Helix Energy Solutions Group Inc (HLX) 2010 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Helix Energy Solutions Group Inc. review of fourth quarter 2010 results with investors conference call. During the presentation, all participants will be in a listen only mode. Afterwards we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded today, Thursday, February 24, 2011. I would now like to turn the conference over to Mr. Stephen Powers, Director of Finance and Investor Relations.

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

Hopefully you 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 web site 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 the 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 Security 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 end December 31, 2009 and any subsequent form 10Ks.

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

Thank you. Let's move to slide 5 which summarizes fourth quarter results. I will focus our commentary of sequential quarterly results comparing Q4 to Q3. Quarter 4's revenues declined 22% to $306 million, reflecting a sharp decrease in contracting services revenue partially offset by a nice increase in oil and gas revenues. The largest contributing factor to decrease in revenues directly relates the Helix Producer One coming off BP Macondo spill response activities and on to in house service on the Phoenix field. Other contributing factors including seasonal declines plus the Caesar coming out of service for a previously scheduled upgrade work.

Oil and gas revenues moved up nicely by 43% in quarter 4 versus quarter 3 reflecting the start of production on the Phoenix field as well as higher oil prices. Our earnings were impacted by the special items noted in the press release and covered on slide 6. When looking at the results from a cash flow basis, we generated a decent level of EBITDA during Q4 at $95 million.

On slide 6, earnings were impacted by a few noteworthy items. First, we took a non-cash charge of $23.9 million associated with writing off the goodwill and related to that some deferred tax assets for our Australian operations. We concluded that the carrying value of the assets was no longer justified, given the performance of our Australian operations the last couple of years. Second, we suffered a loss of $22.4 million after tax in the quarter related to the first job performed by the Norman cloth on an abandonment project in the South China Seas for CNOOC, the Chinese National Offshore Oil Company. To establish ourselves in the market we took on weather, another risk, which obviously impacted our profitability, but thankfully we have moved off this job now.

Third, we impaired some of our oil gas properties on the shelf and also wrote off some deep water leases to the tune of $15.6 million pre-tax or $10.2 million after tax. On the positive side, we generated a nice amount of free cash flow in the quarter as our cash balances increased by $66 million during the quarter to $391 million. Our total liquidity at year end stood slightly below the $800 million mark.

We commenced production on the Phoenix field on October 19 and finished the quarter with 13.7 billion cubic feet equivalent of oil and gas production, above our previous guidance. We have been very pleased with production out of the Phoenix field and our production profile today is now 63% oil. And through Tuesday, we were averaging 162 million cubic feet equivalent for the month of February, with Phoenix production at approximately 12,000 barrels of oil equivalent a day net to our interest.

Furthermore, we are pleased to announce that we have received a completion permit for the Little Burn well, a part of the Phoenix field and we expect to bring production from this well on sometime before the middle of the year. I will turn the call over to Owen for an in depth discussion of the contracting services results.

Thank you, Tony. Good morning, everyone. Let's move to slide 9. Helix contracting services delivered top line growth year over year owing to higher utilization in our well intervention and robotics business. On a sequential Q3 to Q4 basis, revenues were down as expected coming off of a strong third quarter that was bolstered by Macondo spill containment activity. As Tony already mentioned, our margins were off primarily due to the Lufeng field abandonment in China.

Slide 10 shows the equity and earnings contribution of Independence Hub, Marco Polo and Club Helix JD. The results are fairly consistent with Q3, so I will leave this slide for everyone to look at, as you wish.

Over to slide 11, our well intervention business enjoyed 90% utilization in Q4. Both the T well and Well Enhancer stayed busy in the quarters despite a delay in the Enhancer's coil tubing upgrade. And both vessels carried healthy back logs into 2011. The Q4000 spent most of Q4 working through a back log that had built up as a result of -- it was built up pre- Macondo and delayed due to Macondo. She also has a healthy and visible backlog for 2011. The Normand Clough in Australia, worked on the Lufeng field abandonment campaign offshore China for CNOOC, but as Tony mentioned earlier, unfortunately at a substantial loss and is now working on a construction project in the South China Sea, which I should point out fairly low risk day rate contract.

