Helix Energy Solutions Group, Inc. (HLX) Q1 2011 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the Helix Energy Solutions Group. Review of First Quarter 2011 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, Tuesday, April 26th, 2011. I would now like to turn the conference over to Stephen Powers. Please go ahead, sir.

Thank you. Good morning, everyone and thanks for joining us. Here with me today is Owen Kratz, our CEO; Tony Tripodo, Chief Financial Officer, Johnny Edwards, Executive Vice President of Oil and Gas; Alisa Johnson, our General Counsel and Lloyd Hajdik, our SVP Finance. Hopefully, you’ve had an opportunity to review our press release and the related slide presentation release last night. If you do not have a copy of these materials, both can be accessed through the investor relations page on our web site at www.helixesg.com. The press release can be accessed under the press release’s 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?

Thank you. 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 any associated presentation other than statements of historical facts are forward-looking statements and are made under the Safe Harbor provisions under 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 two and in our annual report on Form 10-K for the year ended December 31st, 2010. Also during this call, certain non-GAAP financial disclosures may be made. In accordance with SEC rules, the final slides of our presentation material 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 replay of this broadcast are available on our website. Tony?

Thanks. Good morning. Moving over to slide five summarizing first quarter results. We reported a sharp increase in earnings and EBITDA for quarter one with earnings of $0.24 share and EBITA rising 149 million up from 95 million in the prior quarter. Quarter one’s revenues declined slightly from the 306 million in Q4 to 292 million reflecting weak contracting services activity in the Gulf of Mexico that was almost entirely offset by higher oil and gas revenues. Oil and gas revenues rose 23% in quarter one versus the prior quarter reflecting a full quarter of production on the Phoenix field as well as higher oil prices. Well looking back to a year ago, which was quarter one ‘11 represented a sharp increase in revenues, earnings and EBITDA again with our oil and gas business leading a way for this comparative period. Over to slide six and seven, we generated nice amount of free cash flow in quarter one as our cash balances increased by 50 million during the quarter to 441 million at March 31st. Our total liquidity at quarter end increased to 837 million and given the size of our balance sheet that’s a significant amount of liquidity. Again our oil and gas business led the way for quarter one results as our contracting services business was impacted by the low levels of activity in the Gulf of Mexico as a slow pace of permitting has impacted all offshore activities in the Gulf and pipelines all the way to drilling. We are expiring our contracting service business continues to be well intervention both in the Gulf as well as in the North Sea. Production rate in the first quarter averaged to 160 million cubic feet a day production in the quarter up 14.4 million cubic feet equivalent, with 63% of that production being oil. Production from the Phoenix field averaged 12,001 barrels of oil equivalent a day net to our interest. Furthermore, much of our oil production is sold at a premium price to quoted WTI prices due to factor that Johnny Edwards will get into later. Our realized oil and gas prices for the first quarter inclusive of hedges were slightly better than $90 per barrel of oil and $5.77 per gas. Our realized gas prices benefited from natural gas liquid sales. I will now turn the call over to Owen for in-depth discussion of our contracting services business.

