Helix Energy Solutions Group Inc (HLX) 2010 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the review of the second-quarter 2010 results with investors.

During the presentation, all participants will be in a listen-only mode. Afterwards we will conduct a question-and-answer session. (Operator Instructions)

As a reminder, this conference is being recorded Thursday, July 29, 2010. It is now my pleasure to turn the conference over to Mr. Cameron Wallace, Director of Investor Relations. Please go ahead, sir.

Good morning, everyone, and thanks for joining us today. Joining me today are Owen Kratz, our CEO; Tony Tripodo, our CFO; Johnny Edwards, Executive Vice President of Oil and Gas; Alisa Johnson, General Counsel; Lloyd Hajdik, our SVP of Finance.

Hopefully you've had an opportunity to review our (inaudible) slide presentation released last night. If you do not have a copy of these materials, both can be accessed through the investor relations tab on our website at HelixESG.com. The press release can be accessed under recent news and the slide presentation can be accessed by clicking on today's webcast icon. Before I 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, 2009. Also during this call, certain non-GAAP financial disclosures may be made.

In accordance with SEC rules (inaudible) presentation material provide a reconciliation to certain non-GAAP measures to comparable GAAP financial measures. The reconciliation along with this presentation to earnings press release, our annual report and a replay of this broadcast are available on our website. Tony will now make some opening remarks.

Okay, good morning, everyone. Moving on to slide four which summarizes second-quarter results, and I will focus our comments on sequential quarterly results comparing quarter two of 2010 to quarter one of 2010.

Well quarter two showed a nice increase in revenues from $202 million in the first quarter to $299 million in the second quarter primarily owing to a substantial increase in well intervention activity in the UK, coupled with a lot less intercompany utilization of our vessels. Gross operating margins increased nicely as well from 18% in the first quarter to 22% in the second quarter, again led by strong margins for well intervention at production facilities.

Our earnings of negative $0.82 per share were impacted by two large items which I will discuss in more detail later. When stripping out the impairment charges of $160 million, we would have booked positive earnings of $0.18 per share. And if you back out the incremental DD&A we needed to book on the Bushwood reserve revision, quarter two earnings would've been even higher.

Over to slide five with respect to EPS, we recorded two two large items that impacted our second quarter results. First we performed a midyear review of our oil and gas reserves and due to our updated review of field economics, we revised reserves downward, leading to an impairment charge of $160 million on 15 of our Gulf of Mexico shelf properties.

The impairment amount is at the low end of the range we cited with our early July press release on this subject. Second due mainly to production performance issues on our Bushwood Deepwater field, otherwise known as [Danny oil and Newnan gas], we reduced the proved reserves numbers in the field which had the intended result of increasing DD&A.

We recorded additional DD&A of approximately $19 million associated with the reserve reduction over and above what it would have been at the previous DD&A rates. However, this impacts us on an ongoing basis as the DD&A rates for the Bushwood field are now reset at the higher rate. I will turn next (technical difficulty)

I'll start on slide six. On the service side of the business as we had previously forecasted, quarter two results are indicative of improving market conditions as reflected by high vessel utilization, particularly for well intervention in the UK.

Moreover as we were coming to the end of our major oil and gas infrastructure buildout for Phoenix and Danny, internal utilization decreased quite a bit. And conversely, we were able to book more third-party revenues associated with all of our Gulf of Mexico fleet.

We also placed both the Caesar and the Helix Producer I in service during the quarter. The Caesar contributed but only on a marginal basis.

However as we previously press released, the Helix Producer I was contracted by BP for the Macondo spill containment activities and it was diverted from the restart of production of the Phoenix field. Both the Phoenix field and the HP I have the necessary permits to start production, so once the HP I comes off of Macondo, we should be able to put Phoenix into production shortly thereafter.

Oil and gas production increased slightly in the quarter to 11.9 Bcfe from 11.3 CCFE in Q1. Again this would've been higher had we been able to start production on the Phoenix field but it was more important from our perspective to assist in the spill containment efforts of BP. Even without Phoenix, increased production coupled with slightly higher commodity prices led to a $13 million increase in oil and gas revenues in the quarter.