Moving to slide 12. As we forecasted in our Q3 call, our robotics business experienced a seasonal slow down combined with lower activity levels in the Gulf of Mexico. As such, we have adjusted the size of our charter (inaudible) fleet to scale to the current activity levels in the business. One interesting component of this business to watch is trenching and power cable which is being driven by increased demand for sub-sea cables that are deployed for interconnections and offshore wind integration projects. In 2010 we generated $36.5 million in revenues from this non-oil field business.

Over to slide 13. The Intrepid and the Express have combined utilization of 97% for the quarter while the Caesar went into dry dock for some planned upgrades after completing a job in Trinidad in November. The sub-sea construction market is currently seeing a significant contraction in activity in the Gulf of Mexico which is an area of concern for us. The Caesar currently has no backlog. When she comes out of the shipyard next month, whereas our near term visibility for the Express is good, it's a little bit weaker for the Intrepid.

We tactically made the decision in 2009 to focus our pipe lay assets in our traditionally strong Gulf of Mexico backyard, but we couldn't foresee the consequences of the regulatory slow down in the Gulf of Mexico. As we look into the near and midterm futures, demand for sub-sea construction lags drilling by 12 to 18 months and drilling activity in the deep water of Gulf of Mexico remains at a standstill. And this is a good lead in to the next slide, slide 14.

Helix plays a key role in the Macondo spill response last summer providing assets and off shore teams to assist in the completion and containment effort . Based on the lessons learned and technologies developed through those efforts, we have partnered with a group of independent producers in the Gulf to develop the Helix Fast Response System or HFRS. Last month, we signed and agreement with a nonprofit organization called Clean Gulf Associates to make the system available to the participants as the essential component of their deep water spill response solution should a future blowout incident occur. This was done in exchange for a quarterly paid retainer fee.

We also signed separate utilization agreements with each participate company specifying the callout rates for the Q4000, the HP1 in the event that the system was ever needed. As of today, there are 20 companies participating in programs. These companies refer to themselves in the drilling permit applications with the BOEMRE as members of the Helix Well Containment Group which indicates that they have contractual access via their agreements with the CGA and Helix to the Helix Fast Response System. As well as over 30 subcontractors who provide other core services necessary to fully compliment a deep water response.

The third party subcontractor services include firefighting vessels, disbursement systems, sport vessels and the like. It would be coordinated by the CGA along with activation and deployment of our system. The HFRS stands ready today to respond in the unlikely event of a deep water blowout. Our current system includes the Q4000, a 10,000 PSI stacking cap that is capable of operating in up to 5600 of water, all of the necessary equipment to completely cap and close an oil that has a mechanical and structural integrity to be shut in. And the ability to flow back and flare up to 10,000 barrels of oil per day and 15 million cubic feet of natural gas per day.

In addition, we are currently working on enhanced solutions that will make the system ready for more comprehensive responses. The enhanced system, which we are targeted for completion around the end of Q1 adds a 15,000 PSI capping stack, the production capabilities of the HP 1 and increases the systems depth capability to 8,000 feet. The enhanced system will be able to shut in a well with mechanical integrity to be shut in and/or produce up to 55 dozen barrels of oil and flare-up to 95 million cubic feet of gas per day. We believe that our containment system using vessels that provided their capabilities during this type of work last summer meets or exceeds the regulatory requirements that have halted drilling activity in the Gulf. And it's our hope that the HFRS will help get activity restarted very soon.

Moving to slide 15, this slide shows the utilization we achieved with our contracting assets in Q4 and I will leave that to your reference as you wish. Now for our oil and gas business, I will turn it over to

Good morning. Please turn to over to slide 16. Both slides 16 and 17 provide the financial highlights for the fourth quarter. ERT production for the quarter as Tony mentioned earlier, was 13.7 BCFE, and that is compared to 10.4 BCFE for the third quarter.

The increase in production is mainly associated with the startup of our Phoenix field. And in the fourth quarter, the Phoenix field produced over 400,000 barrels and 680 million cubic feet of gas and this net ERT during the quarter. The production from the Phoenix field changed our production mix for the quarter to 52% oil. That's compared to only 46% oil in the third quarter. The increase production and the change in product mix and the higher oil price realization, has increased the revenue for the fourth quarter by $41 million up to the $137 million.