Thanks Tony. Good morning everyone. Let’s look now to slide nine, (inaudible) margins improved on a sequential basis, primarily due to the loss that we incurred on the Lufeng abandonment project offshore in China in the fourth quarter of 2010. Moving over to slide 10. This slide shows the equity and earnings contribution of Independence Hub, Marco Polo and the CloughHelix JV. The results are fairly consistence with the Q4, so I will leave this slide, I wanted to review at your leisure. Over to slide 11, our well intervention business achieved a 77% utilization in Q1. The Q4000 achieved 88% utilization during the quarter working for some of our key customers and as a healthy and visible backlog for the remainder of 2011. The Seawell encountered 7 days of weather downtime and was down for another 17 days for repair and maintenance, but otherwise fully utilized for the quarter. The Well Enhancer was down for 40 days in January and February for R&M and was fully utilized for the remainder of the quarter. Both vessels continue to remain strong and visible backlogs for the remainder of 2011. So, we see we would expect strong results as the year goes on. The Normand Clough again worked on a day rate construction job that will continue through the third quarter. Moving to slide 12, as a mentioned a minutes ago, weakness in the Gulf of Mexico construction market posed a challenge for our domestic Robotics business in recent month. That said, roughly two-thirds of our Robotics business resides outside of the Gulf and we expect this segments performance to improve throughout the year. We recently secured a 1 to 2 year contract in India for the Olympic Canyon. The Island Pioneer is fully booked until the fourth quarter to do trenching work in the North Sea. And the Deep Cygnus is built at the healthy backlog at wind farm development and trenching work in the North Sea as well. While the business is off to a slow start, all five of our chartered vessels are now utilized and utilization of our trenching and ROV assets in trending upward. On slide 13, our Subsea Construction assets operated to 33% of utilization for the quarter. The Caesar spent the quarter in the shipyard undergoing maintenance and upgrades, while the Intrepid and the Express completed a few small projects in the Gulf of Mexico. The Express is now deployed on 170,000 foot pipelay job for Deep Gulf’s [Condor] field and we are working to build a campaign of projects into the fourth quarter. The Intrepid is currently [dark side] but it will be deployed delay 100,000 feet of seven inch pipe on our own Eugene Island 302 field in May. We then schedule to mobilize the California mid-year where we are working to build campaign around work that we have already secured and contracted. Over-supply of pipelay assets in the Gulf of Mexico coupled with customers permitting issue to present a significant challenges for this segment of our business but we are working hard to secure projects for the assets. Slide 14 illustrates the current design of our deepwater containment system, the Helix Fast Response System, which we discussed on our year-end conference call. Since that call four more producers have joined the consortium brining the current number of participants to 24, and six drilling permits have been approved citing our system as the key component as the spill response plan to satisfy BOEMRE regulations. The system is currently capable of capturing and processing up to 55,000 barrels per day in water depth to 8,000 feet. And we continue to work with members of our consortium to expand the system with the objective of increasing capacity in later lenient redundancy. In the near to mid term the HWTG plan to upgrade from our current 10,000 psi well cap to 15,000 psi cap. This is a dynamic solution and it will continue to evolve over time. On slide 15, this slide shows the utilization we achieved with our Contracting Services assets in Q1. And I will leave it for you to look at, but there is obviously upside potential through greater utilization. Now for our oil and gas business I will turn it over to Johnny.

Good morning. Please turn to slide 16, both slide 16 and 17 provide the financial highlights for oil and gas for the first quarter. As shown on the slide ERT had a great first quarter. ERT’s production for the quarter was 14.4 Bcfe compared to 13.7 for the fourth quarter. The increase in production driven by our strong Phoenix production changed our product mix up to 63% for the first quarter of 2011 compared to 51% from the fourth quarter 2010. This increased production, the change in product mix and a higher oil price realization increased our revenues to 169 million compared to 137 million in the fourth quarter. Turning to slide 17, our operating cost was slightly lower first quarter 2011 compared to fourth quarter 2010. Operating expenses by 10 million compared to Q1 2010 primarily reflecting the cost of our HP I utilized in the Phoenix field. As Tony mentioned earlier ERT’s production for the first quarter averaged to 160 million a day equivalent. The increase in production over the fourth quarter is associated with the full order of Phoenix production. In early January, the four Phoenix well was bought online. The Phoenix field averaged 12,100 barrels of oil equivalent per day or just over 40% of ERT’s net production. The Phoenix field continues to produce over 10,000 barrel oil day equivalent per day net and we can say that Phoenix field has exceeded our expectations. Our current production in April is averaging 140 million in cubic feet a day equivalent. Our production is being impacted by mechanical issues at our Noonan well and some inter mid and third-party pipeline outages. We also additionally have been advised that there will be some future schedule of third-party pipeline outages that will affect oil production including 10 to 12 days at our Phoenix field. We continue to focus our capital dollars on oil projects in 2011 where we can develop our proved and probable undeveloped oil reserves. A Little Burn completion in the Phoenix field is one of our key projects in 2011. We currently have a rig on location completing the Little Burn well and expect to add an estimated 4500 barrels a day equivalent by mid year. Little Burn well was drilled by BHP in 2005 part of hurricane Rita destroying the TLP structure. The infrastructure is in place now to hook up the well quickly to the HP I. We also have oil projects on the shelves we are developing in 2011, we currently have a rig on Eugene Island 302 which is finishing up the completion on a well that ERT drilled in early 2010. We expect this well to add 800 barrels equivalent by mid year pendings BOEMRE approval for a sales pipeline. Second, we are currently mobilizing our platform rig to our South Marsh 130 field to workover 8 to 10 wells. The well work program is targeting oil reservoirs behind pipe which have not been depleted. ERT expects to add another 1000 barrels of oil a day production in 2011 from this workover program. The follow-up on Tony’s earlier comments, ERT’s oil production is primarily marketed with the Gulf Coast Cruise. Current the Gulf Coast Cruise are trading at a premium when compared to WTI prices actually tracking closer to Brent pricing. During the first quarter our oil price realization benefited by 3 million from this premium. However, we expect based on the current premium above WTI we estimate the benefit by as much as 10 to 15 million in the second quarter. On the exploration front we have plans to participate in the drilling of two deepwater exploration wells contingent upon permit approval by the BOEMRE and rig availability. The first prospect is Kathleen prospect in the Bushwood field. The Kathleen well is a look-alike to our Danny oil well the permit has been filed with the BOEMRE. And the second exploration well targets the Phoenix field our Wang prospect. The well is targeting an untested section of the main field play which most of the other Phoenix wells produced from. Currently ERT has 70% interest in the Wang well and the permit has not been filed yet though expected by the permit by mid year. Both of these exploration wells discussed or in existing field with existing infrastructure to handle the production, both target oil and they both carry a reasonable chance of success. Over to you, Lloyd.

