Helix Energy Solutions Group Inc (HLX) 2004 Q1 法說會逐字稿

[Operator Instructions] I would like to introduce your host for today's conference, Mr. Jim Nelson. Mr. Nelson, you may begin.

Thank you. Thanks, everyone, for listening in. With us today is our A team, I guess -- Owen Kratz, our Chairman and CEO, Martin Ferron, our President and COO, Wade Pursell, our CFO, and Jim Connor, our General Counsel. The material that we'll be going through is the typical format that we follow. Hopefully all of you have had the opportunity to access, first of all, the press release, which has attached to it the summary financial statement for the first quarter. Then there's also a two-page shareholder report that is on our website, and we've also filed that and it's been Edgarized, as a form 8-K, so hopefully everyone has that. We will walk through that shareholder letter today.

I think as most of you-- some of you are aware, this will be my 28th and last opportunity to do a conference call with you. I want to thank Owen, Martin, and the ERT guys for sending me out on such a high note.

Before we get to a review of the quarter, we will all stand to do our national anthem. Jim Connor?

Good morning. As noted in our press release and associated report, certain statements therein, in and in our discussion today, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. For a complete discussion of risk factors, we direct your attention to our press release and to our annual report on form 10-K for the year ended December 31st, 2003, filed with the Securities and Exchange Commission.

Thanks, Jim. Why don't we get into the first quarter report? Our net income of $13.65m was 11% of revenues. That compares well to some of the early cycle service companies, as well as mid to small size E&P companies. And I guess the bottom line for that is that our model works, and Owen will talk a little bit more about that when we get toward the end. Specifically this quarter, it was an all-time record for the first quarter. The first quarter in the contracting business is typically a difficult one, as weather limits activity in both of our major markets.

Our record earnings flowed from two significant events. First of all, we achieved 10 BCF in oil and gas production, 85% of it came from our properties on the shelf, 15% from the three natural gas wells that are on line at Gunnison. And I'll go through each of those in the oil and gas section.

The second key event was that our two-- the two vessels dedicated to well operations, the Seawell and the Q4000, have excellent utilization of 82%, and in fact, when you add in the other two large vessels, the Intrepid and the Eclipse, that we've put in service in 2002, along with the Seawell and the Q4000, the average utilization of those four large vessels was 87%, quite an accomplishment in this market.

Finally, in terms of milestones, three of our vessels worked on commissioning the Marco Polo Tension Leg Platform - the Intrepid, the Northern Canyon, and the [Echo John].

Just a couple of comments on the financial highlights. Revenues increased almost $32m, or 36%. Roughly 2/3 of that are in the oil and gas operations. That in turns reflects a 26% increase in production and a 7% increase in prices. The balance, essentially, is due to improved revenues from the two well operations vessels. Margins of 26% were the highest of any quarter since 2001, four points better than the year-ago period, and most of that improvement relative to Q1 a year ago is in our contracting business. SG&A of $11.2m was up a bit from last year, but at 9% of revenues, it's right in line with our guidance for the year.

Our tax rate was only 26%, 26.5% in the first quarter. That's in relation to the 36% that we had in our guidance, and that, of course, reflects the completion of an Internal Revenue Service review of the years 2001 and 2002, and they're signing off on the method in which we have treated costs associated with the construction of the Q4000. There seems to be some differences, as I've looked at some of the analyst reports, in terms of calculating the impact. Of that 36 cents of earnings, 3 cents related to the tax situation. Wade, why don't you just go through where the 3 cents comes from?

