SilverBow Resources Inc (SBOW) 2006 Q1 法說會逐字稿

At this time I would like to welcome everyone to Swift Energy's first quarter earnings conference call. (OPERATOR INSTRUCTIONS). It is now my pleasure to turn the floor over to your host, Scott Espenshade. Sir, you may begin your conference.

Good morning everyone. I am Scott Espenshade, Director of Corporate Development and Investor Relations. I would like to welcome everyone to Swift Energy's first quarter 2006 earnings conference call. Terry Swift, CEO, will provide an overview. Alton Heckaman, Executive Vice President and CFO, will review the financial results for the first quarter. Joe D'Amico, Executive Vice President and COO, will cover our recent domestic activity. And then Bruce Vincent, President, will update our New Zealand operations. Terry Swift will then summarize before we open up to questions.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on or current assumptions, estimates and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports. And our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes, and then allow additional time for questions.

With that I would like to turn it over to Terry.

And thank you again for joining this morning's conference call. Swift Energy Company has regained its prehurricane operating momentum, which we had established in August of last year. At the same time, we find ourselves in a high-priced oil commodity environment. Given these fundamentals, our net income has increased 45% to $37.3 million for the first quarter of 2006. We also have a 41% increase in cash flow to $91.6 million for the first quarter of 2006.

Equally important, our production was up 7% to a record 16.6 Bcf equivalent for the quarter. We have made tremendous progress over the past two quarters to restore operations to normal. Our people have done a fantastic job meeting the challenge. In fact, I would like to say that the true value of Swift Energy Company is with the people at Swift Energy Company. And we're proud to report that based on their efforts we have -- our total production from South Louisiana fields that were affected by the hurricanes is actually above last August levels.

Lastly, our 2006 drilling program is underway, and should provide Swift Energy Company with some of the best reserve targets in the history of our Company. We believe that our 2006 plans will continue to deliver solid performance for our shareholders.

We started 2006 much the same way that we started 2005, a very robust emerging oil and gas pricing environment with high levels of volatility, a growing U.S. economy, and a situation where even the experts cannot agree on whether these current pricing levels are sustainable. Looking back to crude oil and natural gas prices as they were a year ago, we find that crude oil was about $50 a barrel, and natural gas was nearly the same as it is today at $6.75 per Mcf.

The significant difference between a year ago and today is the 12 month strip. Crude oil 12 month strip is up nearly 50% to about $75 a barrel. And natural gas strip is up about 25% to just over $9 per Mcf.

As we reviewed last year's quarter it strikes us that many of the factors affecting the commodity price environment were very similar to those of today. We have an extremely strong commodity market. But along with that comes some industry cost pressures. The U.S. economy remains strong, but the dollar -- the U.S. dollar is globally weak. Global energy demand remains strong, but global production growth, despite the high rig counts, may not actually materialize. We continue to have little marginal oil capacity, and the U.S. natural gas storage overhang is similar to where it was a year ago.

The one thing that has changed is the political concerns are much higher today than they were a year ago. And the concern of the upcoming hurricane season, of course, is much more focused than it was a year ago. At Swift Energy we are focused on the measures that we can control. Namely, we believe our costs will continue to increase, but we will endeavor to moderate these costs by good management. We have seen our operating costs rise about 30% on a per unit basis over the past year. But we have been able to maintain our gross margin at the same percentage levels, which of course has led to increased income.

We plan to grow our production and reserves at Swift Energy Company at approximately 14 to 18% on the production side, and 5 to 8% on the reserve side for 2006.

Swift Energy has just increased its 2006 CapEx budget to keep pace with the increasing service cost. We added an additional 25 to $50 million to our 2006 budget to account for these higher costs, particularly those resulting from day rate increases for drilling rigs. Because of the commodity pricing environment, we still expect excellent returns from this additional spending. And it is certainly well with our anticipated cash flow.