Thanks Johnny. Turning to slide 18. Slide 18 represents our commodity hedge positions of volumes and prices for the balance of 2011 and 2012. For 20 Bcfe equivalent hedge for the remainder of 2011 covers about 53% of our forecast combined production for April through December. Of the approximate 20 Bcfe and hedges for the balance of this year, the break down of 63%, 37% gas and this is inline with our average daily production rate with two-thirds of our production coming from oil. For 2012 we have hedged a portion of our estimated production and we'll continue to opportunistically put hedges in place to cover the majority of our forecast in production. Turning over to slide 20. Slide 20 profiles our current debt and liquidity position as of March 31. In the first quarter we reduced net debt to $51 million from December 31, as our cash on hand increased correspondingly the 441 million (inaudible). Based on our outlook for the balance of 2011 we expect further decreases in our net debt provision from the March 31 level. Tony.

Turning to slide 22, where we have provided an updated overview for our outlook on 2011. In general we have upgraded our outlook for 2011 for what we outlined a couple of months ago. First, we now forecast oil and gas production at 50 Bcfe up 1 Bcfe from our original forecast. Our commodity price outlook net of hedges is $96 for oil and slightly better than $5 for gas. On the oil side we are definitely benefiting from the Gulf Cruise pricing premium and on natural gas side we are benefiting from both our hedges and natural gas liquids by product production. We now forecast EBITDA for 2011 at 550 million, this is up considerably to the original outlook of 475 million and again up substantially from last year of 430 million. CapEx spending is pegged at 250 million a slight increase in the power upgrades plan for the Caesar. And as the level of EBITDA with the forecast to the level of CapEx for the year we should generate a nice amount of free cash flow in 2011 allowing us to increase for cash balances from the already healthy $441 million level at March 31. Turning to slide 23 and 24, we provide little bit more color on our outlook. On Contracting Services side, we booked a nice level of backlog for our well intervention vessel, the Q4000 is nearly fully booked for all of the year and both the Well Enhancer and the Seawell appearing a solid book of business as well. Well both the Express and Intrepid have contracted backlog, the permitting process in the Gulf of Mexico has frustrated our ability to put these vessels to work. Nonetheless, we expect the second half of the year for a Subsea construction business to be much better as permit start to get issued and this vessels go to work. The Express is already back to work today. As far as the Caesar goes, we are in a way taking advantage of the slow activity levels in the Gulf to continue on with the power system upgrades for this vessel. We expect that Caesar remain import to these upgrades through August. Again our Robotics business most likely hit its low point in Q1 and the business outlook is much stronger for the rest of the year and as Owen said earlier we have now all five of our construction support vessels to work. Oil and gas production forecast is 50 Bcfe as two critical assumptions, no significant tropical storm activity in the Gulf of Mexico and the Little Burn production commencing mid year. Again we have secured to permit to complete this well and Johnny said the rig is on location and working to do that. Our CapEx of 250 million breaks down to 85 million for Contracting Services and 160 million for oil and gas. And Contracting Services numbers contains little spending above the maintenance other than some upgrades for the HP I to enhance spill containment profile. Some incremental investment in our historically profitable Robotics business and the power upgrades for the Caesar. We have assumed no CapEx associated with the potential for the Cat B vessel for Statoil. The major items in the oil and gas spending are 165 million includes the Little Burn completion and the drilling of the two exploratory wells that Johnny mentioned Kathleen in the Bushwood field and Wang in the Phoenix field. Both of these exploratory wells targets oil, and spending will be contingent upon securing the necessary drilling permits and I think it's important to point out our production forecast assumes no production from these wells in 2011. Furthermore and as a result of the strong oil price environment we are quietly developing the Shelf field as Johnny mentioned earlier. Back to you Lloyd.

Slide 26 and 27, our non-GAAP reconciliations schedule presented here for your reference. I will not necessarily schedule the detail on the cal, and at this time I will turn the call back over to Owen for his closing comments. Owen.