As we discussed in our press release of July 1, we performed a midyear review of our oil and gas reserves. The midyear review evaluation led to a reduction in proved reserves to 400 Bcfe. The majority of the reserve reduction relates to the Bushwood field, both Noonan Gas and Danny oil and primarily the result of production performance issues encountered since the beginning of the year.

I'm pleased to report that our balance sheet remains strong with liquidity levels of $647 million at June 30 which is up from $598 million at March 31. Now moving over to slide eight, the good news is that activity levels have rebounded and we should see a continuation of the trend in the third quarter.

The well intervention business looks particularly strong with backlog building into 2011. We are likely to underspend our prior capital spending forecast for 2000 from the previously announced $220 million to a current forecast of about $190 million.

We pared down some of our oil and gas development spending for the rest of the year and year to date, we have incurred $112 million of capital. Therefore the back of the year would be at somewhat a lower rate. Before getting into the contracting services business in more detail, I will turn the call back over to Tony now who will update our 2010 outlook and guidance.

If we turn to slide nine, we've updated our guidance from the last call. First of all, based on the pushback of Phoenix production due to the HP I being diverted to spill containment for BP, we have lowered our oil and gas production range to 40 to 45 Bcfe for the full year.

The big variable on the range is represented by whether significant disruption occurs with hurricanes in the Gulf of Mexico and a little bit with the uncertainty regarding the startup date based on when the HP I frees up. Our EBITDA guidance is now tightened up to $400 million to $450 million compared to our previous guidance of $400 million to $500 million.

As Owen mentioned, we're now projecting 2010 CapEx at $190 million. We have cut out some CapEx for development of a gas field that we now deem to be uneconomic that led to some of our second-quarter impairment charge.

With our hedges in place, we are forecasting realization on commodity prices to be approximately $75 for oil and a little bit under $6 for natural gas. Now turning back to contracting services, I will turn it back over to Owen.

Thanks, Tony. I will pick up on slide 11. Our contracting services produced a gross profit of $63 million for the quarter which represents a 0.75% increase compared with the previous quarter. Margins improved to 28%. I should note this quarterly gross profit is one of our highest ever.

Equity in earnings from our share of Marco Polo and Independence Hub stayed constant but were impacted by our share of losses associated with the startup of our CloughHelix joint venture in Southeast Asia as noted on slide 11. We expect the JV to generate a profit in the third quarter of 2010.

Moving to slide 12, Q2 utilization, the utilization of the subsea construction vessel decreased because of the introduction of the Caesar in late May and the fact that the vessel didn't mobilize until late June. The utilization of the Canyon chartered ROV vessels was adversely impacted by the SeacorCanyon being inactive in Singapore and the transit of the Normand Fortress from India to the Gulf of Mexico.

We've now released the SeacorCanyon after a couple of years of charter. Our [three owned] well intervention vessels enjoyed 98% utilization in the Gulf of Mexico and the North Sea.

Turning over to slide 14, we're proud of our involvement in the Macondo spill containment. The MODU Q4000, FPU, Helix Producer I and the MSB Express worked for BP on this project and have proven to be ideally suited for this type of oil spill response. Our employees performed extremely well under difficult circumstances. Slide 14 shows the Q4000 and Helix Producer I at work.

The versatility of the Q4000 was put to use on the Top Kill, the containment using the Evergreen burners and soon will be used for the Static Kill. The Helix Producer I commenced production operations within one month from our departure from Phoenix and a new 270 ton buoy was constructed in record time for the pull in of their flexible riser coming off the freestanding riser tower in MC252.

The topside facilities of the Helix Producer I will have to be returned to their Phoenix configuration before the vessel will connect to the buoy at Phoenix at which time the BP charter will end. On slide 15, we cover the activities on our subsea construction and robotics business.

The Caesar commenced the installation of a 46-mile, 20-inch gas pipeline in the central Gulf of Mexico, which is expected to be completed in August, at which time the vessel is scheduled to transmit to Trinidad for another pipelay job. The Canyon chartered ROV Trencher support vessels delivered a decent contribution in the quarter and I'm pleased to report that our trenching performance exceeded our own expectations.

Turning to slide 16, I've covered the Q4000 already. We expect that this vessel will remain active on the Macondo project for the majority of the third quarter. Her backlog looks strong into the first half of 2011 and both the Seawell and the Well Enhancer operated successfully in the North Sea and we feel confident about the remainder of 2010.

