Helix Energy Solutions Group Inc (HLX) 2011 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the review of the second-quarter 2011 results and the 2011 outlook with investors conference call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded, Tuesday, July 26, 2011. I would now like to turn the conference over to Stephen Powers, Director of Finance and Investor Relations. Please go ahead, sir.

Thank you. Good morning, everyone, and thanks for joining us today. Here with me this morning is Owen Kratz, our CEO; Tony Tripodo, our Chief Financial Officer; Cliff Chamblee, EVP of Contracting Services; Johnny Edwards, Executive Vice President of Oil and Gas; Alisa Johnson, our General Counsel; and Lloyd Hajdik, Senior VP of Finance.

A special introduction to the investment community of Cliff Chamblee who may be new to the position of Executive Vice President of Contracting Services, but a very familiar hand about around Helix, since his been with the Company since 1997, most recently serving as President of our successful Robotics Business, Canyon Offshore.

Hopefully, you've had a chance -- you've had an opportunity to review our press release and the related slide presentation released last night. If you do not have a copy of these materials, both can be accessed through the investor relations page on our website at www.HelixESG.com. The press release can be accessed under press releases tab and the slide presentation can be accessed by clicking on today's webcast icon. Before we begin our prepared remarks, Alisa Johnson will make a statement regarding forward-looking information. Alisa?

During this conference call, we anticipate making certain projections and forward-looking statements based on our current expectations. All statements in this conference call, or in the associated presentation, other than statements of historical fact are forward-looking statements, and are made under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual future results may differ materially from our projections and forward-looking statements due to a number and variety of factors, including those set forth in our slide 2, and in our annual report on Form 10-K for the year ended December 31, 2010.

Also during this call, certain non-GAAP financial disclosures may be made. In accordance with SEC rules, final slides of our presentation materials provide a reconciliation of certain non-GAAP measures to comparable GAAP financial measures. The reconciliation, along with this presentation of the earnings press release, our annual report, and a replay of this broadcast are available on our website. Tony?

Good morning, everyone. Moving on to slide 5, which summarizes second-quarter results, we recorded a nice increase in earnings and EBITDA for quarter 2, with earnings of $0.39 and EBITDA rising to $176 million, up from the $149 million in the prior quarter. Quarter 2's revenues increased 13% over quarter 1, primarily related to a sharp increase in our well intervention and robotics businesses. Oil and gas revenues rose slightly over quarter 1, as higher realized oil prices offset the expected natural decline in production. When looking back to a year ago, Q2 2011 represented a sharp increase in revenues earnings in EBITDA, mainly driven by higher oil production and higher oil prices.

Over to slides 6 and 7, in addition to the nice uptick in earnings, the Company's financial condition continues to strengthen. In quarter 2, we repaid $109 million of our term loan and at the same time, upsized our revolving credit facility to $600 million. We also extended a maturity of our remaining term loan and the credit facility to July 2015, and under certain circumstances the maturity will fall into 2016. Along with cash on hand of $414 million at June 30, and available credit facility, our total liquidity at June 30 increased nicely to $965 million.

Our oil and gas production in the second quarter averaged 139 million cubic feet equivalent a day, while lower than the 160 million cubic feet equivalent in the first quarter, due to natural decline rates, production exceeded our own expectations due to better-than-expected well performance in the Phoenix field. Total production in the second quarter amounted to (inaudible) cubic feet equivalent. The Little Burn well was successfully completed in late May. Production of this well in the Phoenix field through the Helix Producer One commenced on a sustained basis in the last few days, slightly delayed due to the need to secure regulatory approvals, and for scheduled downtime on the third-party operated export pipeline servicing the Phoenix field.

Our overall production levels through July 24 averaged just 114 million cubic feet equivalent a day, due to the pipeline downtime serving the Phoenix field for approximately 10 days. However, the pipeline is now back in service, and with Phoenix ramping back up, we expect to exit July with a production rate of approximately 155 million cubic feet equivalent a day. I will now turn the call over to Cliff for an in-depth discussion of our contracting services results.

Thanks, Tony. Good morning, everyone. Let's move on over to slide number 9. The contracting service revenues picked up considerably in the second quarter, despite the continued weakness in the subsea construction market in the Gulf of Mexico.