Thanks Lloyd. As Tony mentioned Helix reported strong first quarter and we are pleased to upgrade our outlook for the remainder of the year. We have come a long way over the past few year's to streamline our business model and improve capital spending, and discipline, improve project execution and strengthen the balance sheet. While the regulatory environment in the Gulf of Mexico presents a challenge to our entire industry our business model is growing more robust which enables us to weather such uncertainties and challenges competitively. We are proud of what our teams have accomplished, but there is still much to do, and we will continue to reduce debt and make improvement in debt structure. We will continue to aggressively pursue both opportunities particularly in low ops where Helix is not only the early adopter but also the clear global leader. As you are aware we announced a little over a year ago that we have engaged advisors to assist us with evaluating potential alternatives for the sale of the oil and gas business. About a month after that announcement our industry suffered the worst environmental and our operational disaster in the history of the Gulf when the Macondo well blew. The regulatory hangover from that event has resulted us in a very challenging environment for the sale of our entire oil and gas business. Meanwhile, our favorable oil prices and strong production of Phoenix which had a very positive impact from our financial condition. As a result of these factors we determine that we can build more value for the business and their shareholders by developing additional proved developed reserves and converting our high value PUDs. That sets our plan for the remainder of the year, pursued development of a portion of our significant PUD inventory and to drill some of our existing exploration prospects with the focus on oil to generate higher cash flow rather than selling the entire business at this time. We will continue to evaluate the conventional sale of this specific properties as opportunities arise in which we deem to be in the best interest in terms of economic returns and risk mitigation. We believe we can garner more value at this approach given the current regulatory environment, favorable commodity prices and the size and quality of our PUD inventory. I would also like to make a few comments on the status of the Statoil Cat B opportunity. At the time of our year end call we were expecting a tender award announcement around the end of March. That announcement has been pushed to the later part of this year as Statoil’s requested the competitors undertake advanced engineering studies related to the riser stack. We have agreed to engage in the feed study and maintain our competitive position in this complex bidding process and we will keep you continually informed of progress as we work through it. This will be the largest project that Helix has ever undertaken which help to reinforce our global leadership and well intervention. It's an important opportunity but it's not our only opportunity. Well intervention is important to the future of our company. Helix is the global leader in this space and we intent to maintain this competitive position. So, we will continue to build the liquidity necessary to fund our future growth and reduce our debt level. We cut our net debt in half in little over two year's and we won’t try to reduce that position further in 2011. The takeaway for this quarter is that Helix is executing a strategic transformation building a strong balance sheet, fortifying it's competitive position and delivering quality earnings in a challenging environment. We look forward to the future with this confidence and optimism. And with that I will turn it back over to the operator for Q&A.

(Operator Instructions). And our first question comes from the line of Marshall Adkins with Raymond James. Please proceed.

Owen, after a touch and go four or five years here, you're looking awfully brilliant with the hybrid contracting E&P model for the first quarter I can remember. Sounds a little like you're rethinking the whole let's divest of E&P and go to a straight contracting model. Am I reading that right?

We are first and foremast Marshall service contracting company and we are getting back there, right now though cash and value is king, we have a balance sheet that needs restoration for us to really take advantage of the growth opportunities we have in from well intervention. And it's the matter of being flexible and we are responding to the market in the manner that generates the highest level of cash and value, and that’s what gets us to the end game the fastest.

Well, it certainly showed up this quarter. Fill me in on your optimism for the contracting side. I know we've had a few permits here issued in the Gulf, but it sounds like you're starting to see other stuff. Is that the international market coming through, or maybe just share with me what you think the time lag will be between these permits getting issued and that leading to eventual work for your asset?

It's sort of interesting and I may or may not be right in this, but the documents surely definitely in a big swamp because of the lack of drilling. If you were to start drilling at normal permitted levels today you are probably looking at 2013 before a normalization in the market. Now that sound a bad quarter for us here, on the contracting side which we anticipated, but I think one thing the consequence of that is that with the international markets remaining robust, I think the competition is more keen to deploy assets elsewhere which is given us the opportunity to actually have a little better visibility on utilizing our assets here in the Gulf than what we might have expected looking forward from the fourth quarter of last year. So, I’m not predicting great things it's going to be bad in the Gulf of Mexico, but probably not as bad as we were anticipating in the fourth quarter.

So, it sounds like, really, the international market picking up is tightening the whole system, and you're certainly seeing that reflected in your order book, or however you want to phrase it right now.