The Well Enhancer will be taken out of service in August here to complete the coil tubing upgrade before we redeploy on our first deployment of coil tubing from the vessel for Hess in the North Sea in September. The the Normand Clough is currently offshore China in the South China Sea on a [well ops] Asia-Pacific contract for CNOOC for the PA of five subsea wells in the Lufeng field. This is the first riser-less deepwater well P&A job offshore China. Now for our oil and gas business, I will turn it over to Johnny Edwards.

Good morning. Please turn over to slide 17. The second-quarter financials were negatively impacted by a reduction in our reserves on our 2010 midyear reserve report. The midyear reserve report contains 400 Bcfe which reflects a reduction of approximately 143 Bcfe from our December 31, 2009 report.

The majority of the reserve reductions were in the Bushwood field with the remaining reductions spread over some shelf properties. The reductions in the Bushwood field reserves were primarily due to less than expected production performance of the wells.

First the Garden Banks 506 #3, our Noonan well, began producing -- one of our Noonan wells, began producing water in May and remains shut in. The water production along with the reservoir pressure information reduces the size of the remaining reserves for the Noonan reservoir.

Also with shutting in the Garden Banks 506 #3, a larger part of the remaining Noonan reserves are being drained by the offset operator. Our Garden Banks 506 #1, our other Noonan well, continues to produce net 29 million a day [to ERT].

Our second well performance issued in Garden Banks is 502, the Danny oil reservoir. The reservoir pressure has continued to decline faster than we expected.

The Danny well started producing in February this year at 3600 barrels net rate DRT. The well continues to produce at approximately the same rate today but the declining reservoir pressure indicates the remaining reserves are less than predicted by the volumetric analysis from our December 31, 2009 reserve report.

With the less than expected performance from our two producing reservoirs, the remaining reserves in the Bushwood field were reduced. The reserve reductions in the Bushwood field added about 19 million to our oil and gas DD&A in the second quarter incremental. As Tony stated earlier, this will have an impact on future quarters' DD&A.

Also there were downward reserve revisions on the shelf at the midyear reserve report. Many of these reserve revisions were the result of management's decision not to pursue drillings in small pools of remaining reserves requiring significant capital expenditures. The [$160 billion] of oil and gas impairments are primarily associated with the reduction in carrying values of the Gulf of Mexico properties due to the reserve revision in our midyear reserves.

On a positive note, we are looking forward to the Phoenix field startup later this year once BP releases the HP I. The HP I received the required regulatory approvals in June prior to starting work for BP and we do not anticipate the current events in the Gulf related to the Maconda incident will prevent the Phoenix field from restarting production.

Once the HP I is back in the Phoenix field, we will begin the process of starting up four wells. These four wells have been shut in since the Chevron operating typhoon platform was destroyed in Hurricane Rita in 2005. An additional well was drilled in case by BHP prior to Hurricane Rita and this well will be completed by Helix at a later date.

ERT owns 70% working interest in the Phoenix field and depending on our operational performance, the Phoenix field should add between 8,000 and 10,000 barrels of oil a day equivalent to our net production. Turning over to slide 19, slide 19 summarizes our 2010 commodity hedge positions for the remainder of the year.

Our average price expectations for 2010 with our hedges that are currently in place is approximately $75 for oil and just over $5.80 for gas. We currently have hedged approximately 22.1 B's of production for the remainder of 2010 which covers a significant portion of our forecasted production for the remainder of the year.

We've also begun to layer in some hedges for 2011 as this slide reflects. We have hedged a total of 7.2 Bcfe of both oil and gas for 2011.

Although our objective is to exit the oil and gas business given the current environment in the Gulf of Mexico, we feel the process may take longer, thus we felt it prudent to layer in some hedges for 2011. I'll turn it back over to Cameron.

Slide 20 reflects the synopsis of our debt and liquidity position. We project 2010 to be another year in which we expect to bring down our debt levels (inaudible) to continue to maintain relatively high liquidity levels which stand right now at $647 million. Slides 22 and 23 are the non-GAAP reconciliation schedules within a four-year reference. I won't go into these figures. At this time, I'll turn this call back to Owen for his closing comments.

Well we're still in what I would characterize as a weak global market cycle. It's improving but it's burdened by oversupply.

