Helix Energy Solutions Group Inc (HLX) 2011 Q1 法說會逐字稿

Welcome to the Helix Energy Solutions Group the first quarter 2011 results with investor's 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 26, 2011.

I would like to turn the conference over to Stephen Powers. Please go ahead.

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 of Finance. 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 the 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.

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 two and in our annual report on Form 10-K for the year ended December 31, 2010. 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 reconciliations, along with this presentation, the earnings press release, our annual report, and a replay of this broadcast are available on our website.

Tony?

Good morning.

Please turn over to slide five summarizing first quarter results. We reported a sharp increase in earnings in EBITDA for Quarter 1, with earnings at $0.24 a share and EBITDA rising $149 million up from $95 million in the prior quarter. Quarter 1'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 1 versus the prior quarter reflecting full-quarter production on the Phoenix field as well as higher oil prices. When looking back to a year ago, which was Quarter 1, '11 represented a sharp increase in revenues, earning, and EBITDA, again with our oil and gas revenues leading the way for this comparative period.

Over to slide six and seven, we generated a nice amount of free cash flow in Quarter 1 as our cash balances increased by $50 million during the quarter to $441 million at March 31. 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 1 results as our contracting services business was impacted by the low levels of activity in the Gulf of Mexico as the slow pace of permitting has impacted all offshore activities in the Gulf from pipelines all the way to drilling. The one bright spot in our contracting service business continues to be well intervention, both in the Gulf as well as in the North Sea.

Our production rate in the first quarter averaged 160 million cubic feet a day, total production in the quarter of 14.4 billion cubic feet equivalent with 63% of that production being oil. Production from the Phoenix field averaged 12,100 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 factors that Johnny Edwards will get into later. Our realized oil and gas prices for first quarter, inclusive of hedges, were slightly better than $90 per barrel for oil and $5.77 for gas. Our realized gas prices benefited from natural gas liquids sales. I will now turn the call over to Owen for an in-depth discussion of our contracting services business.

Thanks, Tony. Good morning, everyone.

Let's move now to slide nine. Helix contracting service revenues were down both on a year-over-year and sequential basis, due primarily to a weak subsea construction and robotics market in the Gulf of Mexico. Utilization for our owned and chartered construction vessels dropped to 44% in the first quarter of 2011 from 84% in Q4 of 2010. 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 2010.

Moving over to slide 10, this slide shows the equity in earnings contribution of Independence Hub, Marco Polo, and the Clough Helix JV. The results are fairly consistent with Q4, so I'll leave the slide for everyone 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 has a healthy and visible backlog for the remainder of 2011. The Seawell encountered seven days of weather down time 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 maintain strong and visible backlogs for the remainder of 2011, so we would expect stronger results as the year goes on. The Normand Clough began work on a day rate construction job that will continue through the third quarter.

Moving to slide 12, as I mentioned a minute ago, weakness in the Gulf of Mexico construction markets posed a challenge for our domestic robotics business in recent months. That said, roughly two-thirds of our robotics business resides outside of the gulf, and we expect this segment's performance to improve throughout the year. We recently secured a one to two 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 has built up a healthy backlog of wind farm development and trenching work in the North Sea as well, so while the business is off to a slow start, all five of our chartered vessels are now utilized in utilization of our trenching and ROV assets is trending upward.

On slide 13, our subsea construction assets operated at 33% utilization for the quarter. The Caesar spent the quarter in the shipyard undergoing maintenance and repair -- upgrades, I mean -- while the Intrepid and the Express completed a few small projects in the Gulf of Mexico. The Express is now deployed on a 170,000-foot pipe lay job for the Deep Gulf's [Conger] field and we're working to build a campaign of projects into the fourth quarter. The Intrepid is currently dock side, but it will be deployed to lay 100,000 feet of seven-inch pipe on our own Eugene Island 302 field in May. She's then scheduled the mobilize to California mid-year where we're working to build a campaign around work that we've already secured and contracted. Oversupply of pipe lay assets in the Gulf of Mexico coupled with customers' permitting issues have presented significant challenges to this segment of our business, but we're working hard to secure projects for the assets.