We continue to keep an amount for discretionary spending in the capital budget, which we will only spend with the realization of the commodity prices and our operational success. Swift Energy's planned activity level -- and we now anticipate our capital expenditures for 2006 to be in the range of 325 to 375 million, which is still within our anticipated or expected cash flows for the year, based on a $7.50 gas price and a $60 oil price.

We're continuing to deliver value through our current operations, and are always looking to add to or enhance our portfolio of opportunities and assets. This quarter we announced our entree into the onshore portion of the Cook Inlet in Alaska. This in itself is not significant in the near term, but it certainly is consistent with Swift Energy's strategy of focusing on areas where prolific producing basins exist that have been under-exploited, and where Swift can obtain a large acreage position at a relatively low cost.

We just recently spudded a well that is operated by our joint venture partner, Aurora Gas LLC. The well is a 9,200 foot test that has a shallow oil -- a shallow gas and a deeper oil target. We also recently sold our minority interest in the Brookeland gas processing plant, which is in East Texas, for approximately $20.3 million to a third party. We felt this was an exceptional opportunity to bring forward a future annual cash flow stream come, and focus the proceeds on our primary activity of exploration and development drilling, along with our strategic objectives in oil and gas acquisition opportunities.

Proper execution of our operating strategy in 2006 as planned should bring us another good year. Our operating set -- our opportunities set for reserves and production growth is the best in the Company's history. South Louisiana plans call for more wells, deeper wells, the use of the 3-D data set, and great effort that we believe is going to be very significant, not only for production, but for reserves growth, especially in Lake Washington, Bay de Chene and Cote Blanche Island of South Louisiana. We also continue to have impactful exploration activities that are underway in New Zealand.

With that introduction, I would like to ask Alton to present the first quarter of 2006 financial results.

Good morning everyone. I am very proud to report that Swift Energy had record earnings for the first quarter of 2006. Revenues were 136.2 million, up 42% over 1Q '05. As Terry said, net income set a Company record of 37.3 million, up 425%. And diluted EPS increased 40% to $1.24, while cash flow for working capital changes increased 35% per diluted share to $3.05. Production for 1Q '06 increased 7% to a record 16.6 Bcf equivalent, and increased 13% sequentially. Domestic production actually rose 16% for the '06 quarter when compared to '05.

Commodity prices stayed strong, paving the way for our great results. 64% of Swift's production for 1Q '06 was crude oil and NGLs, which in this current pricing environment is obviously quite favorable. With current weighting of crude oil and liquids, Swift's average composite realized price for 1Q '06 increased 32% to $8.14 per Mcf equivalent. Domestic composite prices averaged $9.25, up 32% for 1Q '05. And New Zealand composite prices rose 7% to $4.41, in spite of the strengthening during the quarter of the U.S. dollar versus the New Zealand dollar. All resulting in a 41% increase in oil and gas revenues over last year. These prices are great, but as Terry mentioned in his intro, it is all about the margins. And we never take our eye off the ball with respect to our focus on per unit cost and metrics.

As for the first quarter of 2006, G&A came in at $0.46 per unit, including the new stock option expensing, which was slightly above guidance. DD&A for unit came in at $2.13, slightly below guidance. Production cost came in at $0.87 below guidance. Production taxes increased in tandem with higher prices in the production mix, and interest expense came in at $0.35.

Swift Energy realized net income of 37.3 million, which is $1.28 basic and $1.24 diluted, meeting the FirstCall mean estimate for the 16th consecutive quarter. Cash flow before working capital changes, as I mentioned, came in at 91.6 million, or $3.05 per diluted share, while EBITDA was 99 million for the quarter, both well over the '05 comparable amount. CapEx for 1Q '06 was 78 million, well within our cash flow from operations, allowing us to increase our cash at quarter end to 55 million.

Our recently announced sale of our Brookeland plant, as Terry also mentioned in his intro, provided another 20 million of cash shortly after quarter end. Our bank line remains unused, providing plenty of available capital for any value-adding strategic opportunities that may avail themselves.