Helix performance in the cycle is improving and I think it should continue to improve. There's two significant areas of uncertainty I think that may be of interest to investors in Helix.

First is, what does the future Gulf of Mexico production look like. And second, what is the future of Gulf of Mexico services look like and how is Helix impacted in the post-Macondo world here.

On the service size, it should be pointed out that over 50% of our service revenues are derived from outside of the US. In well ops including the Q4000, we don't expect a negative impact and backlog is strong as well as our performance.

On the ROV Canyon side, we have approximately 12 ROVs in the Gulf of Mexico. One area that I could see potentially impacting us is as the Gulf slows and vessels relocate out of the Gulf of Mexico, it could impact margins on a global basis but it would be small.

In general on the robotic side, we view ourselves as a quality provider versus the volume provider. So if there is any impact, I think it should be relatively minor to our business.

In the facilities business which includes our interest in Marco Polo and the Independence Hub, an extended moratorium could potentially impact future production developments and therefore flow-through tariffs. But there's really no expectation of any kind of near-term negative impact to that business.

On the pipelay side, this is where our greatest exposure is to the Gulf of Mexico. We made the strategic decision to relocate our three pipelay vessels back and concentrate on the Gulf of Mexico.

If the moratorium continues beyond the six months, one way of looking at it is that other assets will probably leave which means supply will drop and that would be okay for us. We will be looking to work the Intrepid in alternative roles to pipelay including construction as a multi-service vessel, light well intervention and P&A.

The Caesar will probably take a bit more of an aggressive look at international work, as she has always been anticipated to be a global asset. And then that leaves our remaining asset, the Express, as our primarily lay asset which we should be able to keep busy in the Gulf of Mexico.

We were expecting a modest recovery through the second half of 2010 and throughout 2011. The moratorium does place some uncertainty on the 2011 work in the Gulf of Mexico as 2000 drilling is what creates 2011 work. Helix is in my opinion better placed to cope with the slower Gulf of Mexico than most might assume.

On the oil and gas production side, we had no wells planned for the second half of 2010, so the moratorium will have no effect on us. Our intent to sell oil and gas has certainly been impacted as capital markets and buyers are a bit uncertain at the current time.

Nonetheless there is interest in our oil and gas assets. The process has been delayed and the pace may be a little slower, but we are following through with the discussions with parties that continue to show strong interest. The Q2 impairments are indicative of the fact that reservoirs can disappoint after being placed in production relative to expectations.

But there is an awful lot of value in our oil and gas assets and prospects. However, we are a first and foremost a service focused company.

The amount of capital investment and risk inherent with E&P does not fit with our service ambitions and the assets are probably better in the hands of producers that are engaged in E&P. Our intent is to redeploy the value that we do have in our production assets into further debt reduction and service growth. The market conditions will be the determining factor on when we can get this divestiture done. And with that, I'll just open things up for Q&A.

(Operator Instructions) Jim Rollyson, Raymond James.

Owen, any thoughts on maybe how you think of Helix's position in the long term as far as maybe long term benefiting from this kind of push towards an emergency spill response given the role you guys have played in dealing with the Macondo situation?

Jim, I really think the industry pays a lot of attention to prevention and post Macondo, I think that is going to be first and foremost on everyone's minds. So I don't see this as an event that you would create a business around.

I do think that it's been demonstrated that our assets are very conducive to responding here, especially if the hardware was pre existing. I think you're looking at containment within weeks. I don't see there being a financial benefit to Helix, but I do see a benefit from the Helix assets to the general industry in its efforts to get the moratorium lifted.

Okay, Q4000, if I recall correctly, was fairly well booked, maybe even into -- through the end of this year and into next year before the BP situation, obviously working for BP now for a while. Can you maybe share the status of some of the other work you were supposed to be working on right now? Are people -- you are going to get some cancellations there or do you think that some of that continues to get extended?

Jim, let me take that. The Q4000 was fully booked before BP Macondo throughout 2010 and somewhat into 2011. And for the most part, its involvement in the Macondo situation is only extending that backlog and increasing the backlog.

There has been a job, a small job that was canceled. But aside from that, mainly the work that she had in backlog has just been pushed to the right. So, it's been fairly positive for us in terms of actually building backlog.

Okay, and then last question for me, Tony, maybe the drop in EBITDA guidance from the 400 to 500 down to a tighter range of 400 to 450. Do you think the majority of that delta relates to the production decline?