Sure. Yeah, you might recall, as Jim said, the IRS was auditing our 2001 return. They ended up including the '02 return also-- [other than] just a quick summary of the audit. Other than the Q4000 R&D, no adjustments were proposed. We did end up settling the R&D credit. As, for background, you may recall, due to the innovative design and the concept of the Q4000 and the associated risk we took, we claimed R&D credits for those costs. The way the taxes work, there's two components of the R&D. One is simply timing difference deductions, which we take immediately and it doesn't impact earnings, it's just a timing difference. And then also there's a 6.25% credit, permanent credit, on top of that. We filed the tax returns, claiming the timing differences, resulting in no cash taxes for the last several years, and we never benefited the books for the permanent credit. Our policy was to wait until the IRS signed off on that treatment. The IRS, in the audit, disputed the claims, as we expected, and at the end of the day, we settled for $1.6m of permanent credit, which is included in the provision this quarter, partially offset by interest expense for certain disallowed timing differences on the R&D credit timing differences.

So the final result is very positive, in that all of our tax issues were cleared through 2002, we ended up effectively paying no taxes since 1997, as a result of all of this, and we had a permanent credit hitting the first quarter, adding 3 cents of earnings. And at the end of the day, we still have $25m NOL remaining, to be utilized this year, so just to reconcile the number real quick for you, the $1.6m that I mentioned is credited in the provision, and that-- you could do that math. That's simply taking our 35% statutory rate, applying it to the $19m, and then the difference between that and the $5m is $1.6m. And then offset against that, interest and fees associated with this, totaling a net amount, net of tax, of $540,000, and you end up with $1.1m, which is 3 cents of earnings.

OK, so, 33 cents related to a very favorable settlement, related to how we treated the Q4000. With that, let's move to the operational highlights. Let's start with Marine Contracting.

I've put in a table on utilization and just a comment about that, and then Martin will go through the specifics. As you know, we have nine dynamically positioned vessels. Two of them are in Wells Ops, the other seven are in deepwater construction. Of those seven, two are principally deployed to robotics support, the Merlin and the Northern Canyon. All seven of those are in deep construction. What you see in robotics is simply the utilization of the ROV systems themselves.

So Martin, with that, Martin's going to go through the first quarter and then he'll move into the second quarter, and what he'll be doing, many of you may recall that when we gave our guidance for the year, we listed key variables, and Martin is going to talk, essentially, how contracting performed relative to those variables -- Q1 and what it looks like, going forward.

Yes, thanks, Jim. You know, as we talked about last time, there were six variables that have the most impact on our earnings in the Marine Contracting segment. I'll just quickly comment on the bearing each variable has on quarter one results versus our expectations, and then the outlook for quarter two.

The first variable is market demand, as measured by utilization and rates. Here deepwater demand was better than expected, and it was particularly pleasing to keep both the Q4000 and the Intrepid almost fully utilized. The Intrepid has now established a good position in the small diameter pipeline niche, which is leading to improving rates. While the Q4000 demonstrated both the versatility and mobility by undertaking a heavy lifting job in the Dutch sector of the North Sea. Second quarter will again see good utilization for the Intrepid, but demand for the Q4000 and the Uncle John is [inaudible] for the next couple of months.

Demand in the shallow water, Gulf of Mexico market was very soft in quarter one, and as anticipated, we terminated the alliance agreement with Horizon Offshore.

Demand conditions remain similarly slow in April, and it's too early to tell whether the seasonal rebound will be as strong, as usual, and as expected. Well Ops demand was pretty much as we expected, and much better than last year. We achieved 66 days of utilization for the Seawell versus only 27 last year in the first quarter. The outlook is as planned, with the Seawell likely to be fully utilized in quarter two.

Second variable was project performance, and across the board, we did a good job of risk mitigation, and therefore made or bettered our [inaudible] expectations. Also of note was that we-- sorry, that quarter one saw the first fruit of our direct cost reduction initiatives.

Third variable is geographic fleet disposition. During the quarter, we had the Eclipse in the Asia Pacific region, and demand there is shaping up better than we expected for the balance of the year. On the flip side, we had the Mystic Viking in Trinidad for January and February, but demand there for the rest of the year is likely to disappoint us.

Vessel down time is the fourth variable, and here the Cal Diver I left right on time and on budget. We experienced worse-than-usual unexpected weather down time in the Gulf of Mexico, and we had a minor engine fire on the Eclipse, which will cause around 30 days of down time, with 20 days of that occurring at the start of quarter two.