With respect to Swift Energy's hedging activity we have natural gas price floors in place through June of '06 production, with an average strike prices of $8. And we recently acquired crude oil price floors for the third quarter with a floor price of $65. The Company also has executed the sale of approximately 5 to 10% of its second quarter domestic crude oil production at an average NYMEX strike price of just under $70 per barrel. Please see our website for more extensive information. As always, we have included additional financial and operational information in our press release, including guidance for the second quarter and full year 2006.

2006 looks to be a great year for Swift Energy Company. We're off to a great start. And we are even more excited about the greater things we believe are in front of us. With that, I will turn it over to Joe D'Amico for an overview of our domestic operations.

Good morning everyone. Today I want to discuss first quarter 2006 domestic production, the facility upgrades at Lake Washington, and current sales status, and recent drilling results in our domestic core areas.

In the first quarter Swift Energy completed the facility upgrades in Lake Washington that were delayed due to the hurricanes. Production during April has averaged approximately 16,600 net barrels of oil equivalent per day. This is an approximate 2,000 barrels per day increase over the 2005 year-end exit rate. For 2006 we expect to exit the year with net production of 18,500 barrels of oil equivalent per day.

We are starting further capacity increases in Lake Washington. Alternatives include increased compression in the field for gas lift purposes, and the potential of a fourth platform on the western side of the field. Cote Blanche Island Field is undergoing its final repairs, and will begin production in the second quarter. This field was averaging approximately 375 barrels of oil equivalent per day of production in August of 2005, but is expected to quickly exceed that as it comes online with addition of recompletions and newly completed wells.

As for our domestic drilling results, Swift Energy drilled a total of 15 wells domestically and successfully completed 13 of these wells. In the Company's South Louisiana region, Swift successfully completed six to seven development wells, with four to five being completed in the Lake Washington area, and one each in Bay de Chene and Cote Blanche Island. The Company successfully completed six development wells targeting the Olmos Sand in its AWP area. And was unsuccessful on a very shallow exploration well targeting the government well sand in the same AWP Olmos area in McMullen County, Texas.

Swift Energy successfully drilled and completed a development well in South Bearhead Creek in Beauregard Parish, Louisiana. And it is waiting on a flowline to begin production. Swift currently has four barge drilling rigs operating. All are on long-term contract, with two located on (technical difficulty) field. A fifth barge rig is being considered in these field for later this fall.

At this time a drilling rig is operating in Swift Energy's AWP Olmos field in South Texas, with another rate operating in the Brookeland field in East Texas. As Terry mentioned, the Company's recently announced Endeavor Prospect onshore Alaska, a joint venture with Aurora Gas LLP, has been spudded. The Endeavor well serves as a commitment well for Swift Energy, and is planned (technical difficulty) 9,200 feet. It has a shallow natural gas target and a deeper oil target. Now I will turn you over to Bruce to talk about our New Zealand operation.

Good morning. I like to cover several things in New Zealand this morning, including our first quarter production, our first quarter drilling program, and our ongoing 2006 drilling plan.

To turn to production results, New Zealand produced 3.8 billion cubic feet equivalent in the first quarter of 2006, which was evenly split between the TAWN and Rimu/Kauri area. For the first quarter of 2006 New Zealand accounted for 23% of Swift Energy's total production. This is a 7% increase from the 3.7 billion cubic feet produced in the fourth quarter of 2005, but a 16% decrease from the same period in 2005.

Production in the Rimu/Kauri area averaged approximately 18 billion cubic feet equivalent per day in the first quarter. This was a decrease of 4% from the fourth quarter 2005, primarily resulting from natural declines in the Kauri Sand. Up at the TAWN field, production averaged over 24 million cubic feet equivalent per day in the first quarter, up 16% from the fourth quarter of 2005. This is predominately resulting from the Piakau North A-1 well, which was a new discovery last year, produced throughout the first quarter.