Slide 14 illustrates the current design of our deep water containment system, the Helix Fast Response System, which we discussed at length on our year-end conference call. Since that call, four more producers have joined the consortium, bringing the current number of participants to 24, and six drilling permits have been approved, citing our system as the key component of the spill response plan to satisfy BOEMRE regulations. The system is current capable of capturing and processing up to 55,000 barrels per day in water depths to 8,000 feet. We continue to work with members of our consortium to expand the system with the objective of the HWCG -- I'm sorry, with the objective of increasing capacity and layering in redundancy. In the near to midterm, the HWCG plan to upgrade from our current 10,000 psi well cap to a 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's 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 slides, 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 the higher oil price realizations increased our revenues to $169 million compared to $137 million in the fourth quarter.

Turning to slide 17, our operating costs were slightly lower first quarter 2011 compared to fourth quarter 2010. Operating expenses increased by $10 million compared to Q1 2010 primarily reflecting the cost of our HP 1 utilized in the Phoenix field. As Tony mentioned earlier, ERT's production for the first quarter averaged 160 million a day equivalent. The increase in production over the fourth quarter is associated with a full quarter of Phoenix production. In early January, the fourth Phoenix well was brought on-line. 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 barrels of oil equivalent per day net, and we can say the Phoenix field has exceeded our expectations. Our current production in April is averaging 140 million cubic feet a day equivalent. Our production has been impacted by mechanical issues at our Noonan well and some intermittent third-party pipeline outages. We also additionally have been advised that there will be some future scheduled third-party pipeline outages that will affect our 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. The 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 4,500 barrels a day equivalent by midyear. The Little Burn well was drilled by BHP in 2005 prior to hurricane Rita destroying the TLP structure. The infrastructure is in place now to hook up the well quickly to the HP1.

We also have oil projects on the shelf we're 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 pending BOEMRE approval for a sales pipeline. Second, we're current mobilizing a platform rig to our South Marsh 130 field to work over eight to 10 wells. The well work program is targeting oil reservoirs behind pipe which have not been depleted. ERT expects to add another 1,000 barrels a day production in 2011 from this workover program.

To follow up on Tony's earlier comments ERT's oil production is primarily marketed with the Gulf Coast crudes. Currently, the Gulf Coast crudes 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 the current -- based on the current premium above WTI, we estimate to benefit by as much as $10 million to $15 million in the second quarter.

On the exploration front we have plans to participate in the drilling of two deep water exploration wells contingent upon permit approval by the BOEMRE and rig availability. The first prospect is our 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 pay which most of the other Phoenix wells produce from. Currently ERT has 70% interest in the Wang well and the permit has not been filed yet, but we expect to file the permit by mid-year. Both of these exploration wells discussed are in existing fields with existing infrastructure to handle the production. Both target oil and to both carry a reasonable chance of success.

Over to you, Lloyd.

Thanks, Johnny.

Turning to slide 18, slide 18 represents our commodity hedge position in both volumes and prices for the balance of 2011 and 2012. The 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 in hedges for the balance of this year, the breakdown is 63% oil, 37% gas, and this is in line with our average daily production rates 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 forecasted 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 to $441 million from $391 million. Based on our outlook for the balance of 2011, we expect further decreases in our net-debt position from the March 31 levels.

Tony.

Thanks, Lloyd.

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 from what we outlined a couple of months ago. First, we now forecast our 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're definitely benefiting from the gulf crude pricing premium, and on a natural gas side we're 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. 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 due to the power upgrades plan for the Caesar, and at the level of EBITDA with the forecasted a level of CapEx for the year, we should generate a nice amount of free cash flow in 2011, allowing us to increase cash balances from the already healthy $441 million level at March 31.

Turning to slides 23 and 24, we provide a little bit more color in our outlook on the contracting services side. We've booked a nice level of backlog for our well intervention vessels. The Q4000 is nearly fully booked for all of the year and both the Well Enhancer and the Seawell are carrying a solid book of business as well. While 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 our subsea construction business to be much better as permits start to get issued and these 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 the Caesar to remain in port for these upgrades through August. Canyon, 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, we now have all five of our construction support vessels to work.