Fifth variable is the strength of the ROV markets and in particular the result of our efforts to develop the market for deepwater pipe burial services in the Gulf of Mexico. This is working out quicker or better than we expected, and we had completed two important projects for a major operator with the Northern Canyon and a [T 750 Spread], and we see good follow on opportunities for that later in the year. In comparison, in quarter one last year, the Northern Canyon was just conducting supply board operations in the North Sea.

Finally, the sixth variable was the strength of the Wells Ops market in the North Sea. As I mentioned earlier, the Seawell had a good quarter one, is likely to have a good quarter two, but more importantly, we secured Norwegian sector work for [Stilo] for the first time in many years. This will allow up to 80 days of utilization in the second half of the year, and help us firm rates for other work in the British sector.

Thank you, Martin. I'll quickly run through the oil and gas production side of the business. Of the production of a little over 10 BCF, you can see the breakdown -- 8.5 is on the shelf, 1.5 from Gunnison. Looking first at the shelf, that 8.5 BCF equivalent of production is up from 6.8 in the same quarter a year ago and 6.9 is what we had in the fourth quarter. That increase is a function principally of our second successful PUD development at High Island, 544. It's 100% owned field that we acquired in one of the 2002 acquisitions. No reserves were assigned to the field. Our ERT people bought the seismic, worked the seismic, and spotted a good target, brought in a rig, and completed that PUD, or Proven Undeveloped Reserve Development, late in December. So we had roughly 800 million cubic feet coming from that field alone.

We also, as you know, did over 30 million of well work in 2003. That was the success in three fields -- Vermillion 200, High Island 557, and South Marsh 130 produced, basically, their remainder of the quarter over quarter improvement. Particularly encouraging was the work at South Marsh Island 130. That is, you know, is the large oil field that we acquired in 2002. But with the well work that we have done at that field, we had almost 500 million cubic feet of natural gas production in the first quarter versus 75 million in the same quarter a year ago.

We have, again, authorized anywhere from 25 million to 30 million of well work in 2004. We, in the first quarter, continued work, particularly, at South Marsh Island 130.

Our goal, again, on the shelf is to match last year's production of 28 BCF. In other words, I wouldn't annualize that first quarter, given the decline curve of the mature production.

If you look at Gunnison, as you know, the three subsea natural gas wells were brought online in December last year. Production was slowed slightly, as we brought online the first oil well in March. We also brought on the second oil well in April, which is right on schedule, and a third is scheduled for May. We then work at the [Spar]. They've got a rig on the Spar. They'll set risers and then the remaining four oil wells will come on line. I think the schedule is August, September, October, November, so by the end of the year, we should have all ten wells online. To date, we've got five of those ten producing.

When you look at the first quarter production, when you add the Gunnison natural gas production together with the well work, which was mostly natural gas, 67% of our product in the first quarter was natural gas versus 58% in the year-ago quarter.

I think with that, we'll- Wade, why don't you talk about hedges here?

Sure.

If you would, and then we'll go to Martin with production facilities.

Yeah, the hedges we have in place for the remainder of the year -- on the gas side, for the second quarter, we have a costless collar with a floor of $5 and a ceiling of $6.60, and that collar makes-- that hedge makes up about 35% of our non-Gunnison gas. We've still not hedged any of the Gunnison oil or gas, so if you just look at our total production for the second quarter, that comes out to about 25% of the total production, gas production. For the remainder of the year, the second half of the year, we have about 30% of the non-Gunnison gas hedged and a couple of costless collars, averaging a floor of $5 and a ceiling of $7.39.

On the oil side, we have for the remainder of the year, the remaining nine months, various swaps, making up about 43% of our non-Gunnison oil, and the average of those is $27.78. If you add in the Gunnison oil, it's-- the total hedged volume is less than 30%.