I also on to point out that our guidance for the second quarter production in New Zealand shows lower production, between 3.0 and 3.5 billion cubic feet equivalent for the quarter. This is primarily attributable to down time at the TAWN and Rimu plants because of annual plant maintenance, as well as the fewer crude oil liftings during the quarter. You may recall that we booked production sales when the liftings occur at the [Amadatam], and that is something that we're not in control of. And this quarter it appears we're going to have fewer liftings. And so those are the principal reasons for the lower guidance.

In regard to drilling results. During the first quarter the Company completed two of two development wells. One in the shallow Manutahi Sand and the Kauri-E11 well, both down the Rumu/Kauri area. And one of two exploration wells, the Trapper well up at TAWN was (technical difficulty) completed, and the [Tariki] well, which is the shallow Manutahi test, trying to look for another area down the Rumu/Kauri area that was deemed noncommercial.

Swift Energy New Zealand currently is evaluating the prospectivity of several intervals that were encountered in the Trapper exploration well, located in the area of [Tariki] field, and is drilling the Goss prospect what is located in the Waihapa field area. The Goss well is targeting several deep gas objectives, and is part of the exploration joint venture with Mighty River Power, as is the Trapper well.

The Goss well should be finished drilling in the second quarter. Both of these areas are located in the TAWN area, and if successful, the wells can be produced through the Swift [tone] infrastructure in this area.

In regard to our development activity, the Company was successful with two development wells in the Rumu/Kauri area. The first well, the Kauri-E11 well, targeted both the Kauri Sand and the Tariki Sand. And it has initially been completed in the Tariki Sand, which is the deeper [horizon], and it is currently undergoing production testing in this sand. We were also successful with one development well that did target the shallow Manutahi area, where we have been producing for some time.

Swift Energy currently has two drilling rigs operating in New Zealand, one on the Goss exploration well, and one rig targeting the Kauri Sand and the Rumu/Kauri area. Following the Goss well, Swift Energy plans to drill the [Cofi] prospect, which is up in Permit 38742, which is on the north side of the Taranaki Basin. This well will also target deeper perspective gas energy.

We also intend to have further exploitation of the Kauri and Manutahi sands of the Rumu/Kauri area this year, as well as evaluating additional potential in the Taranaki formation up in the TAWN area.

Swift Energy New Zealand's near term exploration focus, coupled with our development assets, gives us a very competitive drilling portfolio to deliver targeted growth over the next several years. In Swift Energy's ten years in New Zealand we have built a regional expertise in the Taranaki Basin, plus substantial infrastructure assets and acreage position, which we believe positions us for success. Swift Energy New Zealand continues to focus our assets [to aid] the projected New Zealand natural gas shortfall that becomes even more evident each year in this under-explored basin.

Thanks for your attention, and I'll turn it back to Terry for a recap.

Before we open it up to questions, I want to emphasize where Swift Energy's 2006 operational goals are focused. First is reserve growth. The Newport and Bondi discoveries from last year are very important to the Company. These are very important focus areas for our growth in 2006, along with our interpretation of the process 3-D in the greater Lake Washington and [Babacari] area, we are focused specifically on drilling deeper wells in Lake Washington and in the Bay de Chene areas, which give us a high level of confidence that we can accomplish our objectives. Second, is our 2006 production growth target, which is in the range of 14 to 18% growth. Third, is to manage our cost in this new environment of increasing costs.

To review some of Swift Energy Company's investment highlights thus far, I would like to focus first of all on the impressive financial results of the first quarter. We intend to continue delivering on our operational plan. In the first quarter of 2006 our revenues increased by over 40% to $136 million, Earnings increased about 45% to over $37 million. And cash flow increased about 41% to more than $90 million. These results all lead directly to increased shareholder value.

In the first quarter of 2006 we have record production of 16.6 Bcf for the quarter, a 7% increase. Swift is drilling deeper, higher impact prospects, especially in the Lake Washington area, and specifically around our Newport prospect, Newport discovery. We will also use this year to drill deeper in the Bay de Chene and Cote Blanche Island areas of South Louisiana. These deeper wells will continue to showcase the potential of our high-quality, 3-D based South Louisiana activity, as well as our impactful New Zealand exploration footprint.