I'd say somewhat, somewhat related to lower production from Noonan and really, Jim, I have to admit, we're just being conservative here.

Okay, thanks, guys.

Roger Read, Natixis Securities.

I guess maybe, Owen, everybody is -- nobody knows how the moratorium is going to end or exactly when it will end. But if you just sort of talk with your customers, their views, hey, if the moratorium ends on November 30, we would expect to need X in 2011 or are people still just maybe a little too discombobulated from all this to really think that far ahead yet?

I'm not sure I understood the question, Roger.

Well, just your customers, are they thinking about 2011? Are you talking with them about pipelay vessel needs in 2011?

Or was your commentary on the vessels you expect to see within your own fleet repositioning potentially? Is that just -- that is how you are interpreting the market today? I'm trying to understand what are the moving parts that you see.

I am taking a worst case view forward and assuming that with six months of no drilling here that that is going to have some impact on the volume of development work that occurs in 2011. It may or may not be that severe.

We haven't had a lot of feedback from our clients. A lot of the development work that was going to occur during this period, actually the permitting process slowed down even for pipelines. So a certain amount of that has moved to the right.

So I'm not confident that we're going to see much of a slowdown really. But I'm just anticipating the worst and we are looking for alternative uses of the assets.

Okay, perhaps it's really on the pipelay side, not on the well intervention side. I think on the well intervention side, I think it's fair to say that will probably benefit Roger long term from what's happened here.

Like I said in my color commentary there, the only area about Helix that is at all exposed to the Macondo incident in my mind are our three pipelay assets in the Gulf. And that is -- we don't have anything definitive to say that they're going to be negatively impacted. We're just being prudent and cautious.

Okay and then help me to understand a little bit the expectation that this could be beneficial -- well, I don't know, beneficial -- but the fact that the well intervention vessels could see a better overall setup from this. Because I've always historically thought of the sort of rate that a well intervention vessel could get was somewhat determined by the day rates on a deepwater rig.

That is your well intervention competitor. If we got an oversupply even if temporary of deepwater rigs, you know they can't operate in a drilling mode and clearly we've seen some deterioration in day rates of those units. How does that -- help me understand how it works out as beneficial for the well intervention fleet.

So far, the Q4000 for the work that it does is a lot more efficient than a drill rig. We have seen that just on our own #3 well on Noonan. We were looking around for rigs just recently to go out and do the the water shutoff work because the Q4000 is booked up and it just is not commercial to do so without the Q4000 because the efficiency gains.

The clients have expressed to us so far that they are just holding their programs and they're going to wait for us which is a very positive sign. I think the MMS -- I just got word today that it looks like the ruling is going to come down that lease extensions are going to be extended for a duration equal to this moratorium which would be a positive for everybody.

Okay, but I guess -- so you haven't necessarily seen more demand for the vessel. It's just you had an opportunity to prove the vessel out, the value of the Q4000 here on this Macondo well?

I think the clients understand the value of the Q4000. Like we said, we were booked before pretty -- with a great backlog.

We have just seen no deterioration of that and therefore this period of Macondo has just been sort of adding backlog. So we are looking really strong going forward.

I might add, if the moratorium -- depends on what happens with the rigs. If the rigs start leaving the Gulf of Mexico, then when the moratorium is lifted, there is going to be a -- rather than an oversupply, there's going to be an undersupply of rigs which would benefit us greatly.

Another thing, Roger, assuming the government tightens up regulatory requirements on P&As and decommissioning, that's where we see the potential upside here in well intervention as well.

Okay and then a final question. The HP I expectation, you get that back on the Phoenix field starting up I guess September, do you have -- that's kind of the high hurricane season obviously, September in terms of disrupting operations. Is that factored into it or is this timeline you are considering right now basically consistent with release from Macondo (inaudible) shipyard and then that's when it would be available? Can you get it on sooner I guess would be the short question there.

You know our outlook is strictly based on our guess on when the vessel will be released from the Macondo efforts. So, you know, we are assuming light Q3, but it could be sooner or it could be later. We just don't know. We're out there to help the situation. As long as BP needs the vessel, we're going to keep her out there.

Well that clears it all up for me. Thanks.

Joe Gibney.