OK, just to run through the key variables in oil and gas, and you know our guidance for the year is production of 38 to 44 BCF equivalent, a price deck of $27 for oil and $4.75 for gas, so obviously the production rate and commodity prices are better than we estimated. Our production efficiency is reflected in the margins of a little over 50%. We've talked about the Gunnison rate and reserve additions and hedging impact. The well exploitation program is underway. The DD&A rate is a little bit higher -- well, it's up to 32% and part of that is driven by Gunnison, at 36%.

Well, that's what we wanted to cover on oil and gas. Martin, why don't you step in with our newest segment, production facilities?

Right. On production facilities, first quarter saw the mechanical completion of the Marco Polo platform. That occurred in early March, and we received the first demand payment from Anadarko in early April. Production is still expected to commence in the late June to early July timeframe. Also in the quarter, we signed a binding memorandum of understanding to bring the K2 field production across the platform. If you add that to the already committed production from [Green County 518], that puts us in pretty good shape in terms of using our oil capacity on the platform. Both those fields, that is, K2 and 518, are likely to be developed early next year, with production certainly starting by mid next year.

With oil capacity being pretty much committed, we're turning our attention to gas, and we're in discussions with several operators about providing incremental pipeline infrastructure, and to process their production. Again, in the next year timeframe.

While we're on that, you and I talked about the upstream article, dealing with- [Atwater Valley]. I did get some questions.

Yeah, the Atwater Valley hub is obviously causing a lot of discussion in the marketplace, and we're dealing with six different operators. We've been doing a [feas] study now for several months and we're pretty much coming to the end of that. You know, as far as we're concerned, it's still a good opportunity for us. We're obviously looking at numbers now and negotiating things, so you know, hopefully we can turn that into a deal. It’s still our position.

OK. Wade, why don't you finish with whatever other financial things you wanted to cover, and then we can go to Owen.

Sure. Just to run through the debt real quick, we did-- we were able to reduce our total debt from $223m at year-end to $204m at the end of the first quarter. That's through nearly $40m of cash flow from operations, offset by $21m of CapEx. That level equates to 33% debt to boot cap and 1.38 debt to trailing EBITDA.

Walking through the components, as usual, the [Mirant] debt made up most of the debt, at $138m. We're still paying less than 1.5% on that debt. The revolver was reduced to $16m, and I believe we were paying about 2.7% on that, floating. The Gunnison term loan was down to $33m. That has now begun amortizing, paying about 3.5% on that. And then the rest of the debt is capital leases, most of which is the $12m facility for the [tranche] on one of the ROVs, and that's a fixed rate of 3.29%.

You might have noticed the- on the revolver, we did get it down to $16m at March 31st and by the end of April, we're actually out of it -- we paid it down to zero. That's a $70m facility which expires February of 2005. That's why we classified it as current. That's an ABL facility, led by Fleet Capital, with Whitney and Southwest Bank participating. We're currently negotiating a larger, non-ABL type facility with various potential banks, which we expect to have in place later this year.

I mentioned the $21m of CapEx for the quarter; we're still on target to do $77m of CapEx for the year and if you're interested, the break out is $25m in the second quarter, $19m in the third quarter, and then $12m in the fourth quarter.

Anything else?

That's it for me.

All right. We're turning it over to Owen. Heads up out there; he's got hand-written notes.

That's always bad. I realized that there was a lot of detail there, so I thought I'd just take the opportunity to put it in the context of going over our model and perhaps simplifying the model again, in review, especially for any new investors listening. I'd also like to thank all these long-standing shareholders that have had faith in us. I think we're starting to see the fruits of the capital investment development of the model and over the next year or two, we should see the model fully mature and start to show its potential.

In essence, Cal Dive has three business groups -- Subsea Construction, Production, and Facilities. In Subsea Construction, we participate on the shelf, in the Gulf of Mexico, and inspection, repair, and maintenance work and abandonment. In the deeper water, in the Gulf of Mexico, Southeast Asia, and the UK, we participate in development construction and we are the leading contractor in well operations, which-- in the Gulf of Mexico and the North Sea, offering non-rig solutions, which is the [inaudible] field services on the subsea wells.