Finally, we continue to have a strong and flexible financial position, which allows us to take advantage of future opportunities, whether they are growth -- organic growth in the drill bit, or through strategic growth through acquisitions.

At this time we would like to begin the question and answer portion of our presentation.

(OPERATOR INSTRUCTIONS). Rehan Rashid Friedman Billings Ramsey.

Just a quick -- maybe a little bit more details of the exploratory -- or success in the Lake Washington area. I'm sorry, CBI in your Bay de Chene prospect have we talked about. And also for the rest of the year if you could remind me how many deeper prospects are you guys going to drill in Lake Washington around that 14,000 feet range?

That is a great question, and I would hope to refer back to our analyst presentation that we had put forward earlier in the year. We clearly have a very significant inventory of 3-D based activities in the Lake Washington area. And to be a little bit more specific, we are doing both appraisal or delineation of the Newport discovery, which we announced at year end, a couple of zones that tested there at very significant rates for the Company. But we're also drilling deeper in that same area, testing some very new targets that we weren't able to get to last year. General depths involved could going as deep as 15, 16,000 feet in that area. Some of the targets are right on the flank of salt. And in some cases we're having to drill through small sections of salt. Some difficult drilling, but some very high impact prospects.

We stand behind our probable estimates in those areas that we gave at year end for those prospect sizes. It is still early in the testing and appraisal process to say exactly how big we are, but they are material in size.

We also have 3-D -- and when I say 3-D, what we're doing is we are essentially mapping complete subsurface control into the 3-D, and doing amplitude and ABO analysis around these targets as well. We have also have some significant prospects that are in the 14 to 16,000 foot range in the Bay de Chene area, where we have complete acreage control that we plan to get on this year. All in all, between Lake Washington, some appraisal work over at Bondi and into the Bay de Chene area, the higher impact activities should be somewhere between, I would say, 8 to 10 wells that we will drill.

We still have a lot of probable and possible reserves that we kind of classify in the exploitation area. We will drill somewhere between 35 and 45 wells that are more of -- I hate to use the word, plain vanilla, but they are very noncomplex wells. They drill down the salt face. We are using both subsurface and the 3-D there in Lake Washington and in Bay de Chene. And we believe we will be getting some nice reserve growth from some of those activities as well.

With regard to the Cote Blanche Island, most of the drilling activity there is development in nature. We did extensive mapping last year, and they are targeting a lot of those proved undeveloped reserves. However, on certain occasions we are taking some of those wells deeper to see if -- to really look toward what I want to tell you would be an exploration target, but you're doing it on the margin really with a development well.

And then sticking with those two, we are waiting for 3-D to come back so we can do more exploratory work sometime late this year, next year?

That's correct. You know, Bay de Chene had a 3-D on it that we were able to get and merge into our larger data set running from Bay de Chene, Territory Bay all the way over to Lake Washington, which are fully emerged, fully integrated and processed all on the same parameters. We're using the 3-D at Bay de Chene. That is a significantly larger component of exploration 3-D driven prospect.

Over at Cote Blanche Island, although there was impartial 3-D in the area, it was of poor quality. It really wasn't what we wanted to really work the [dome] with. So we're planning a 3-D shoot that is just about ready to kick off. I think permitting is 99% done. So that should be being shot over the next couple of months, processed, and we should have it by the end of the year. That will be a big driver in some of the exploration in '07 and '08.

Got it. And again, going back to Lake Washington, the Newport well, Terry you mentioned -- I guess they are still working on it -- the third well. Any in terms of timing -- what do we hope to -- should it be sometime during this quarter --?

Yes, the current well on Newport, which is the third one that we have drilled, we had announced the previous two discoveries. One about midyear last year and the other right at the end of the year. We expected that to be finished drilling this quarter. We really currently expect to immediately move the rig to another location in Newport, more than likely focusing down depth from the discovery we made at year end to try to see how far down the sands go.