In early January, the 4th Phoenix well was brought online. For February our net production rates for Phoenix are averaging 12,000 barrels a day equivalent. Driven by the production from this field, our current production mix has increased to 63% oil as Tony mentioned earlier. In February we received the BOEMRE which is formerly the MMS permit to complete the Green Canyon 238 number 1 Little Burn well in the Phoenix field. Our plan is to complete the Little Burn well during the second quarter with first production around midyear. Our expectation is that Little Burn will add 3,600 net barrels of oil equivalent per day.

Now turning to slide 17, our increase in operating costs is directly associated with the Phoenix field. Higher production volumes increasing our DDNA, and that was an increase of $15 million and operating expenses increased by $3 million reflecting the cost of the Phoenix field offset by reduction in cap bond expenses. All the other costs from the fourth quarter were in line with the third quarter with nothing unusual.

Turn to slide 18, on December 31, 2010, we had total [prove] reserves of 376 billion cubic feet of gas equivalent and that's compared to 400 billion at June 30, our mid-year reserve report. The production for the second half of the year is the principle change between the mid-year report and the end-of-year report with no other significant changes. Our reserves comprise 40% oil in our reserve report and 60% gas with a discounted PV 10 of about $1.3 billion of pre-tax based on SEC pricing at $77.55 a barrel and $4.40 per MCF. About 39% of our reserves are developed and 61% in the undeveloped category. Applying the forward strip pricing at 1231, this gives us a PV 10 of $1.7 billion at 1231 pricing. I'll turn it back over to you, Lloyd.

Slide 20 is a snapshot of our debt and liquidity position at the end of the year. In the fourth quarter our net debt position was about $65 million from September 30. As our cash on hand increased to 391 million from 325 million at the end of quarter three. Since the end of 2009 our net debt decreased over $120 million. Based on the outlook for 2011, we expect further decrease in the net debt from year end 2010 levels. Tony?

Okay. Let's move to slide 22 which provides a general overview of our outlook for 2011. First we forecast oil and gas production at 49 billion cubic feet up from 47 billion in 2010. As Johnny mentioned, our production is now 63% oil. We expect EBITDA to increase to approximately 475 million in 2011 up from the 430 million in 2010. And at this stage, I would say there is probably more up side to that figure than we have got on this piece of paper here.

CAPEX is pegged at $225 million. And with the hedges in place and based on our forecast to production rates, we expect to yield $87 a barrel for oil and $4.80 for natural gas. Obviously, at today's prices, that would be higher than those figures. At the level of EBITDA and with the forecasted level of CAPEX for the year, we should generate a nice amount of free cash flow in 2011, allowing us to increase the cash balances from the already healthy $391 million at year end 2010.

On slide 23 and 24 we provide more color on this outlook. On the contract for service side we expect another strong year for well intervention both in the Gulf of Mexico with the Q4000 and in the North Sea with our two shipshape intervention vessels. Our vessels carry strong backlog into 2011. Due to the regulatory overhang in the Gulf of Mexico, we expect our robotics and sub-sea construction business to have a down year from 2010. Again, this is baked into the outlook noted on slide 22. Our oil and gas production forecast, 49 billion cubic feet has two critical assumptions. No significant tropical storm activity in the Gulf of Mexico and Little Burn production commencing prior to midyear. Again, we have secured the permit to complete the well.

Our CAPEX at $225 million breaks down to $65 million for contracting services, $160 million for oil and gas. The contracting services numbers contains little spending above maintenance other than some upgrades to the HP1 to enhance it's spill containment profile and some incremental investment in our historically profitable robotics business. We have assumed no CAPEX associated with the potential for a Cat B vessel for Statoil.

The major items in the oil an gas spending are $160 million includes the Little Burn completion and drilling of two 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 obviously is contingent upon securing the necessary drilling permits. Another general override assumption is that we continue to own the oil and gas business throughout the year. Obviously if we succeed in selling this business in whole or in part, the numbers reflect in the outlook would change significantly. Lloyd?

Slide 25 represents our commodity hedge position in both volumes and prices for 2011 and 2012. The 25.5 BCFE hedge for 2011 covers a little over 50% of our forecasted production for the year. Of the 25.5 BCFE in hedges, the split is 57% oil, 43% gas, which is in line with our current daily production profile of over 60% oil.

Slides 27 and 28 are the nonGAAP reconciliations presented here for your reference. I will not go over those in detail for the call. And at this time, I would like to turn the call over to Owen for his closing comments.

Thank you, Lloyd.