Now subsea construction historically and especially in recent times has been exposed to cyclically-driven risks of utilization, pricing, and contract liability. It was to address these risks that our model was initiated. To reduce our exposure, we take equity positions in production and facilities when, first, the economics of the equity position is compelling in its own right, and second, when there exists corresponding asset utilization.

On the production side, we will acquire mature properties, using the abandonment liability as currency for the acquisition. We also will acquire or partner in proven and undeveloped reserves that are either non-core, stranded, or capital constraints associated with them. We do take exploration at all.

On the facilities side, we will procure, fabricate, and own production facilities, provide them to the producers on a lease-tariff basis. With the base utilization derived from the equity positions in these business units, we're then able to better resist the common practice of sacrificing price and especially taking the contract risk that is often done in an effort to avoid the idle asset costs in construction. Now this doesn't mean that our construction activities are not depressed right now, but it does mean that the downside exposure is greatly minimized. We currently have a lot of leverage to any upside in the construction market.

Additional benefits of this model are, number one, we participate in a broader range of the cycle. Construction typically follows, but rarely coincides, with the high commodity pricing. When construction does rebound, it usually signals that we're entering an active production/acquisition phase. In other words, we're able to prosper through the full cycle.

Second, this has the effect of smoothing earnings, or at least reducing volatility, which in turn provides greater visibility of cash flow. And that allows for better management of capital allocation.

Third point is that it allows us to bring-- reduce costs of development and abandonment solutions. Production life is extended. Risk allocation is largely resolved, because we're sharing in the reservoir value. Large producers have a place to divest marginal properties, smaller producers have a value-adding partner. And of course, the whole things provides utilization to our asset base.

I've been real heartened to watch the results of [Tetra] over the years, as they've adopted a similar model, and in listening to Superior Energy's conference call, and the recognition of the value-added that [inaudible] resources has brought to their contracting abilities.

The present point in the cycle, where we are right now, we've seen a prolonged period of elevated commodity pricing. Many comments from other contractors that I've listened to on the calls are forecasting a pick-up in the construction and service cycle as a natural result. Our view is that, you know, while this might be true, a great deal of capacity has yet to be absorbed. Utilization may improve, but I think significant pricing leverage will take some time. Contract [risks] may also improve but unfortunately that's sort of dependent upon contractors walking the talk, as it were, and demonstrating rational constructing behavior in the face of difficult utilization.

We believe the construction outlet-- outlook is improving but fairly gradually. More significantly, though, we see perhaps a beginning of a period of increased equity plays in providing facilities and PUD production, which turned from mature property acquisitions further along in the cycle.

With this outlook, the upside in the construction market is ours to enjoy but one that we don't have to count on in order to see continued growth.

We've just finished an aggressive capital spending period and we're starting to see the fruits now. We've now paid down and are out of our revolver and we'll continue to pay down total debt, but the high quality of our sort of limits how much it's prudent to pay down. Our strong cash flow visibility positions us well to take advantage of upcoming opportunities in the improving market.

I've just returned from the North Sea, where we just incorporated ERT UK. We studied the market for about a year, and I'm pretty excited about the prospects for franchising our model in the North Sea, which complements and enhances our existing presence there, that we've had for the last two years with robotics and well operations. We've begun to market an integrated contracting approach for Step Out Development that we've called SOS -- Step Out Solutions. With that capability, our Wells Ops group and our production equity capability, the reception's been pretty encouraging. In fact, we'll be partnering with several other contractors in the North Sea to bring a broader range of value-adding capability to the producers as well as being able to combine our balance sheet strength to take equity positions. I believe we can really bring a valuable and timely service to the North Sea at this point in its maturity.