The incremental improvement since quarter 1 is primarily attributed to the improved oil lease support vessel utilization of 99% in the second quarter versus 65% in the first quarter, as well as the 12% improvement in well intervention vessel utilization from 77% in quarter 1 to 89% in the second quarter. Margins also improved sequentially as a result of these increased utilizations, as well as the addition of a containment system retainer fee. So moving on to slide 10, this slide shows the equity earnings contribution of Independence Hub, Marco Polo, and the Clough-Helix joint venture. The results are fairly consistent with the first quarter, so I'll leave the slide for you guys' reference.

Moving on to slide number 11, as I mentioned before, our well intervention business achieved 89% utilization the second quarter, in Q4000 worked on various projects for Shell throughout the quarter, with minimal downtime for minor repairs and maintenance. Utilization in the North Sea improved from 68% in the first quarter to 87% in the second quarter. As a result, fewer downtime days for repairs and maintenance. Contracting activity remains strong for the Q4000, the Seawell and the Well Enhancer, and we maintain strong visible backlog for all 3 vessels for the remainder of the year. Normand Clough continued to work on a day rate construction project in China through the CloughHelix joint venture, which started in the first quarter this year and was scheduled to run through the third quarter this year.

Moving on to slide 12, as we mentioned in our previous call, the first quarter was a slow period for the robotics business, but it has since rebounded quite nicely. During the second quarter, we kept all 5 of our (inaudible) business, achieving 99% utilization and continuing to improve the ROV entry utilization, particular in Europe and West Africa. While the Gulf of Mexico continues to be a challenge is for us, our robotics group truly is a global operation with over two-thirds of the revenues coming outside of the Gulf of Mexico this year.

While geographic reach has been instrumental to the resilience of this business, we believe that the diversification of our services are offering us the key to the future growth. We completed the operation of our 2 road drill units during the quarter and are working to apply them on subsea coring projects in the coming months, and we're excited about the opportunities in this area.

You may also have noticed of that on the cover page of this quarter's slide deck, there's a picture of offshore wind turbines. This photo is one of our 200 construction vessels, the Deep Cygnus working on an offshore wind farm project in the UK sector of the North Sea. We believe there's substantial growth and opportunity in the offshore renewable energy market supporting wind farm development projects via trenching and cable barrel, and we have begun making investments to achieve a leadership position in this area.

We're currently constructing a new jet venture, the T1200, which will be packaged up next year with our other trenching and ROV equipment on board a new charter vessel that's specially built for us. This will be the most sophisticated cable trenching spread in the world and we believe there will be sufficient demand and potential returns to make this significant growth catalyst for our robotics business in the coming years.

So over to slide 13, our subsea construction business continues to lag as a result of weak market in the Gulf of Mexico, however utilization for the express and the intrepid are improving, and their combined backlog has doubled over the past quarter. It's important to note, while the bidding activity has improved, our customers are subject to permitting requirements for most projects, so scheduling has been problematic.

That said, Express has achieved 82% utilization the second quarter, and our backlog is growing and now includes projects in the North Sea next year. The Intrepid was dockside for most of the second quarter but went back to work in the last couple of weeks of the quarter. She is scheduled to perform some diving work for Chevron in the third quarter before deploying her to California. Last but not least, the Caesar remained dockside in Mobile through the quarter, her planned maintenance and upgrade continue.

So on to slide 14, this slide illustrates the design of our deep water containment system, the Helix fast response system. Here in the second quarter, we received our first quarter retainer fee from the consortium of the 24 Independents and completed the system upgrades to a 15,000 PSI well cap that's capable of operating in water depths of up to 10,000 feet, that's an improvement over 5,000 feet, and 2,000 feet -- 5,000 PSI and 2,000 feet than we had previously.

Moving on to slide 15, this slide shows the utilization we have achieved in the contracting services assets n the second quarter, and I'll leave that for you guys to reference, and turn it over to Johnny now for the oil and gas business.

Good morning. Please turn to slide 16. Slides 16 and 17 provide the financial highlights for the oil and gas for the second quarter. Additional details are provided in the footnotes for your review. As Tony mentioned earlier, oil and gas revenues were up slightly over Q1, due to higher net realized oil prices. The production for Q2 was 12.7 Bs compared to 14.4 Bcf equivalent in Q1, and the Q2 production was better than expected, with shelf production almost flat to Q1.