I think we are starting to see the visibility of utilization pick up for the rest of the year and that would be my best guess as to what to attribute it to.

Last question for me. I know you've been somewhat coy on this in the past. Help us to understand pricing for the well system that's being bid for all these permits. What are you getting out of that, and/or it seems as if the competing system doesn't have the surface storage facilities that you have. Could you comment on how your system shapes up versus the Exxon-lead group, whatever that's called?

Let me take the proceeds that we are receiving from large consortium group first. We rather not get into the details of how much are being spend, but it's not a company maker. We are basically, our assets are here, they are working the HP I and the Q4000 which are the target based system, they are working. So, we are basically making them available to the consortium in order to get the industry going again. How we are doing that is a little different from the MWCC, the philosophy or the approach is we are looking at existing assets and what can we mobilize in the fastest way possible. Now that may not be a system that’s all inclusive of every well that everyone wants to drill in the Gulf, but it covers the predominant number and gets the industry moving again. Whereas I believe the MWCC is taking a little broader stroke at it creating a system with more capacity, probably slower in responding. So, I think between the two systems there is an application which is focusing on what can we do today and what can we get out in the fastest way possible.

That being said, we are being paid a retainer by the consortium, a stand-by retainer.

Right. But the preponderance of your business is not going to be that. It's just the add-on.

Right. Like I said it's not a company maker. Everyone shouldn’t read too much into that retainer.

Well, it's good to see the hard work pay off this quarter. Thanks, guys.

Thanks Marshall.

The next question comes from the line of Roger Read with Morgan, Keegan. Please proceed.

Hey, good morning guys.

Good morning.

Like Marshall said, congratulations on having the right business model here.

(Inaudible).

Story of my golf game anyway. On the oil and gas production side in the second quarter, can we get a little bit more clarity on the impact of the pipeline issues and is that pretty much a Q2 event, Q2 and Q3 spread out throughout the year? I just wanted to kind of help understand how the quarters roll out within that 50b number.

In terms of production Roger, I will give you a broad, conceptually you expect to see because of natural declines and the other issues Johnny mentioned too will come down a bit. Q3 will recover as Little Burn comes on the production, and some of the Shelf development work we’re doing also comes on. And then I think you see quarter four take maybe a slight dip from Q3. So, generally speaking our highest quarter could be quarter three depended upon how Little Burn comes on, but Q2 it will come down again because of natural declines. Okay.

Okay. Kind of using the 160 to 140 change we've seen so far?

Yes.

As an indicator?

As an indicator, yes. Although as Johnny said, some of that decrease from 160, 140 is coming from production problems at Noonan and I guess the silver lining in that is gas.

I understand. 0wen, probably a question for you. I understand all challenges in the Gulf, the repositioning of the Intrepid here this summer. What else, as you look globally, and clearly globally we haven't had the same challenges in the deepwater drilling side, what can you do what would you be willing to do in terms of maybe it's the Caesar, since it's clearly not going to be working until the latter part of the year anyway, but do you move one of these vessels overseas on a semi permanent basis until the Gulf shows significant recovery in drilling, and then the follow-on construction work?

Well the Caesar I think has always been a global asset. So, that drive will move globally. The others I wouldn’t say a permanent move, I think I described it as we are looking to work with other contractors more closely in a range maybe taking the assets out of Gulf on campaign basis.

Which the Intrepid already is schedule to work in California in the back half of the year already is subject to permitting, but we already got the Intrepid moving out of the Gulf and the Express is working on projects assets, bidding on projects outside the Gulf.

Roughly close to the Gulf in the sense of Trinidad, or should we think of it as truly the Middle East or Asia Pacific or something like that?

Everywhere.

Okay. And then the final question, Owen, you mentioned, as you looked at that time E&P business, you'd love to sell as one piece, but maybe not in terms of what the market will allow today, but what sort of interest have you had or have you very much marketed the business at this point in terms of selling particular portions, or as we saw a few years ago, when interests were sold within some of your deepwater portfolio? Just give us an idea of maybe what you're looking at as a way to continue to monetize the business.

Well I think it's a difficult market at best to monetize Gulf of Mexico based E&P business. I think specific to our properties though you have to consider the 60% of proven reserves our PUD. So, the value equation, generally the debt that we ran up in order to drill them, the value equation for what we can get for a PUD makes it's a questionable proposition eventually in a tough market. PDP, our proven developed producing is from the comp deal that we have seen is still carry a relatively robust value. So, I think the better long-term value for us would be to continue to look for opportunities to sell packages of PDP, which we were doing for the last few year's and is the normal part of our business. We then reallocate the capital to PUD conversion to PDP and I think what you wind up with is some pretty positives free cash flow over the near-term without any diminishing of the value of the remaining portfolio. So, I think for the long-term value it makes sense to pull that from marketing the whole thing right now, selling down PDP and then concentrating on PUD conversion.