Now, Martin mentioned some of the significant variables to our budget. I'd just like to say that collectively, the overall impact is on the very positive side to our budget assumptions. The range on earnings that we provided at the beginning of the year was a risk-weighted range, surrounding our budget assumptions. The positives of the first quarter should be taken in context, though, as still having three quarters to go, but it sure is a nice way to start. We won't be changing the range, but we'll continue to guide as to where each quarter finds it, relative to our budget assumptions. And keep in mind that the budget assumptions had something like 60% or 70% of earnings coming in the second half. These are the big quarters, but this strong start certainly improves our chances of demonstrating the earnings that we were predicting.

I guess I'd like to just close by saying a couple of things. This model is here to stay. It's been one that's been sort of difficult for some to understand, but it is spreading among contractors. It's not an E&P model and it's driven by four realities. One, smaller and smaller reservoirs are being discovered, that need a more cost-effective approach. Two, there's more and more mature reservoirs every day needing extended life and lower minimum costs. Three, there's going to be more and more subsea developments, due to their cost-effectiveness. And I've often said that out of the small deepwater reservoirs don't know how much water is over them. They need a different approach. And then four, the widespread problem of proper risk-sharing for contracting work. This is one that our sector has been struggling with. If you think about it, this model aligns interests and allocates the risk to the reservoir value that's benn shared. It's just very equitable.

Our fleet is right-sized for the projected utilization ahead. Our capabilities are substantial. Our challenge right now is to become a deal-making factory, and repeat the success that we're starting to demonstrate. And our people are the best. We have the corporate culture that is certainly up to the challenge.

And with that, I'll turn it over.

OK, we're ready for questions.

[Operator Instructions] Our first question is from Bill Herbert of Simmons Company. Your line is open.

Good morning, guys.

Good morning, Bill.

So we opened the box here for Atwater Valley and you know, I think, you know, just my reading of the press and sort of discussions with industry sources, big opportunity, certainly in terms of dollars, and I-- I'd like to try and put some numbers around it, just a little bit.

First of all, how much is this, I guess, production facility going to cost, and what will be your split and what will be your equity commitment, just round numbers?

I think we're going to pass on that, Bill. Our primary for 2004 is to find another production facility type of deal, and that's one we're working on.

OK. And in addition to Atwater Valley, do we have others which are imminent, or are they sort of more long-shot possibilities?

Bill, hi, it's Martin. We are working on several other ones. I could see, you know, another potential deal happening in 2004, and some others certainly happening in 2005.

OK. Secondly, or thirdly, ERT production from the shelf -- you guys were candid enough in sort of saying the challenges associated with sustaining current production levels. You guys have updated guidance for Q2 through Q4?

In terms of production?

Yeah.

No.

OK. The-- [Mirant] debt - weighed any thought towards fixing that, from floating?

Well, we-- I look at it all the time, Bill. We're still paying less than 1.5%. You might remember that such a spread between the floating rate on that debt versus the long-term. We would be over 6% on a long-term, fixed basis right now. But it's something we're watching and at some point, you know, we'll probably put a tranche in, but I don't think it's any time real soon.

We've got what, another eight years?

Yeah, they've given us a total of ten years to float without being required to fix.

Gotcha. Hey Jim, 27 conference calls. That's a long time.

28, 28, I misspoke.

Congratulations. I think it would take too long for me to extol your many virtues, but I think the one that's most impressive is that of those 28 calls, did you ever start a conference call on time?

You've been waiting a long time to say that.

A long time, Jim.

Thanks, Bill. Next question.

Our next question is from Roger Reed from Natexis Bleichroeder Your line is open.

I won't make any comments about whether we started on time or not here. Good morning, guys.

Good morning, Roger.

Looking at the North Sea in terms of the Seawell and the well work over-- work there, what do you see in terms of-- you've got decent backlog with the Stat Oil deal, but in terms of pricing, this a market that has underperformed, not surprisingly, over the last year and a half. But what do you see there in terms of pricing?

Well, our pricing for Seawell, I think as you know, Roger, obviously depends on demand for the Seawell but also rig rates. So we are seeing some firming of rig rates, but it's not a big increase yet. But I think it's important that we've got this Stat Oil work, 80 days of utilization, so that allows us to increase rates for any smaller jobs that certainly happen in the summer months. So I think with rig rates going up, the Stat Oil work, we will see better pricing than we enjoyed last year.