And the start appraisal well wasn't too much farther down dip from the second location, I guess?

No, it wasn't. It was designed -- as you recall, that discovery -- the well that we announced at year end had two really big thick [sands] in it. But we did complete the one, and it is producing. And the well we are drilling right now was designed to penetrate at least one of those sands so that we could get another tap really in the sand that wasn't completed in the other well, and then test some of the deeper objectives.

Got it. Any progress in discussions with the state in terms of for letting you produce beyond the allowable?

We are working on some things that would allow us to produce beyond the allowable, but until we have all that worked out, it would be premature to say anything. But we are working on that.

Last question from me. On Lake Washington, it was mentioned that talking about adding another platform. Could we maybe talk about what size is being considered? And if so, by when should we have the production impact, I guess?

What we're doing, one of the things that we have found to be very successful for us when we were adding the facilities in the current Lake Washington area, was we got a barge and built essentially processing and compressing -- compression on the barge, and put it out in the [CN3] area. That allowed us to basically do all the work in the shipyard, rather than doing it offshore.

Today it is even more difficult to work in the waters, because you don't have the same infrastructure you used to have before the hurricanes. We have actually gone and acquired several barges. I think five in total, of which we planned in number of facilities. One of the things we're looking at right now is actually using one to put some compressors on to get some additional compression out in Lake Washington that could easily be moved to either Cote Blanche Island or Bay de Chene at a later date, if need be. And using one of the barges to plan for the fourth production platform in the Lake Washington area over at the western side. Initial thoughts -- we're still early in the the process -- initial thoughts would be to set it up -- initial designed for about 10,000 barrels a day of production fluid capacity.

Lovely. Great. And at analyst conference you guys had given guidance of capacity on the Lake Washington side being 28,000 barrels by year end this year. That takes into account the impact of compression and every other thing that is going on -- the minor tweakings that are going on?

It takes into account the compression and the number of the minor projects, but not the addition of the fourth platform.

Sure. But you. Thanks.

[Andrew Lubek] Citadel Investments.

It is actually [Neil Chagwaney] from Citadel. My question was twofold. Firstly, can you update us on your hedging policy? It sounds like you guys layered on some hedges this quarter. What should we expect going forward?

Yes. We can tell you that we basically apply a portfolio approach to our hedging. And typically it has been protecting against a precipitous decline in hydrocarbon pricing, where we layer in floors, both in crude oil and natural gas. Typically we try to buy into the strength and go as far out as we can, which limits us historically, because of some of the factors in the strip.

But as Terry said, the strip is getting stronger out there, so we have been able to go out at this point well into the second quarter and protect some gas and crude oil. And as we mentioned in both the press release and in our talk, we actually are able to forward sell some of our hydrocarbon as well. And we have done that with respect to about 5 to 10% of our crude oil for the second quarter of '06 at just under $70. We apply again a portfolio approach to try to capture the maximum that we can, but more importantly protecting against the downside, but keeping the entirety of the upside.

How much of your volumes would you be comfortable hedging? Because right it is still a small percentage, but could we see you hedge 30, 40% of your volumes? Or is that something that is not --?

We have done that in the past. Typically we target 20 to 50% would be the hedge, as far as we can go.

My follow-up question was on the increased CapEx number. Can you give us a little bit more detail in terms of the drivers for the higher CapEx, and what this means for the projected SMB for this year?

Yes, the principal driver for the increase, probably at least half of that range that we talked, probably the 20 to 30 million, is really resulting from higher cost that we are seeing, I would tell you, principally in the rig side of it. But there's a general overall cost inflation which we expect to happen. We had factored some of that into our budget for this year. But particularly on the rig side, that is where we are seeing a pretty dramatic increase in costs. So we felt it appropriate to up our budget to allow for that.

What does that do to projected SMB? I think you guys had some sort of a number I think in your 10-K, but I -- was that -- I'm assuming that that changes a little bit?