Bottom line, the losses in the quarter were obviously a disappointment, but, I think as long as you learn from those and take appropriate actions it's possible to look beyond them. What should be obvious at this point, is that we are successfully working our way out of the position that the Company was in. Capital spending discipline and project execution is restored. Wells ops is operating well and positioned well for future growth. The Canyon robotics business is also operating very well and has the potential to surprise and be up side of expectations. ERT production is now operating well. Surprises have been reduced and expectations conservative. We are generating more than 30 million in cash each month from our new stable production and it's becoming more and more oil focused. Risks will be better managed going forward in contracting and we don't intend to drill any further 100% production wells.

Our challenges, though, are first we have incurred a number of significant losses on a few contracts specifically with HSC pipe lay. And more recently with an approximate $30 million loss on the Lufeng China project. We have taken aggressive steps to modify our risk management and operating structure to prevent further occurrences. The total of this kind of loss for 2010 was $60 million in total. This is a positive, looking forward, as I feel this is now being mitigated.

HSC pipe lay, with three major assets in the Gulf of Mexico as their focus, is a challenge. The Gulf of Mexico in my opinion, will not likely see a normalized market before 2013 due to the impact of the regulatory environment. I do see a sign of resumption of the drawing permit process possibly in the near future given the readiness of containment solutions and the work of producer groups to provide the central infrastructure in crisis management. At what rate permits will be issued remains to be seen and this is critical for a normalization of the Gulf of Mexico market.

For 2011, our focus will be on, first, allocating capital production to develop valuable leases as the permitting process allows. We will also allocate capital to low risk PUD conversions to PDP. This is less dependant on permitting with 60% of our approvement roughly in PUD. This is a chance to greatly increase our production and cash flow and the emphasis will be obviously on oil PUD. This will also enhance the overall value of our production business and its marketability. We will continue to seek a prudent investment and monetization of all or at least part of our total production. As we begin to see signs of drilling resumption and as the market demand improves, we think the opportunity to affect such an investment will also improve. We will be patient here.

We will explore our alternatives for the Gulf of Mexico pipe lay business. This includes all kinds of alternatives, partnering with people, divesting of assets, renewed better managed international effort or it could also simply be stacking the assets and waiting. We will continue to reduce debt as well as seek to make improvements in our debt structure. Our ultimate goal is a debt to book cap of 30%. We will aggressively pursue growth opportunities especially in the area of well ops where we are clearly the global leader. The Federal Cat B tender award announcement has been delayed by Statoil until the end of March. However, there are other opportunities, but these other opportunities are all events beyond 2011.

We will continue to simplify our business model and operations, thus lowering our cost of doing business. There are market uncertainties but we are clear on our path. 2011 should be an improved year over 2010 and there is plenty of value to further unlock. It may be a more deliberate pace then some may hope, be it will be a path based on long-term sustainable growth and improvement. I expect a sustained period of year-over-year growth in the shareholder value ahead. With that I will turn it back over for questions.

Operator?

Thank you. (Operator Instructions). Jim Rollyson with Raymond James. Please proceed with your question.

Good morning, guys. Owen, or maybe Johnny, just on the production guidance for a 49 BCFE, works out to about 134 million equivalents a day, and obviously you are running in the 160s in February, implies either a pretty strong reduction or decline in production as you go throughout the year. Just trying to figure out, A, do you think that starts up stronger and weakens throughout the year from a profile standpoint, and B, is there a little bit of conservatism in your guidance, do you think?

Well, we always like to provide guidance that we think we can meet on the production side. And from that, I guess you could interpret some conservatism. But typically the Gulf of Mexico wells will see a 30% decline per year. We do have some capital money in there, but we also risk weight some of that work as well. So, I think the 49 BCF is achievable, and possibly beatable.

Okay. That's helpful. And Owen on the HFRS, I don't know what you can say exactly, but as it relates to the annual retainers that you guys will get, is this something that is meaningful and starts right away, or is it more of a small margin enhancer, absent any -- hopefully none -- but any actual situations in the Gulf?

Jim, this is Tony, we are under a confidentiality agreement with CGA, so we can't disclose the exact amount. It starts April 1. It's not a large number, but I wouldn't call it insignificant either. So, hopefully that answers your question.

Sure. And then last, I guess for me for now is Well Ops seems like you have pretty good coverage from a demand and utilization standpoint. Can you spend maybe a minute, and just talk about how the margin environment looks for that work for first quarter in 2011, maybe relative to what you've seen in the last quarter or two?