OK. And as to the start of ERT in the North Sea, can you give us an idea of how-- I mean, OK, you're incorporated, but really, what's sort of the nearest term that something could actually happen there, where you'd be in a position to, you know, put your capital to work and actually take over production of a field, potentially.

Well, I just got back from the North Sea there, and I'm planning to go back over, I think, in a couple of weeks, and I plan on staying there until we have a deal.

Yeah, that's a good answer.

OK, well, if you're doing this in November, I'd feel that it was pretty soon, but you know, you're going over for the summer, it could take a while, right?

I-- I was very encouraged by the response that we got over there. I thought- well, here I'm going out on a limb again. But I feel confident. I think it's the right model and I think the North Sea is very open and receptive to it right now. The conversations that I've had over there indicates that there's a number of people to talk to. It's just a matter of finding the one with the right economics.

OK, that's it for me. Thanks, guys.

Thanks, Roger.

Jim Rollyson of Raymond James, your line is open.

Good morning, guys.

Hey, Jim.

You talked about the hedges on ERT production and not Gunnison production, and I think your guidance for the year was, what, 12 to 15, Bs total, from Gunnison. Is that still on target there?

Yep.

And then you didn't hedge, or still haven't hedged, any Gunnison production. What's your kind of outlook for hedges there, or do you plan on hedging anything?

I think at some point we will, Jim. We're getting comfortable with the rates.

Well, that's the key -- we have to get comfortable with the rates.

With it ramping throughout the year, we're just not to a point where we're comfortable with the rates to hedge enough. I mean, there's a lot of risk involved for us entering into those hedges with respect to deliverability.

Right. If you look at the second quarter, you mentioned kind of in your commentary about the, you know, a little bit softer start. Just seasonally, you obviously don't have the work from Marco Polo. What's your general take on overall, you've got some visibility in some areas, but you know- in subsea or Marine Contracting. What's your general thought on Q2 levels versus where you were, say, in Q1 with what you see today?

I would say, you know, pretty much the same, as Q2, as Q1.

OK, and then margin-wise, your margins were off a little bit from where they were in, say, Q4. Is that a function of just trying to keep some assets utilized, or what is the general thought there?

Yeah, it's just keeping some assets utilized in the bad weather months.

Right.

And we've taken weather risk, too, which sometimes hurts us, so you know, with better weather, we should see those margins improve from the second quarter.

In the shelf, it should--

Yeah, it should get back to work, so hopefully sometime soon.

Perfect. And just lastly, Jim, on the DD&A rate for Gunnison, you mentioned 36%. Is that going to be pretty much the standard rate, going forward for this year, or should we expect levels kind of like what we saw in the first quarter, in terms of overall percentage, and then ramping up as Gunnison production ramps up?

Yeah. Wade is shaking his head.

Yes.

Perfect. Thank you, guys. Congratulations, Jim.

Thank you.

Can I jump in here?

Yeah.

Give it a little more substance than a flippant response to the North Sea production question. In the North Sea, the deals are a lot more laborious to close than they are in the Gulf. We have learned that over the years, so it is going to take a while to close one. I should point out that the budget assumptions, we had no acquisitions in the budget, although we stated the goal was to do one PUD acquisition and I believe that we can at least sign that up this year, but probably not impact the budget until next year.

OK, we're ready for the next question.

Thank you. Our next question is from Will Foley of Sidoti & Company. Your line is open.

Good morning.

Hey, Will.

On Marine Contracting, I just missed the end of the last question. Did you guys say that second quarter margins, Marine Contracting, were perhaps in line with something similar to the first quarter?

Utilization -- but in the first quarter, margins were impacted because we take weather, so--

Yeah, slightly better, I think, is the answer.

