you have got a backlog of $300 million so far. Normally in the past, how far out do you book jobs?

And are you seeing -- has it been just primarily because of the Gulf of Mexico that it's been different, if it is different? Or is this something that is typically -- your jobs last for two months and three months and you have to -- or continuously basically looking for work for your assets?

Let me answer that question. We normally have a rolling six-month backlog. That's what we're used to with our assets.

I mean, we're not an epic construction company where you have a three-year backlog. We're very comfortable with having a three to six months backlog for our assets and so this is a number that we are comfortable with.

And are you seeing -- has bidding activity or people seeking bids for work, has that improved at all since the moratorium was lifted or are you still not seeing any activity at all for like six months out or 12 months out, something like that?

I mean, the lifting of the moratorium hasn't had any impact on the business because I mean, there's some permit moratorium at the moment. Nobody gets a permit to drill a well.

What Owen mentioned earlier is that it was also -- I mean, producers, operators had difficulty getting their pipeline permits and that was for projects that had been sanctioned, deepwater pipelines where pipe had been procured and we had pipe welded at [spool base] ready to be installed. But those operators didn't get the permits.

That has changed. They have been receiving the permits over the last couple of months and so that is work now that we have in our backlog work that we will execute in the next six months with Express and Intrepid in the Gulf of Mexico. But for the rest, it really depends on these permits being issued and for the drilling to recommence.

And then in other parts of the world like in the North Sea, are you seeing bidding activity picking up or increasing or has it just held fairly stable throughout this whole thing?

Yes, it has been very stable. Of course all the regulators around the world are looking what's happening in the Gulf of Mexico. But we haven't seen any impact on any projects or any drilling activity in other parts of the world.

Great, thank you.

We have no further questions at this time. You may proceed with your presentation or closing remarks.

Hi, everyone, this is Stephen Powers. Just before we wrap up the call, I would like to provide you my contact information.

My direct line is 281-848-6644 and my e-mail address is SPowers@HelixESG.com. Thanks everyone for joining us today. We thank you for your interest in Helix and very much appreciate your participation on today's call.

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and kindly ask that you please disconnect your lines. Have a great day, everyone.