Well Ops looking forward, I see -- once you take the Macondo event out of it, I see Well Ops as a pretty steady state robust business year-over-year here with our current assets. I think the opportunity for Well Ops is not necessarily in expanded margins, but in the addition of assets and further growth.

Okay. Thank you.

Thank you. Michael Marino with Stephens, Inc. Proceed with your question.

Good morning. Just a quick point of clarification on the EBITDAX guidance. Does that include anything from equity income?

Yes, it does, Michael.

Okay. And then on the job in China, what was the revenue contribution? I'm trying to get to maybe what margins could have been, absent that job?

The revenues we booked in fourth quarter for that job was very, very small, with the pre-tax loss of $22 million. So that really did impact our margins quite considerably. Lloyd, I think it was only $1 million or $2 million of revenues that we actually booked in the fourth quarter.

That's right.

And some of that has to do with reduction in scope and the way you handle long-term contracts from an accounting standpoint, you are taking a -- adjusting what you booked previously, Michael, we shouldn't get into it because it's fairly complicated, but it was a very low amount of revenues with a large loss.

Okay, and then on the Caesar, that vessel was -- did that generate any revenue in the quarter?

A little bit in October coming off the Trinidad job, just a little bit.

Were there costs associated with it? Dry docking it that maybe, once it's dry docked, there is some costs that go away there? Can you quantify that?

I think there was a small amount of costs in the interim between the end of the project at the end of October, and going into the dry dock, but once you went into the dry dock, the costs would have been capitalized. This dry dock was a further continuation of completion of work on the vessel.

I will add though that there is another dry dock period that is probably coming up where -- when the vessel was originally built there were two thrusters in engines not installed, and I think I've mentioned it before. We were planning to do that during this dry dock period, but because of the lack of the facility, saving the capital, and then further engineering what could probably be a better solution, that work has been deferred until later on in the year.

Okay. Finally, you mentioned the Intrepid. I think previously you had mentioned that potentially had some work outside the Gulf of Mexico. Can you update us on the outlook for that vessel.

Right now she is supposed to have a contract in California to do some IRM work out there in replacing control lines and other work in the California fields. When she actually goes is still subject to getting all the permits and everything required and a final contract. So, I think right now the date is something like --

May. Mid-May at the earliest.

June timeframe.

Yes.

Okay. And how long does that work last?

The actual contract I think is 90 days, but the transit is going to be fairly extensive. And then once we get out there, there is additional work out in California, which we would be well positioned then to start building a longer campaign.

You are getting paid to mow, correct?

Yes.

Okay. Thank you.

Thank you. (Operator Instructions) Martin Malloy with Johnson Rice & Company. Please proceed with your question.

Yes, could you update us on your outlook for what you might do with the Caesar. Is it something that you are still perhaps interested in selling, or are you looking to leave it at the yard if there is no work to be found for it?

Probably yes to all the options. It's a very changing market conditions out there. Right now we have no visibility for it. So, our definite plan, and what we budgeted for is to put her back in the dry dock, finish the thruster (inaudible) and then following that, our intention would be to cold stack her and just wait. Alternatives to that would be to seek partners that wish to collaborate with us on working her and contracting her, and also sale of the asset. So yes to all the options, and we are pursuing each of those.

And Marty, just from an outlook standpoint, our own assumptions assume no positive contribution from the Caesar in 2011. Any work we wind up getting would be upside.

Okay. And is there any update that you can provide us with or additional information on the sale process of the E&P assets in your outlook there.

Marty, as Owen says, I think we need to be patient here because of the regulatory overhang. I will say this, our data room is still open, and we continue to stay focused on ultimate disposition, and in the meanwhile we will enjoy the high oil prices and high production.

Thank you.

Thank you. Stephen Gengaro with Jefferies & Company. Please proceed with your question.

Good morning, gentlemen. Two things, Tony, can you give us any sense for the breakdown of the EBITDA guidance between contracting services in the production?

I would say certainly this year, with the expected down year, particularly in the Gulf of Mexico on contracting and also coming off of all the nice EBITDA we earned from Macondo last year, we are going to be down on EBITDA on the service side, and substantially up on EBITDA from the E&P side. We are definitely well over 50% EBITDA coming from oil and gas. I will just leave it at that.