The better than expected second-quarter results for oil and gas are mainly attributable to the performance of 2 of our fields. On the shelf, we worked on 5 wells in South Marsh 130 field in Q2 and oil sales from the Small 130 field increased by over 50% from Q1 to Q2. In deep-water, the Phoenix field had 4 producing wells in Q2. These wells outperformed our expectations, which resulted in over 60% increase in the PDP reserves at our mid-year review.

We completed the Little Burn well in the Phoenix field in Q2. This well adds about 4.000 barrels of oil equivalent net to ERT, which will bring our net Phoenix production rate back over 12,000 barrels a day. We recently came up to full rate in our Phoenix field, as Tony mentioned, the gas sales pipeline was down for approximately 10 days this month, for a scheduled re-route of the pipeline. With Little Burn on production, the total net production rate approximates 155 million and this is about 70% oil.

We continue to focus our capital dollars on oil projects in 2011, where we can develop our proved and probable undeveloped oil reserves. As part of our oil and gas CapEx budgeted at $165 million, we have 2 shelf properties scheduled to start up in the second half of this year. [EG91302] is expected to add about 800 barrels equivalent per day net in the third quarter. We have already set a platform, completed the well in Q2, and we're waiting on a DOE MRE permit to install the sales line. Start up is expected in Q3.

We're installing a platform in facility in Southam 86 in Q3 which are adding 500 barrels in Q4, and allow us to drill 2 oil pads in 2012. On the exploration front, we have plans to participate in the drilling of 2 deep water exploration wells, contingent upon permit approval by the DOE, MRE, and rig availability. The first prospect is Kathleen in the Bushwood field, and the Kathleen well is a look-alike to our Danny oil well. The permit has been filed with the DOE.

The second exploration well targets the Wang prospect in the Phoenix field, and the well is targeting an untested section of the main field pay, from which most of the other Phoenix wells produce. The permit has not been filed yet but we expect to file soon. Both of these exploration wells target oil in existing fields with existing infrastructure to handle the production. Over to you, Lloyd.

Thanks, John. Turn to slide 18, slide 18 details our commodity hedge position for a significant portion of our forecasted production for the second half of 2011, through December of 2012. The 13.5 Bcfe hedge for the remainder of 2011 covers about 60% of our forecasted combined production, and since we are weighted about two-thirds to oil production, our remaining 2011 hedges are broken down about 68% for oil and 32% for gas.

In the second quarter, we layered in additional hedge contracts for 2012 for both oil and gas. Further, we entered into some collared crude oil contracts based on Brent crude pricing. We did this to better correlate our financial hedges against the actual pricing we were receiving for our GoM crude sales, and we will continue to opportunistically hedge our forecasted 2012 production depending on the current commodities markets.

Turn over to slide 20. Slide 20 profiles our current debt and liquidity position at June 30. And as Tony mentioned earlier in June, we amended our senior credit agreement, to among other things, extend the maturity dates of both the term loan and the revolver and to increase the capacity of the revolver from $435 million to $600 million. We repaid $109 million of the term loan and ended the second quarter with net debt of $833 million, a decrease of $83 million from the first quarter. And given the term loan payment, total cash decreased $27 million in the second quarter but our liquidity position increased $128 million to $965 million at June 30, with the increase in capacity of our revolver. And based on our outlook for the balance of 2011, we expect further decreasing of our net debt position from the June 30 levels. Tony?

Okay. I'm going to turn to slide 22 now, which outlines our updated outlook for the year. First of all, our oil and gas production forecast remains at 50 Bcfe for 2011, which is up from the original 2011 outlook of 49 Bcfe equivalent. Again, this forecast assumes no significant disruption caused by tropical storm activity in the Gulf of Mexico. We forecast oil and gas prices net of hedges at $95 a barrel for oil and 543 Mcfe for gas.

On the oil side, we're definitely benefiting from the Gulf crude pricing premium over West Texas Intermediate, and on the natural gas side, we're benefiting from both our hedges and natural gas liquids byproduct production. Due to the better-than-expected performance in Q2 and the improving outlook for our contracting services business, we now forecast EBITDA at $575 million in 2011, which is up considerably from the original outlook of $475 million, and up from the outlook we presented at the Q1 conference call of $550 million. You will note a plus sign on the slide next to the EBITDA forecast, which suggests we have upside potential of the $575 million number. Again, the big variable that could impact this number to the downside would be significant disruption to our oil and gas business, caused by tropical storm activity.