Tony, you tightened up on CapEx a little bit here, $270 million in cash, improved liquidity. Just could you help us a little bit with net debt expectations in the second half and how we should be thinking about interest expense into the next year?

I think that we expect net debt to go down marginally in the second half of the year. I don't think you're going to see a number like $100 million lower, but you will see some marginal improvement based on our own internal forecast.

I think in terms of interest expense, assuming no sale of E&P assets, I think you're going to see interest expense somewhat consistent with quarter two from this point on. (multiple speakers) yes, because of less capitalized interest. So I think you are going to see pretty consistent numbers from this point out.

Okay, that's helpful. Shifting back to the marine side, just a couple vessel-specific questions and then a higher-level view.

But for the Caesar shifting to Trinidad, can you give a little more color on the duration of the work that it's going to have down there and if there's other follow-on opportunities that could keep it there? And then just curious on the broader marine, understand sort of the pressure on the pipelay side and what could transpire coming off the moratorium.

Owen, you've previously talked about your revenue potential on your existing marine asset base being about $1 billion, obviously giving consideration to a sluggish Gulf and maybe the Intrepid doing P&A light well intervention work. But is that still a reasonable opportunity set given what you see in your prospect queue, obviously taking into consideration the potential for a little sluggishness there on the pipelay side?

Okay, a lot of issues there. But yes, I don't think that our outlook has materially changed from anything that we said before. I am pretty confident about the -- I guess the Intrepid being our third pipelay vessel is the one that I would have the most concern with. But she is on her way down to Trinidad.

I believe she's down there for at least two months and there is additional work that clients in Trinidad are talking to us about that could extend the stay. So that's a very positive move.

The Caesar is out on its first pipelay job right now and like with all vessels, the work is going pretty slow as we train the crews and get the equipment functioning properly and everything. So I don't expect a great contribution from her.

But then she -- right after this, she also heads to Trinidad. So Trinidad is becoming a very good market for us and an alternative to the US Gulf of Mexico.

We're also bidding work in Mexico and Brazil for primarily the Caesar. And that would open up the Intrepid to return sometime in the fourth quarter to pursue both pipelay -- but we really have been really successful with her this year, working her as a multi-service vessel in the construction mode.

I see that kind of a mix continuing. I think actually the construction mode is given the performance of pipelay and the margins available in the current market, I actually see the alternative uses of the Intrepid probably being a little stronger margin than if we left her solely in the pipelay mode for next year.

And then to follow up, the Express has pretty decent backlog here for the rest of the year in the Gulf of Mexico. And the reason why we are -- it's difficult to predict how the moratorium affects our subsea construction business is because again, our assets are floating assets and they can float anywhere to any location in the world and perform work anywhere in the world, as the Intrepid and the Caesar are going to do in quarter three.

And historically, two-thirds of our ROV construction chartered vessels operate outside the Gulf of Mexico. So I mean, we are certainly a bit concerned about the moratorium and how it might impact activity in the Gulf of Mexico. But as Owen said, we're better suited to cope than a lot of people might otherwise think.

I'd like to point out also, were not -- currently with the Q4000, we are in upper end of the heavy intervention market here. But we are not in the light well intervention market.

We are in the North Sea. We're the dominant player over there but we have just not had an asset here.

By using the Intrepid with what we've seen this year in her work on -- P&A work by adding light well intervention on board her and the government's refocus on getting more stringent on P&A, I really do see a solid role for her in that market.

That's helpful, I appreciate it. One last one, I'll turn it back. Just curious, you mentioned heavy well intervention, North Sea. Just any update on the Statoil feed for the well intervention asset there?

We're at the point we've completed our shipyard packages and we are working with the shipyards to develop the concept further. The initial technical submission is September 15 with the commercial submission due October 15 and an award by the end of the year. So we are pressing hard on all fronts there and we have a pretty large team working on it.

Thanks, guys, I'll turn it back.

Stephen Gengaro, Jefferies & Co.

I guess the first thing I would ask you is if you look at the quarter and you look at the gross margins were real solid on the contracting services side, is there anything abnormal? Obviously there's a workload which is abnormal but from a profitability perspective, is there anything sort of abnormal in there that would make this sort of an unsustainably high level?

Steve, you referring to contracting services?

Yes.