Our oil and gas production forecast to 50 bcfe has 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 the permit to complete this well, and as Johnny said, the rig is on location and working to do that. Our CapEx at $250 million breaks down $85 million for contracting services and $160 million for oil and gas. The contracting services numbers contains a little spending above a maintenance other than some upgrades to the HP1 to enhance the 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 a 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, the Kathleen in the Bushwood field and Wang in the Phoenix field. 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 fields that Johnny mentioned earlier.

Back to you, Lloyd.

Slides 26 and 27 are non-cap reconciliation schedules presented here for your reference. I will not go into these schedules in detail on the call. At this time I will turn the call back over to Owen for his closing comments.

Thanks, Lloyd.

As Tony mentioned, Helix delivered a strong first quarter and we're pleased to upgrade our outlook for the remainder of the year. We've come a long way over the past few years to streamline our business model, 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 has grown more robust, which enables to us weather such uncertainties and challenges competitively. We're proud of what our team has accomplished, but there's still much to do. We'll continue to reduce debt and make improvements in debt structure. We'll continue to aggressively pursue growth opportunities, particularly in well ops where Helix is not only the early adopter, but the clear global leader.

As you're aware, we announced a little over a year ago that we have engaged advisers 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 operational disaster in the history of the Gulf when the Macondo well blew. The regulatory hangover from that event has resulted in a very challenging environment for the sale of entire oil and gas business. Meanwhile, favorable oil prices and strong production of Phoenix have had a very positive impact on our financial condition. As a result of these factors, we've determined that we can build more value for the business and shareholders by developing additional proved developed reserves and converting our high value PUDs. As such, our plan for the remainder of the year is to pursue 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'll continue to evaluate the potential sale of the 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 with 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 that 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 latter part of this year as Statoil has requested that the bidders undertake advanced engineering studies related to the riser stack. We've agreed to engage in the feed study and maintain our competitive position in this complex bidding process, and we'll keep you continually informed of our progress as we work through it. This will be the largest project that Helix has ever undertaken and would help reinforce our global leadership in 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 the space, and we intend to maintain this competitive position, so we'll continue to build the liquidity necessary to fund our future growth and reduce our debt levels. We've cut our net debt in half in a little over two years and are on track to reduce that position further in 2011. The take-away for this quarter is that Helix is executing its strategic transformation, building a strong balance sheet, fortifying its competitive position, and delivering quality earnings in a challenging environment. We look forward to the future with confidence and optimism.

With that I will turn it back over to the operator for Q and 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 4 or 5 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 foremost, Marshall, a 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 as well as mentioned, and it's a matter of being flexible and responding to the market in a manner that generates the highest level of cash and value. 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 Gulf of Mexico is definitely in a big slump because of the lack of drilling. If you were to start drilling at normal permitted levels today, you're probably looking at 2013 before normalization of the market. Now, that spelled a bad quarter for us here on the contracting side, which we anticipated, but I think one thing that -- a consequence of that is that I don't -- with the international markets remaining robust, I think the competition is more keen to deploy assets elsewhere, which is giving 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're 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're receiving from our consortium group first. We'd rather not get into the details of how much is being spent, but it's not a company maker. We're basically -- our assets are here, they're working. The HP 1 and the Q4000, which are the heart of the system, they're working, so he we're basically making them available to the consortium group in order to get the industry going again.

How we're doing that is a little different from the MWCC. The philosophy, or the approach is we're 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 a predominant number and gets the industry moving again, where as I believe the MWCC is taking a little broader scope at creating a system with more capacity -- probably slower in responding. So, I think between the 2 systems there's an application. We're just focusing on what can we do today and what can we get out there the fastest way possible.

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

Right. But this -- you're still -- 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.

Good morning, guys.

Good morning.

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

Is this where I'm supposed to say I'd rather be lucky than good? (Laughter)

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'll give you a broad -- conceptually, expect to see because of natural declines and the other issues Johnny mentioned, 2 will come down a bit. Q3 will recover as Little Burn comes onto production and some of the shelf development work we're doing also comes on, and then I think you will see quarter 4 take maybe a slight dip from Q3. So, generally speaking, our highest quarter could be quarter three, depending upon how Little Burn comes on, but Q2 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 the decrease from 161 to 140 is coming from production problems at Noonan, and I guess the silver lining in that it's gas.