Capital spending is pegged at $275 million, a slight increase due to planned spending on well intervention equipment upgrades and engineering work on potential future well intervention assets, however no fleet expansion is it planned at this time. At the level of EBITDA with the forecasted level of CapEx for the year, we should continue to generate free cash flow to the second half of 2011, allowing us to further reduce our net debt position from June 30. Owen?

Just to add a little more color on the outlook, on the contracting services side, we 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 Enhancer and the Seawell are carrying a solid book of business as well. As previously mentioned, backlog for both the Express and the Intrepid has picked up. Both vessels are now working in the Gulf of Mexico, and we still expect the Intrepid to sail for California later in Q3, subject to customer permitting. In addition, we have secured work for the Express in the North Sea next year, and finally were not counting on putting the Caesar to work this year after she completes her planned shipyard upgrades.

In Canyon, our robotics business has seen a market increase in activity in Q2. Trenching for the renewable energy business in Europe has opened up a new and exciting growth path for our robotics business. The assets and operating know-how for subsea oil field trenching and burial apply as well to the offshore renewable energy, and we're keen to pursue and expand in this space. Our CapEx of $275 million breaks down to $110 million for contracting services and $165 million for oil and gas. The contracting services number contains maintenance capital, some upgrades to the HP1 to enhance its spill containment profile, some incremental investment in our historically profitable robotics business, and the thruster upgrade for the Caesar.

The major items in new oil and gas spending of $165 million include the Little Burn completion which is now finished, and the drilling of 2 exploratory wells, the Kathleen well in the Bushwood field and the Wang well in the Phoenix field. Both of these exploratory wells target oil and spending will be contingent upon securing the necessary drilling permits. In fact, just this morning, we have received the permit for Kathleen, so this is a nice positive for the outlook. Further, and as a result of strong oil price environment, we're quietly developing the shelf fields that Johnny mentioned earlier. Back to you, Lloyd.

Slides 26 and 27 are our non-GAAP reconciliation presented for your reference here. I'm not go over these schedules in detail. I'll turn the call back to Owen for his closing comments.

All right. Well, I'll be brief. It was a good quarter. And there's further upside potential. We are pleased with the continuing improvement not only in our work performance but also in the fundamentals of our financial health and positioning for the future. This is especially true, since this is all occurring during a very difficult market with uncertain regulatory environment. Our people, quite honestly, have just been doing a great job.

There's still upside room for improvement, and better results can be generated from our current asset base. First, our pipelay assets are contributing very little in this market, but there's indicators to suggest a return of enough of a market for us to push better returns. Second, our well ops division in Southeast Asia is now positioned for improved returns. Third, Canyon is performing well, but in a weak market. Not only do we expect the market to improve, but Canyon also has some exciting potential in support of the renewable energy market. This market is increasingly drawing on traditional oil and gas contractors to apply the technology to the renewable industry.

Fourth, on the production side, we have initiated a program to convert existing PUD reserves to PDP. We expect to be able to hold annual production at approximately the current levels as well as generate free cash flow. This conversion of PUDs to PDP should enhance the value of the remaining reserves. We will continue to seek buyers for some of our fields when the economics can be achieved, as we've always done historically in the past. Finally, we now have greater flexibility under our newly amended credit facility that allow us to consider further debt repayment that should have a positive impact on future earnings.

Beyond these inherent growth potentials, we're pursuing some exciting growth initiatives such as the Cap B vessel opportunity for Norway, as well as other opportunities. Our financial position will continue to improve, allowing us to take advantage of these opportunities as they're secured. Things look good now, but potentially brighter ahead, and with that, I'll turn it back over to the operator for Q&A.

(Operator Instructions) One moment please for the first question. And our first question comes from the line of Jim Rollyson with Raymond James. Please go ahead.

Good morning, guys.

Good morning, Jim.

It seems like marine is kind of improving a little bit better, maybe than expected, and obviously you're starting to build some backlog for things second half, and even into next year. Can you talk a little bit about just kind of the pricing and margin outlook, at least relative to our expectations, margins came in pretty strong this quarter compared to last quarter, for sure. And I'm kind of curious as to how you see margins trending over the next two or three quarters and are we starting to get enough bidding activity that there is room for that to improve, or it's mostly just on utilization that margins have picked up so far?