Okay, thank you.

The next question comes from the line of Michael Marino with Stephens Incorporated. Please proceed.

Good morning. Just to follow-up on the last question and comment, can you all, I guess, implement the well intervention growth strategy that you've outlined in the past without selling the E&P properties in a lump sum approach? In that regard, can you walk me through the free cash flow profile in the back half of the year and how you get balance sheet to that point?

Yes, we have modeled this out Michael and we have lot of forward-looking assumptions that go into this thinking that could change radically but we believe we can implement our well intervention growth strategy with or without a sale of E&P. First of all I mean we consider the fact that we have $837 million of liquidity, that’s a good starting point right there. Secondly, think about the cash flow generating from the E&P business today. So, we are generating a healthy amounts of free cash flow from the E&P business and we have always said to ourselves internally here that our development of our E&P properties has be self funding. So, we are never going to aggressively spend on E&P side to the extended taxes or balance sheet again. So, I think we got our balance sheet in a shape that gives us a lot of optionality and what we do in terms of growing the service business. And right now I believe the E&P business is a positive contributor to that. Now, again if ever got down to $40 oil it would be a different story but then lot of things will be different at $40 oil. So, again as Owen said earlier we worked very hard to get our balance sheet in shape to give us maximum optionality. And I think we are there. And we are not finished, we will grow even more liquidity by year-end.

Can you walk me through those numbers? I see the CapEx guidance, because some of that CapEx could potentially get pushed out a little bit further, so that CapEx number is probably a little bit conservative from a free cash flow standpoint, anyway.

Yes, I think simple math Michael to generate 550 million of EBITDA and spend 250 million in CapEx that leaves us with 300 million and then you got interest and tax to pay and whatever assumptions you want to use on that we will see that it will generate some nice free cash flow this year.

But I guess taxes should be minimum, right, cash taxes, and then the CapEx number is probably a little bit inflated because you do assume drilling two exploratory wells that may or may not happen, right?

That’s in a number, that isn’t definitely in a number of 250 million which not in that number is P&A’s we plan to do 40 to 50 million of P&A’s this year. As we try to stay on top of our abandonment obligation. But no matter which way you cut it we are going to generate a nice amount of free cash flow this year.

Okay, that's helpful. Shifting gears to the contracting business, are there specific regions out there that give you more optimism? Is it Brazil? Is it Australia? Is it just a global up tick in activity?

Well, contracting does first and foremost means well intervention. So, I mean you have to sort to break it down in this components, well intervention in the North Sea is robust, Norway obviously is a big opportunity market for us that we are pursuing pretty hard. Brazil is another area where we are in dialogue and we love to penetrate that market. I think there following we were paying in the last couple of year's in the Asia Pacific market where now we have a good presence in China. And I think recovery in that market is particularly potential for this year not tremendous close but at least a recovery. Having said that moving on to Robotics, I think our Robotics is perhaps our most global business, and we are pretty well positioned with good contacts pursuing everything west Africa has been really strong market in recent year's for us and I think you see us increased our participation there and then really exciting is the fact that more and more opportunities are presenting themselves outside of the oil and gas for Robotics group, with the wind farm and the new trencher that we have coming online that’s being built currently for burial of cables in the wind farms. It's really only the pipelay of part of the business that gives us a little bit of a challenge there, and we are not going to do something crazy and try and go out and take on contracts that we shouldn’t be taking on internationally. But we are going to be patient and there is upside there but like I said before I think you will see us working more hand-in-hand with other contractors and trying to achieve some better utilization for the pipelay asset.

Are you any more optimistic as it relates to the Caesar than you were three months ago?

Three months ago we saw no projects opportunities. Now we actually do have some good stability of projects on the horizon, the question is how do we do up then and go after them. So, things have improved I’d said marginally for the season.

Great. That's helpful, thanks.

The next question comes from the line of Joe Gibney with Capital One Southcoast. Please proceed.

Thanks, good morning. Just had a couple questions on the marine side, vessel specific on the Intrepid. I was just curious, you referenced the Eugene Island work. I was curious how long the mobilization would be, how long off charter would be before it kicks in this job in California.

I believe if I recall a schedule correctly, the Intrepid schedule go out to Eugene Island and June, Johnny?

(Inaudible).

For the oil line then it's supposed to from that point on, sale of the California.

I believe that because for the end of June, so we might have a weaker (inaudible).