OK. And I think you said on the last call that you anticipated about 70% of Marine Contracting revenue in the second half of the year. Is-- given that you probably started off a little bit better than anticipated, do you see it being a little bit more evenly split here, or do you still see the second half being quite a bit stronger?

We still see the second half being stronger, but obviously with a better start, our percentage split is going to decrease.

OK. And on the oil and gas production, again, you started off with a pretty strong run rate in the first quarter. I mean-- and I know you've indicated that it'll-- shelf production will likely be relatively flat with last year. Does-- is it likely that you're going to be towards the higher end of the guidance range that you've given on production, just given the good start you got here.

Well, you'll have to make your own assumptions there, Will.

All right. And that's all I had. Thank you very much.

Our next question is from Gary Russell of Stifel Nicolaus. Your line is open.

Gary? Gary, you're not there.

Mr. Russell, please check your mute feature.

Here I am.

Are you there, Gary?

Are you there?

Yes -- there, we've got you.

OK, thank you. Quick question -- well, a couple of questions. First, Marco Polo, given the other fields that you're taking a look at, is it possible to have that fully utilized by year-end '05?

For oil, yes, I would say it's possible. For gas, we still probably have got one or two more deals to do here in the next few months.

Possible.

OK. And then other than K2, are you looking at tying back just one other field or a few other fields?

Well, as I mentioned earlier, K2- we've also got Green County 518, which is a dedicated Anadarko field. So [inaudible] is predominantly oil, and they'll probably be producing by, certainly mid next year.

Is that-- the second one, is that K2 North?

Well, yeah, I guess it goes by K2 North as another name. But you know, we're talking to other operators about gas plays, because that's the capacity which we have available. I can certainly see us getting to a stage of doing one or two of those by the end of this year. It should be pretty quick to hook up, so they could be producing by the end of next year.

OK. Changing topics a little, I wanted to revisit the Marine Construction margins a little bit again. You know, revenues were much higher than I was looking for in the quarter and we still had the compressed margins, and you talked about several factors that contributed to that, with weather coming up several times. Was that-- was weather the biggest factor limiting the margins, despite the high revenues in the first quarter?

It certainly was. You know, I mentioned that, you know, weather was much worse than we'd expected and much worse than usual in the first quarter.

And on top of that, Gary, some of that work we took the weather risk, which is why-- one, it limits activity for all the vessels. And two, we were taking weather risk.

OK. And then lastly, I guess, did you comment at all about the schedule, going forward, for the Uncle John. How does that look?

Yeah, I did mention that, you know, the Uncle John has got sort of patchy schedule for the next couple of months. The demand for diving services is down from last year. But you know, we continue to do reasonably well with her, but we'd like to do better.

Yeah, with her cost basis and her capability, she'll work pretty well. What else, Gary?

That's it, other than one closing comment. Jim, congratulations. It's been an absolute pleasure working with you, since the IPO, and I've got just one question for Owen -- Owen, I hope you secured a non-compete.

Thank you, Gary. Next question.

Phillip Dodge of Stanford Group, your line is open.

Yes, thank you. Good morning, everybody.

Hey, Phil.

Good morning.

Just curious what kind of production profile at Gunnison is assumed in the 36% initial depreciation rate, and also whether developments at Dawson Deep could affect that depreciation rate at some point.

Obviously, with respect to Dawson, they would, if that well is ultimately determined to be commercial and brought on line. Wade, did you pick out the first question?

The range of our model this year -- I mean, that is what the 36%--

Did you get that, Phil?

Yes, but then what do you assume happens to the production after it reaches the peak rate, I guess, some time towards the end of the year.

The question, then, is we do 36%, say, this year, and by the end of the year, we have all ten wells on, what is the rate going to be next year, in '05?

That's a good question. I'll get back to you on that. It'll be a little--

It'll be definitely down.

It will definitely be lower.

OK, it's good to hear. Thanks.

[Operator Instructions] There are no further questions at this time.

All right, thanks one and all. Next quarterly conference call, I'll be on your side of the table, listening in. And I hope you guys do well. Thanks, everybody.