Okay. And then just as a follow-up, as I think about that, and how it impacts your quarterly distribution of earnings, normally you get, I would say more seasonality in the contracting services business. Would this change the quarterly progression of earnings because it is heavier E&P, and E&P sounds like it is going to be lower in the back half of the year than the beginning of the year?

Yes, I think that is a good way to look at it. A lot depends on commodity prices, Stephen, as you know. But we expect an improving year in services as the year rolls out, and we expect, as Johnny mentioned with decline rates in the latter half of the year, maybe EBITDA to be less strong for oil and gas in the second half of the year than in the first half of the year. Little Burn will help somewhat, but again, we expect improving for contracting services as the year rolls out, and the slight declines in oil and gas from an EBITDA standpoint.

Okay. Thank you.

Thank you. (Operator Instructions) Phyllis Camara from PAX World Funds. Please proceed with your question

Thank you. Good morning. I was curious, how does your response system differ from the one that I believe Exxon has got going or built or put together?

I would refer you to the MWCC website for details on theirs. Ours has a little different philosophical approach, I believe, whereas the MWCC, if you consider the wells in the Gulf of Mexico like a pyramid with high pressure, high volume, ultra deep being the cap of the pyramid, I think the MWCC approach is for a more comprehensive approach to all wells. Where our approach is based on what is available today, and what can we do now, and then to build on that capability over time. Having said that, our system is based on existing assets, the Q4000 and the HP 1, which are currently in service, and therefore a low cost of option for the producers. They are available, they are proven.

Essentially the way the two systems work is identical. You basically have a capping stack that is capable of closing in a well, assuming that your casing integrity will allow that, and then you further if the casing integrity won't allow that, then you have the ability to flow it back to the surface. The difference is just in the assets deployed to do that.

Okay. So, basically, if there is a blowout, would you guys be competing with their system for work or --?

I don't see us competing at all with the MWCC. The industry needs redundancy, it needs capacity, it needs reliability. And to the extent that ours is, by its name, Helix Fast Response System, ours maybe a little simpler but faster to mobilize, whereas theirs is more comprehensive. So, I think the two complement each other rather than compete.

Okay, and then next question, have you guys had any -- with the price of oil doing what it has been doing lately, are you seeing any more interest in your operations in the Gulf, or just in general, is any more activity?

I'll just answer it by saying, we think that the environment will be getting better in terms of being conducive for ultimate disposition of our oil and gas business.

And what plan -- what do you plan to do with the cash if you were to sell it?

Pay down debt.

Okay. Good answer. Thanks so much.

Thank you.

Thank you. Michael Marino from Stephens, Inc. Please proceed with your question.

Good morning, again. Real quickly on the CapEx side, what is the estimated dry hole cost for Kathleen and Wang, net to Helix.

Estimated dry hole cost, Johnny, about 60?

That's the gross.

Well, yes, that's net to us from both wells. But we are in the process of selling down some of that interest. We are trying to minimize that -- the dry hole costs we are only at -- we've sold down at 2-for-1 on Kathleen. So we got 30% of that $40 million is $12 million a dry hole On the Wang, that is about [$30 million]. So, it's maybe in the $40 million range total of dry hole, but these are not typically just exploratory, even though we categorize them. They are in-field wells in both the Bushwood field and the Phoenix field.I wouldn't look at them as typical in exploratory nature.

I might add also in the CapEx forecast that we have given, we have assumed the dry hole cost for complete interest in the wells. Yet like as Johnny said, our intention is to sell that down, so that should make capital available for other things, or less capital for the year.

Okay. As a follow-up to that, maybe this is for Lloyd, but on your budget, what do you estimate cash taxes are in 2011?

It's pretty low, Michael. Our cash tax will be pretty low in 2011.

Any more color -- I'm just trying to work towards that free cash flow number, that's all.

I will just say this because I think we are going to get asked on my prior comment that we expect to generate a fair amount of free cash flow. I think the way that number is looking now, we should generate more or less $100 million of free cash flow in 2011, which would be inclusive of any cash taxes we pay.

Okay. Sounds good. Thank you.

Thank you. (Operator Instructions) And there are no further questions at this time. I will now turn the conference back over to our host to continue with the presentation or closing remarks.

Okay, well, thanks, everyone for joining us today. We very much appreciate your interest and participation, and look forward to having you participate on our Q1 call in a couple of months.

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