Well I think first and foremost, contracting services, the high margins you saw are influenced a great deal by high utilization of well intervention. That was a primary factor. Anytime you have 98% utilization of well intervention, you are going to drive high margins.

On the other hand, our margins in subsea construction were relatively on the low side. It's mixed up in there. They're relatively on the low side because the Cesar perform a low margin [floatel] job during the third quarter and as Owen mentioned earlier, it's just kind of kicked off its first pipelay job.

I would say, you know certainly the HP I was a helpful factor to our margins because the work she is doing for BP. But it's sort of -- it was cheating margins out of oil and gas because it would have been contributing on the oil and gas side by having Phoenix production.

So, yes, I would say net net, the margins for contracting services were positively influenced because of utilization and the HP I contribution. At the same time like I said, it stole some margins out of oil and gas.

So as we think about the third quarter -- and I kind of come up with -- and you can correct me if I'm wrong. But as far as the tax impact on the D&A hits on Bushwood, that comes out to like another $0.12. So we kind of get operating earnings of like $0.30 in the quarter.

Am I thinking about this properly to think that third quarter could look a lot like the second quarter and the fourth quarter is where some of these fundamental issues would come into play more from an earnings perspective?

I think the third quarter right now will -- absent a hurricane will look like the second quarter. In terms of topline, I'm a little concerned that we will be able to repeat margins as high as we did in the second quarter.

But that's only again because we had very, very high utilization in the second quarter. But still I think margins will still be good. With the topline because of the Caesar now coming in for a full quarter, we might even see higher revenues in the third quarter.

Fourth quarter, you've got some seasonal factors particularly in an RFC that might drive the revenues coming down on contracting services and then you'll have the HP I likely having come off work for BP in the third quarter as well. But then you should see oil and gas come up in the fourth quarter.

I might add, we're also planning to take the Caesar out of service late in the fourth quarter to install the thrusters that we've been waiting on. They were long lead items that did not arrive in time before the vessel went into service. But they were in the design to be added and we're going to be drydocking her probably around the November timeframe.

Okay, that's helpful. Then I guess just the other thing, other important drydocks I think you mentioned, you mentioned one from August to September. I think it was one of the well intervention assets in the North Sea, the Enhancer (multiple speakers) speakers)

That's for a short period of time. That's probably less than two weeks, right, Owen?

Probably a little over two weeks but that is to install the coil tubing equipment that is required to go onto the Hess contract.

Just one final one and that is the transit times to Trinidad, is that anything we should worry about from a modeling perspective? Are you getting paid for that? Is that a long time out of service from a utilization perspective?

No, the payment for that is factored into the rates that we are charging for the work in Trinidad. So it should be a revenue recognition event.

We're getting paid, the bottom line, we're getting paid for the transit.

Okay, great, thank you.

Philip Dodge.

Two questions. First as I understand it on the HP I at Macondo, you are getting compensated to be financially equivalent to if it were producing at Phoenix. Can you just elaborate a little bit on how that calculation is made?

Phil, we have decided that we're not going to talk about the rates with BP. They've asked us to keep that confidential but your --

Was my assumption correct?

But your assumption is correct. The rates were set to keep us financially whole.

But I think it's fair to say that in the future if this were to happen again and somebody wanted the HP I and she were required to disrupt her service on the field she's on, anyone wanting her to come would have to compensate the partners.

Okay and also, can you foreshadow at all 2011 CapEx, how they might compared with 2007, whether estimated cash flow is an important metric and also what the priorities might be?

We're working very hard right now at looking at our capital requirements for 2011. Of course they vary greatly depending on what happens with the outcome of the production assets.

The way we are looking at it though is assuming that -- again assuming the worst and that we aren't able to divest the production assets, what would the capital requirements on the production side be, we have been paring back capital investment in production as part of this whole process. And going forward, I think it's fair to say that that sort of built up a capital requirement that if we are going to be operating a properties next year, the capital investment on production would be greater than 2010.

On the service side, we have nothing planned right now as far as growth capital. We do anticipate -- I'd say our maintenance capital on our fleet is roughly $50 million a year. But then beyond that, we are looking at various M&A opportunities and we are looking at some small organic additions but nothing is planned yet.

Thanks, Owen.

But I will add though, Phil, our goal is going to be definitely contain our capital spending well within our cash flow generation.