Well, I'll let Cliff take that but I'll just start by saying that I think the market is still very, very tough right now. I really attribute our quarter to the performance pickup in the efforts of the people we have here at Helix, but I'll let Cliff comment more on what he sees out ahead in the market.

Yes. On the contracting side, I guess on the roll-off side, it's utilization is driving that. Where there's been downside as we mentioned is in the Gulf of Mexico, so utilization is still pretty low there but it is starting to come back, so on the sub sea construction site, pipeline side, starting to pick up utilization there, not great margins but we do have our backlog filling up. We are starting to increase those margins a bit going forward. And on the Canyon side, it's primarily due to the West Africa, North Sea and a little bit of Asia stuff, the Gulf of Mexico for the Canyon side for -- that's still pretty weak.

But getting a little bit better, it sounds like?

Yes. Jim, I'll add a comment here on margins. I think utilization is definitely a key factor driving margins today, but I would say based on what we are sensing in terms of rates and pricing, there is probably a tendency more in the future on the upside than the downside.

That's good color. On the Grand Canyon charter that you guys have coming in next year, is that replacing any of your existing charter vessels or is that completely incremental?

In theory, it's going to replace one of the charter vessels that we have now, the Island Five here which is over in the North Sea, that vessel is supposed to get in May to June of next year. We will just play it by ear. We have the option to keep the Island Five here if the market's good, if not, we can give it back and use the Deep Canyon going forward on some of the wind farm trenching projects that we have.

And I guess the one incremental part at this point is the new trencher, right?

Correct.

Okay. Oh, and any update on the Statoil feed study for a possible new Q4000-type vessel?

No real updates. We're still continuing to work hard on the resubmission. The resubmission is due September 15, it was postponed about a day to allow us time to do the feed study for adding the stack to the submission and then Statoil is saying award sometime between November 15, and the end of the year.

Okay. Great quarter. I'll turn it back. Thanks.

And our next question comes from the line of Roger Read with Morgan Keegan. Please go ahead.

Good morning.

Hey, Roger.

Real quick, the Caesar laid out for the rest of the year, but what appears to be an overall let's say slight improvement in the market. Are you bidding this vessel for 2012? And if so, where would it kind of be most likely to go?

We're -- again I'll turn it over to Cliff, but we're being very selective with the Caesar. Right now we're not planning to work it. There's nothing in our projections for it. Yet we are remaining open, especially when it comes to working with other contractors on larger projects.

Yes. That's right. We are bidding it directly as Helix, but we're also bidding it with other contractors, on some of these other projects designed to coordinate products, but most of the stuff we are bidding for 2012 and 2013, as Owen mentioned, is selected for our projects that we really want to go after, and they're either here in the Gulf of Mexico or Brazil.

And I mean at this point, what would you think it could work half of 2012? Most of 2012? Very little of 2012?

I don't think that you're going to see up put any contribution for the Caesar into our forecast or projections.

Okay. That's helpful. Flipping over to the E&P side, permit to drill the Kathleen well, could you give us an idea of what your net ownership is in that, maybe the sort of the rough cost as we break down this increase in CapEx, $250 million to $275 million on the near term but $225 million to $275 million from the beginning of the year. Is that driving a portion of that increase, or was something like this already included in the $225 million?

Kathleen is in the Bushwood field, and we haven't included anything in our forecast for an exploration well as far as contribution on production side. To answer the first part of that question, Deep Gulf is our partner there in the Bushwood field, and we've sold down an interest to 50%. We got a nice promote, we won't go into those details, so we will have 50% of the Kathleen well once it's drilled, but as I mentioned, none of the results of that well are included in our projections.

Roger, CapEx has always been in our number for the start.

For Kathleen?

For Kathleen. The $225 million that we originally had for CapEx included Kathleen.

So can you give us a little bit of an idea then what the $50 million increment is here? Is that the shelf work?

It's mainly on the services side, adding some capacity to Canyon, adding some upgrades to well intervention, that's where most of the increase in CapEx is coming from. It's really not the E&P side.

And Robert, that's a $25 million increase overall from $250 million to $275 million.