But that’s how it goes. I think it's next job internally for ERT on the oil line for Eugene Island 302 and then of course you said sell for California.

Okay. That's helpful. In terms of the Robotics recovery, appreciate the color on the five chartered vessels back to work. Just trying to understand when that actually happened in the quarter. Is it a fair characterization to say that 2Q is a bit of a bridge quarter in that recovery and you've got a little bit more sustained momentum and higher utilization outlook for robotics in the back half of the year? Is that a fair characterization just looking at it sequentially into Q2?

Yes, I think the Robotics business itself and we don’t separately disclose numbers for it, but I think you will see that those numbers will improve notably in Q2. So, the improvement when to say is a full quarter but almost the fourth quarter. That’s helpful.

Sure, that's helpful. And just one last one. Owen, you've referenced even, consistent cash and extracting value on the model here, and obviously being able to adapting to market conditions with balance sheet emphasis. Against that backdrop, could you talk a little bit about your approach to additional hedging as you look at 2012 and you look at the E&P business?

We are pretty aggressively looking at hedging by corporate policy were limited to hedging 75% of our forecasting PDP. And we tend to try to push that, we as long the scrip or the hedge price that we can achieve is greater than our budgeted forecast then we look at it as capital preservation and we are inclined to later in the hedges and we are layering in continually right now we are layering in starting for 2012 we are layering in.

Very helpful. Thank you. Congratulations on the quarter.

Thanks.

The next question comes from the line of Martin Malloy with Johnson Rice. Please proceed.

Good morning. Could you talk about opportunities for another well intervention vessel? If you could do one in addition to the potential Cat B1 for Statoil or if the Statoil potential ward keeps getting pushed out, could you go forward on another new well intervention, Q4000 type vessel?

I think we have the capacity to do so and we have got the optionality of doing it with people of financing opportunities are there. So, I say definitely we have the optionality to consider it.

What would be some of the key factors in terms of deciding to move forward on something like that?

Primarily assurance of generating the returns on the capital invested sufficient to one day investment and it have to be a pretty strong guarantee.

Okay. And then just on the production facilities, the revenue and profit, gross profit contribution during the first quarter, is that a good run rate, approximate run rate to think about for the rest of the year?

I’m sorry, Marty if you can repeat that again, I’m sure I was clear on that?

Sure. On the production facilities, the revenue and gross profit contribution that we saw in the first quarter, is that a good run rate to think about for the rest of the year?

I’d say it's going to be higher the rest of the year, because of the retainer on the Helix contained system.

Okay. Thank you.

The next question comes from the line of Philip Dodge with Tuohy Brothers. Please proceed.

Good morning, everybody. Thanks. Wanted to ask you on the Phoenix production being better than expected so far, would that support an increase in estimated reserves for Phoenix?

This is Johnny Edwards. We will be looking at that at the mid year reserve report and I can’t say it's a absolute certain, but I’d say there is a good chance will be increasing reserves there mid year.

Good. Okay. And then, also on production, do you have an estimate of your production profile spending, what you're spending this year and risk adjusting the exploration any way you want?

I’m not sure I followed. Could you repeat that?

Yes, I guess it's a forecast of production with one of the metrics being the spending in 2011. I know some of that is exploration, so it's not easy, but maybe risk adjust that.

None of the exploration is factored into the production profile. And we look at the risk of our I call it our Shelf projects and we risk weight that just for example, at South Marsh 130, I believe we may have risk weighted that and 70, 80% range because it's fairly certain but there is mechanical risk. So, yes we do risk weighted and but no we don’t include non-proved reserves in the forecast.

And with that approach, would you expect to maintain production, raise it, or where would you see that headed?

For 2011 or for 2012?

Well, just looking forward, Tony. I guess we're pretty firm on 2011, but just medium term.

Well, I think the way you can look at this is it's the balance between capital reinvestment rate free cash flow. I personally I think the right way to look at it is to assume flat production annual production going forward. And we will match our capital with what is required to do that and allocate the remaining free cash flow for other purposes.

Okay, thanks, Owen.

The next question comes from the line of Stephen Gengaro with Jefferies. Please proceed.

Thanks. Good morning, gentlemen. A couple of things, the first being, on your guidance, I was trying to back into this a little bit, but given your production guidance, can you give us a sense for what you're looking at for contracting services, because it seems like when I put the pieces together I'm getting a higher number than your EBITDA gets?

Well, Stephen that’s a question I would just answer it by saying it anything we said three months ago, and that is there is opportunities to do better I think the star is aligned and things happened the right way, we can improve on that number. But you have to sort of risk the number which we have got. But that’s probably why you are coming up with maybe a higher number Stephen.