(Laughter) 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 deep water 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 1 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 vessel will move globally. The others, I wouldn't say a permanent move. I think I would describe it as we're looking to work with other contractors more closely and the range -- maybe taking the assets out of the Gulf on a campaign basis.

Which the intrepid already is scheduled to work in California, the back half of the year already. It's subject to permitting, but we've already got the Intrepid moving out of the Gulf and the Express is working on projects -- 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 deep-water 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 that 60% of our proven reserves are PUDs, so the value equation -- given the debt that we ran up in order to drill them, the value equation for what we can get for a PUD makes it a questionable proposition, especially in a tough market.

PDP, proven, developed, producing, is -- from the comp deals that we've seen is it's still carrying 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 years and is a normal part of our business, but then reallocate the capital to PUD conversion to PDP, and I think what you wind up with is some pretty positive 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 back from marking 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, Inc. 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've modeled this out, Michael, and there are a 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, when you consider the fact that we have $837 million liquidity, that's a good starting point right there. Secondly, think about the cash flow generating from the E&P business today. So, we're generating a healthy amount of free cash flow from the E&P business, and we've always said, to ourselves internally here, that our development of our E&P properties has to be self-funding, so we're never going to aggressively spend on the E&P side to the extent it taxes our balance sheet again.

So, I think we've gotten our balance sheet in shape that gives us a lot of optionality in 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 we ever got down to $40 oil, it would be a different story, but then a lot of things would be different at $40 oil. So, again, as Owen said earlier, we've worked very hard to get our balance sheet in shape to give us maximum optionality, and I think we're there and we're not finished. We'll 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. If we generate $550 million of EBITDA and spend $250 million of CapEx, that leaves with us $300 million, then you've got interest and tax to pay and whatever assumptions you want to use on that, you will see that will generate some nice free cash flow.

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 2 exploratory wells that may or may not happen, right?

Absent a number, that isn't definitely a number of $250 million. What's not in that number is P&As. We plan to do $40 million to $50 million of P&As this year as we try to stay on top of our abandonment obligation, but no matter which way you cut it we're going 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 -- you have to break it down into the components. Well intervention, the North Sea is robust; Norway, obviously, is a big opportunity market for us that we're pursuing pretty hard. Brazil is another area where we are in dialogue and would love to penetrate that market. I think there's, following Lufeng and the last couple years in the Asia Pacific market, we're now -- we have a good presence in China, and I think recovery in that market is particularly a potential for this year, not tremendous growth, but at least a recovery.

Having said that, moving on to robotics, I think our robotics is perhaps our most global business, and we're pretty well positioned with good contacts pursuing everything. West Africa has been a really strong market in recent years for us, and I think would you'd see us increase our participation there, and then really exciting is the fact that more and more opportunities are presenting themselves outside of the oil and gas arena for our robotics group with the wind farm and the new trenches that we have coming on line that's being built currently for burial of cables in the wind farms.

It's really only the pipeline of part of the business that gives us a little bit of a challenge there, and we're 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're going to be patient. There's up side there, but, like I said before, I think you will see us working more hand in hand with other contractors in trying to achieve some better utilization for the pipe-lay assets.

Are you any more optimistic as it relates to the Caesar than you were 3 months ago?

I -- well, 3 months ago we saw no project opportunities. Now, we actually do have some visibility of projects on the horizon. The question is how do we gear up and go after them, so things have improved, I'd say, marginally for the Caesar.

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 the schedule correctly, the Intrepid is scheduled to go out to Eugene Island in June, Johnny?

For the oil line.

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

I believe that scheduled for the end of June, so we might after week of down time between the 2.

But that's how it goes. I think its next job is for the -- internally for ERT on the oil line for Eugene Island 302, and then before she sets sail for California.

Okay. That's helpful.

In terms of the robotics recovery, appreciate the color on the 5 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?