Well, from the original, it was $225 million, that's what I was trying to make sure of.

Quarter one, it's $250 million.

Yes. Sequentially just $25 million but $50 million from the beginning of the year.

That's all in the service side as we're starting to position to start growing again.

That's helpful there. And then final question, if Wang goes forward, is that included in the numbers, or do you look at that at this point probably as more likely a 2012 expenditure and event?

Roger, Wang is included in our CapEx forecast, but not the production forecast.

Okay. And then final question for me, as you look at the well intervention business, you're at a high level of utilization. And on the long story of whether you're going to go Cat B or a different version of the Q4000, next-generation, but given the high utilization in that area, what are you seeing in the way of pricing power there? I know ultimately, kind of drilling rates impact that, but we haven't seen any problem on the drilling rates side so maybe give us an idea of where we are on ability to raise prices there, or improve margins going forward?

Well that's been a discussion the we've been having across the contracting services, not just in the roll-off side of it but we have had a discussion, and we are pushing the pricing slightly to test the market a little bit on new opportunities, but several these are NSA type contracts, we've already got pricing established with the client.

So 2011 is set but 2012 has potential?

There may be a little bit of room on the backend of 2011 in the Gulf of Mexico but most of it's set and 2012 has some potential, correct.

Great. Thank you.

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

Thanks, good morning. Just a couple vessel-specific questions. Cliff, if you could help me out a little bit, the Express contract are moving in the North Sea in the back half of 2012. Just curious if this is a term-oriented contract or I know Gulf of Mexico is showing some signs of life here as you indicated, does this mean you'd also consider moving the Intrepid out, just trying to get a little color on where you stand on pipelay Gulf of Mexico.

As we said, the backlog for Gulf of Mexico pipelay through this year was pretty full, and it's going up quite nicely into the first part of next year, and then we do plan -- it's a moving target there a bit, with permitting and stuff, but we do plan to send the Express to the North Sea. Probably early third quarter, late second quarter, early third quarter of next year.

Okay. That's helpful. And just if we could circle around a little bit on non-oilfield demand, your robotics utilization obviously on the RV support side very strong, Tony you indicated some upward bias here still hard to get much better than 99% utilization there. Has this turned aggressively here in the North Sea? You've referenced the wind farm development, obviously you are making some investments on a little-bit more sophisticated trenching systems. Just curious on the sustainability of, you already support robotics utilization because it was a pretty stout quarter here in Q2?

Between the North Sea and West Africa, we were able to move those vessels back and forth from project to project, so the oil and gas side of the construction business is doing pretty well, utilization-wise and rate wise, and then we got this added kicker of the energy business as kind of a mirror of what the telecommunications business was for our transoceanic cables of maybe 10 years ago or so. But if you came up with it in Europe, there's a whole bunch of -- a great push to go to alternative energy, and I think this is just the beginning of what's going to happen in Europe and hopefully come across to the Eastern part of the US as well, so we see a pretty big future in that market, trying to position ourselves to be a leader in that market it we're not already.

Okay, fair enough, and last one for me and I'll turn it back, just in terms of D&A expectations on the oil and gas side for the back half of the year, maybe a little bit of help there kind of calibrating on what expectations are on your 50 B production run rate, should we be hovering in this kind of low $50 million per quarter D&A run rate?

Well, in terms of -- let's just take oil and gas size for a second, I think what you saw in Q2 is probably what you're going to see going forward, absent any major revisions up or down. Okay? But I would expect -- if your question was limited, Joe, to the oil and gas side--.

It was. That's fine.

I think that kind of second quarter DD&A rate should continue on. The only wild card there are if we come to Q4 when we do our reserve report and we have a major upward or downward revision, that obviously could impact DD&A reps.

Got you. Appreciate it gentlemen, I'll turn it back.

(Operator Instructions) And our next question comes from the line of Martin Malloy with Johnson Rice. Please go ahead.

Good morning. Are there any dry dockings we should be mindful of next couple quarters?

No, not this year. The first major one we have will be Q4000 in February or March of next year. That's about a three or four week dry dock.

Okay. And then in the earnings release you referred to a revision of your proved reserve estimate. Could you talk a little bit more about that during the quarter?