Okay guys. Now it just seems like, thinking about the first quarter, thinking about the moving pieces, the number seems to go up more than you suggested.

(inaudible).

You have risk some of this, I mean we risk some at a production. There are natural declines, things have to go right, if Little Burn doesn’t come on by mid July and there is no reason it shouldn’t because we are on location with the rig, we are actually performing the completion as we speak. But things go wrong in this business and we don’t want to disappoint.

Okay. No, that's fair. I just want to make sure I was thinking about it correctly. And then, when we think about the assets, the potential asset sale and where you stand on it now, can you just give us a sense for the way you're looking at it with a little more detail, because it seems like, given what it's done in this recent quarter and given the trajectory of production, it may be actually the right time to sell it as opposed to the wrong time?

Yes, Stephen I think in another way to look at this is based on what we are seeing in the sale process the buyer universe is suffering from Macondo hangover in terms of how they are looking at this valuation lines. In other words there is a huge disconnect between current commodity price level and what buyers are willing to pay. To the point where that diversion is so great we think we are doing our shareholders a favor by being more patient here and taking approach that Owen outlined which is PUD conversions and maximizing a cash flow from existing production. So, I don’t know when that Macondo hangover subsides but it’s certainly present today.

Having said that, I might just say, we used to have a saying in ERT that when we can realize full value of a property we will divest it, I mean that’s been a modus operandi for 20 year's. And I think the best we have sold the ERT was back when we had $140 oil. So, I think there is a lesson learned there that there is a sell-by date on certain things. I just don’t think that today is a day to do it and we have sometime and I think the market is going to improve to see a better opportunity. Now once you go down the road of selling PDP, and you started diminishing the critical mass of the proved reserves unless you are going to offset those reserves you have a critical mass issue which sort of puts you into you got to sell it by package. But right now I’m very happy with where we are and I think of the future of our production as well as it's marketable is still ahead.

Okay. No, that's very helpful. That helps clear it up. And then just one final one, just to help me a little bit with the model please say you can, on the E&P side, you mentioned your operating costs went down on a per unit basis sequentially. How should we think about that number going forward? Without getting too precise, you went from 3.17 to 2.87. That obviously helped the profitability. How should we think about that directionally over the next couple quarters given what you said about some of the guidance on the production levels over the next several quarters?

I would look at more at the absolute dollars more than the dollar per Mcfe because thee is not a lot of variation in those cost you can see I fourth quarter 2010 we were 43 versus 41. And those numbers will as production goes up and down those won’t go up and down as much, so I would look for the constant dollars more than I would the dollar per Mcf that’s a better gauge.

Good. That's helpful, and it's simpler, so thank you.

The next question comes from the line of Joe Mervar with Aluma Sales. Please proceed.

Thank you for taking my question. Production volumes out of Phoenix look they were flat throughout Q1, and for the first 22 days of April it looks like the volumes are down 15, 16%. Could you break down the decline between those items you've previously mentioned, mechanical issues or pipeline, and that which would be more related to a natural field decline? Thank you.

When Phoenix came on in the fourth quarter we were getting some good flush production which came back without a lot of water, and then early January we got the fourth well on which boosted our rates back up. But over the quarter we saw that same decline rate, we haven’t seen like a drop at the end of the quarter that was a constant decline that was happening over the quarter and that’s what we have declined to from January 1st to April 1st there is an average in there. That was decline going on during the whole first quarter so that wasn’t a drop in April.

Okay. And then that 10 to 12 days will come later in Q2, the 10 or 12 days, production will be off-line?

Well we didn’t specifically state Q2 because we don’t have us, we have a estimate from the pipeline company that are reconnecting some damage gas lines and end of Q2 and it could drag the Q3. So, we didn’t specify the specific date or the quarter that that would occur in, but the 12 days is mainly for reconnection of the gas sales line. And like Q2 or Q3.

Thanks.

And there are no further questions.

I’d like to just finish with one comment about of it's sort of connector with some of the question, spending cash is what got us in to the position we are in. Cash gets us back out, whether or not that derive from free cash flow of monetization event that really depended on the value proposition of what’s available at the time. I think we have a done a fairly good job of putting the health back into the balance sheet that could provide us the flexibility that we need in order to be able to seek the best value for the shareholders, and it's a fluid situation that’s what we are trying to give.

Okay. With that thanks everyone for joining us today, we very much appreciate your interest and look forward to having you participate on our second quarter call in a few months.

Ladies and gentlemen that concludes the conference call for today. We thank you for your participation and ask that you please disconnect your lines.