Understood, thanks.

Martin Malloy, Johnson Rice.

On the Newnan field, is it possible that after you do some of the well intervention activities that you might be able to add back some of the proved reserves you've taken off?

I think we would possibly add back production. The reserve reductions were actually based on the reservoir performance and we are taking a slight production hit right now due to the #3 being off-line. And the only reserves we possibly could add back there would be the reserves that were getting drained by the offset operator. If we had that production on, we could add those reserves back.

Okay, and, Owen, you mentioned M&A opportunities. Could you talk about what types of opportunities you might be looking for, types of vessels?

I'd rather not because most of the people that are out there are looking at probably the same opportunities but I will say that we're not looking at anything major. What we're looking at are small near-term accretive bolt-on kind of acquisitions.

Terese Fabian, Sidoti & Co.

I have a question on the work in the North Sea that you are doing. It's gone up nicely. What are the macro factors accounting for that?

I think in general over the last few years, there's been sort of an increase in interest in what is potential with well intervention with regard to production enhancement. P&A has always been a driver and historically has been the strongest driver and I think now actually production enhancement is starting to gain more and more popularity and therefore demand is growing.

We have seen competition in the North Sea but so far, the demand is outpacing the new addition of supply. That's basically it.

Plus I think our credibility in the North Sea and our leadership role makes us a -- there was a period where the clients were looking around a little bit stronger at some of our competitors and I think there's been a revived and renewed interest in our well ops capability.

And you said that you have a contract with Shell, I think?

Yes, we do. Shell is a very good client of ours. It's a partial utilization contract. They guarantee so many days each year and then at the beginning of the year, they designate what their plans for the year will be and that could be greater or less than.

Would you consider moving the Caesar to that location?

No, the Caesar is not a well innovation vessel.

I understand, but for pipelay work?

We did just bid a job in the Mediterranean that we were unsuccessful on. So, yes, we are going to be looking at more global opportunities for the Caesar where -- I have to say that we are not an [epic] contractor.

So, I think the way that we are -- our intent would be to work with the other contractors in making our assets available where they could fill in voids in their fleet. And I think to that extent, we could be -- gain some valuable contribution to the utilization.

Just one last word on the Normand Clough. Is that going to be a significant revenue generator or is that sort of a foot in the door into that region?

I think it's a wait-and-see right now. The difficulties of the Asia-Pacific market is the geographic expanse. One vessel can't cover everything, so you have to sort of pick a place where you're going to operate.

There has been tonnage added to the region over the past year or so. It's in a bit of an oversupply situation right now.

So initially here it is establishing a presence but our forecast does -- the vessel is probably more capable than anything else down there and we do have multiple service lines that can be deployed off the vessel. So we are hoping that we can overcome the difficulty of the geographic expanse by having multiple sources of utilization. I'm hopeful that by the end of next year, we are returning that region to its profitable stance.

(Operator Instructions) Michael Marino, Stephens Inc.

I was wondering if you could give a little color on kind of your commitment to selling the E&P assets and have you thought more about splitting the assets or maybe selling them more on a piecemeal basis given I guess that the deepwater kind of valuation assumptions have changed so dramatically over the last two months?

I am absolutely committed to divesting the assets and yes to all of the options you just mentioned. I think given the uncertainty of this market, you have to be realistic about what you can get accomplished at what value.

For instance, our capital spend -- if you look at the six-year -- the next six years, you're looking -- and the total value of our portfolio, you've got something like a $3.5 billion capital requirement to generate 2.5 TCF out -- and that's over and above our 400 current PDP. That obviously is a big number for us and it's not where we would like to focus our capital.

The options are sell it now and redeploy the value into the service side of the Company. Barring the ability to execute a 100% sale, I think you do look at other options of bringing in partners to provide the capital required and that preserves a lot of value going forward. But eventually we are absolutely committed to a divestment.

I guess you mentioned that there was some interest. Is that in the whole package or parts of it?

It's varied but we are in the middle of the process. So we really can't talk about specifics.

Okay, fair enough. Thank you.

There appear to be no further questions at this time. Please continue with your presentation or closing remarks.

Okay, in closing, thanks for joining us today. We appreciate your interest and participation and we look forward to talking to you again in 90 days. Bye bye.

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. Have a great day, everyone.