Yes. This was an internal look. We've felt compelled in the certain fields to take a look at our reserves based on production rates, and it wasn't a comprehensive look, so therefore, we feel it would be prudent not to talk about what the mid-year reserves came about because it was a limited look at the reserves, but we felt compelled to increase the PDP reserves at Phoenix, because the wells were outperforming the decline curves we assumed. But we also took some minor negative revisions in a few other fields, just based on production curves, so -- but again we don't feel like that the amount of work done was robust enough to publish numbers.

Okay. And then, I'm not sure if I heard correctly, but did you suggest that as you convert the PUDS to producing reserves that production should stay relatively flat from 2011 to 2012?

The thing we haven't done our 2012 budget, but the big picture with the PUD conversions shows that we can maintain approximately flat production from 2011 to 2012.

Okay. Thank you.

And our next question comes from the line of Michael Marino with Stephens Incorporated. Please go ahead.

Good morning.

Hi.

Question on I guess Kathleen with the permit in hand, how long before you can actually get there and start drilling? What's kind of the, I guess, timeline in terms of bringing production online there?

Currently we're negotiating for a rig to drill the well. Having a permit allows you to do the rig negotiation, so getting the rig, we expect to get a rig in this year. The Bushwood field has the Danny well there. We have the infrastructure in place. It'll be a Danny look-alike, a Danny twin almost, just a little deeper, so the infrastructure is there, once it's drilled and completed, but is an exploration well. Once it's drilled and completed, it's successful, it's a short-term to hook it up, probably a couple months. And in deepwater a couple months is pretty quick.

Okay. Kind of late Q4 before we see some production from Kathleen probably?

We're not going to budget any production in Q4. We're going to start it at 2012.

Okay. And maybe help us understand how the government's working with your other pending permits. What kind of timelines are you looking at in terms of start to finish on the permitting front now that you've gotten Kathleen, I guess?

Different permits seem to take different amounts of time. Things we would expect to get quickly, a pipeline permit for example, we waited a full quarter on a gas pipeline permit at Puget Island 302, so it's hard to estimate. It's uncertain, as to what they will do. Almost depends on who in the government gets your permit to work on, so when we get the Wang permit in, I believe the Kathleen permit took about three months, so I don't know that that's going to be the same. It depends on who in the government gets our Wang permit.

I'd like to just jump in. Add my two cents into the story. It really is to the point now where it's not just the permitting process but also regulatory. We just saw that on the delay on a Little Burn driven by another regulatory body, and it wasn't connected with permitting. Cliff is looking -- he's mentioned earlier the difficulty of scheduling the assets on pipelay projects because of the erratic nature of the permitting and the scheduling there. It's really getting to the point where the government and the regulatory process and the permitting is dictating our management portfolio and management of our assets, and I think it's not too well appreciated as to how difficult that really is in this market, which is why my earlier comment, that I think a lot of our performance here is down to the scrambling of the Helix personnel to try and accommodate all this.

Okay. Great. Appreciate the color. One kind of follow-up on the robotics group -- I guess historically, Tony, you've talked about visibility there being more short-term. Having maybe six months of kind of visibility. With the stuff going on in the North Sea, do you have more visibility there than maybe you've had historically and kind of maybe talk about the visibility of that segment?

Well, the North Sea in general always has plans further in advance than they are in the Gulf of Mexico, it's historically been that way and continues to be that way now, so there is more visibility for long-term planning and projects in the Gulf of Mexico, and we're hoping to do even more so in this renewable energy/wind farm business. I don't know if that answers your question or not.

I mean, do you have kind of a year -- can you look at a year and say that business is going to be pretty busy for the next year?

No. It's not really that we have contracts that we can see out for a year other than on some of the burial stuff we have frame agreements with two different companies that go out five years with X amount of numbers of days per year that we're guaranteed. So on that burial side, there is a little bit of that but on the -- most of our revenue still comes from the oil and gas side, and that's more just consistent with historical trends than it is any real visibility anything -- like six months is quite a bit of visibility in the robotics business for us. And I don't see that improving dramatically when we can look out and see a year out it advance now.

Okay. Thanks.

(Operator Instructions) And there seems to be no further questions. I'll now turn the call over back to you, sir.

Okay. Thanks everyone for joining us today. We very much appreciate your interest and participation and look forward to having you participate on our Q3 call here 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.