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 I wouldn't say was a full quarter, but almost a full quarter, Joe, if that is helpful.

Sure, that's helpful.

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're pretty aggressively looking at hedging. By corporate policy, we're limited to hedging 75% of our forecasted PDP, and we tend to try to push that. As long as the strip or the hedge price that we can achieve is greater than our budgeted forecast, then we look at it as capital preservation and we're inclined to layer in the hedges, and we are layering in continually. Right now we're layering in -- starting for 2012 we're layering in.

Very helpful. Thank you. Congratulations on the quarter.

Thanks.

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

Good morning.

Could you talk about opportunities for another well intervention vessel? If could you do one in addition to the potential Cat B1 for Statoil or if the Statoil potential award 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've got the optionality of doing it with people, the financing options are there, so I would 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 warrant the investment, and it would 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 could repeat that again, I'm not 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 would say it eats going to be higher the rest of the year because of the retainer on the Helix well containment system.

Okay. Thank you.

The next question comes from the line of Phillip Dodge with Tuohy Brothers.

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?

Excuse me, this is Johnny Edwards.

We'll be looking at that at the mid-year reserve report, and there's a -- I can't say for absolute certain, but I'd say there's a good chance we'll be increasing reserves there at 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 follow it. 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'll 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 in the 70%, 80% range because it's fairly certain, but there is mechanical risk. So yes, we do risk weight it, but, no, we don't include nonproved 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.

Phil, I think the way you can look at this is it's a balance between capital reinvestment rate, free cash flow. Personally, I think the rate way to look at it is to assume flat production, annual production going forward, a then we'll 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 from Jefferies & Company. 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'll just answer it by saying the same thing we said 2 months ago, and that is, is there opportunities to do better, I think if the stars 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 done. But, that's probably why you're coming up with maybe a higher number, Stephen.

Okay. 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.

Well, again --

Going to try and create a -- or reestablish an old habit of under-promising and over-delivering.

You have to risk some of this. We've risked some of the production. There are natural declines. Things to have go right. If Little Burn doesn't come on by mid-July, and there's no reason it shouldn't, because we're on location with the rig, we're 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?

I think another way to look at this is, based on what we've seen in the sale process, the buyer universe is suffering from Macondo hangover in terms of how they are looking at this valuation-wise. In other words, there's a huge disconnect between current commodity price level and what buyers are willing to pay to the point where that divergence so great, we think we're doing our shareholders a favor by being more patient and taking the approach that Owen outlined, which is PUD conversions and maximizing the 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. That's been a modus operandi for 20 years. I think that the best time to have sold ERT is back when we had $140 oil, so I think there's a lesson learned there that there is a sell-by date on certain things.

I just don't think that today is the day to do it, and we have some time, and I think the market is going to improve to see a better opportunity. Now, once we -- once you go down the road of selling PDP, and you start diminishing the critical mass of the proved reserves, unless you're going to offset those reserves, you have a critical mass issue, which puts you into a -- you've got to sell it by package, but right now, I'm very happy with where we are, and I think the future for our production, as well as its marketability, 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 (inaudible), 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 million to $8.87 million. 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 there's in the a lot of variation in those costs. You can see in fourth quarter 2010 we're 43 versus 41. And that -- those numbers will -- as production goes up and down, those don'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 to be -- 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 rate back up, but over the quarter we saw that same decline rate. We haven't seen a drop at the end of the quarter. That was a constant decline that was happening over the quarter, and that's what we've declined to. From January 1 until April 1, we -- there's an average in there. There 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 Q 2, because we don't have -- we have an estimate from the pipeline company of reconnecting some damaged gas lines in end of Q2, and it could drag to 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. It could be late Q2, early Q3.

Thanks.

And there are no further questions.

I would like to just finish with one comment that connected with some of the questions. Spending cash is what got us into the position we were in. Cash gets us back out. Whether or not that's derived from free cash flow or monetization events, that really depends on the value proposition of what's available at the time. I think we've done a fairly good job of putting the health back into the balance sheet that provides us the flexibility that we need in order to be able to seek the best value for the shareholders. It's a fluid situation. That's what we're trying to do there.

Okay.

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

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