Yes. It could change slightly. The way we provide guidance is with ranges, both ranges in terms of production, ranges in terms of reserves, ranges in terms of costs. And so it kind of depends upon whether you're looking at high end or low end or something in that area. Obviously if all things being equal, and the only thing you did to capital costs, which is roughly 10% or so, you would slightly increase E&D.

Just one last question. The gas price realization in New Zealand was really good. Should we just expect that going forward?

The natural gas market in New Zealand is obviously substantially different than the U.S. It is driven by long-term contracts. All our gas is under contract, some of them longer term, some of them shorter term. We are seeing continued price improvement in the marketplace there, because of the looming shortage for natural gas. But it is also impacted by the exchange rate. The New Zealand dollar has actually softened in the last quarter slightly from the U.S. dollar. That can actually bring us down slightly, but we expect it to be pretty much where it is right now.

Thank you very much.

This is Terry. I would like to add another comment to that capital spending discussion. Again, I want to emphasize that we do maintain a discretionary wedge. And as to the commodity pricing environment, if we found anything adverse happening there, we would act accordingly. We are going to stay within our cash flow in terms of a realized sense, not an expected sense.

Thanks. Good quarter guys.

Van Levy of Dahlman Rose.

First, I would like to start with New Zealand just to make sure I understand. Gas was a little below expectations. Bruce, you talked about that being essentially timing issues. I just want to make sure that there is no issue with quality of the asset or the asset's ability to --.

Are you talking about gas price?

No, natural gas production.

In the first quarter?

Yes.

No, there is really no significant issue there.

So it is not like it was -- it was just timing that is on with bringing the facilities down, etc.?

In the first quarter our production was right within the range, actually slightly above the middle of the range of overall production. Now second quarter we are guiding production down. And that is a result primarily of the plant maintenance. We do it every year. We have done it in the second quarter virtually every year. This year at TAWN it is actually a little more extensive maintenance than normal. And obviously when your plant is shut down, you're not producing. And then it is also a function of the crude oil liftings at the (indiscernible), because production sales aren't actually booked until the crude oil liftings are actually done.

My next question is for -- to get back to Lake Washington. With the seismic and the new drilling that you have going now, in fact, you have a couple of years of quite a lot of data. Has the new seismic integrated with the drilling, does this allow you to maybe advance or book reserves a little faster than you previously would have thought?

Actually I don't think the seismic really in and of itself has much affect on the actual bookings. Clearly it helps us with the drill bit. Clearly it helps us do better mapping. All of our maps -- this relates to actual bookings -- are based on the subsurface data and how the seismic has helped us interpret the subsurface data. It is a fully integrated approach. I think rather than say the timing might be accelerated, I would tend to say the quality and confidence of our planning improves with the seismic.

And then again refresh me. At the end of the quarter where were we roughly in production at Lake Washington?

I think we've got the thirty-day average in the press release.

Joe gave the average. It was 16,600 barrels per day that was the average for April.

The facility is 28,000 availability by the end of '06. I guess your exit rate still is -- kind of targets to around 18,500 for Lake Washington?

Correct. Both of those numbers in terms of the April average and the year end rate of 18.5 is a net production number. In terms of the facility number, when we talk about that, that is really a gross production number. The best rough way to get the gross from a net number is divide it by 0.82.

Okay. Looking further out into '07, Bruce or Terry, could the exit rate in '07, should we be looking at 23, 24,000? Where is the upper limit that you see at this juncture? Could this field go to 30,000 barrels a day net? Where do you see the plateau?

This is Terry. It is a great question, and I think the best answer to that is we're not through with Lake Washington. We have clearly been able to move beyond many other people's expectations in the shallow and intermediate. We have eclipsed that 10,000 barrel a day target that many thought was unobtainable. And we clearly are pushing the 20,0000 barrel a day gross target that now we're very confident we can go beyond.

In terms of the deep potential, all I can do is give you a range. Clearly timing is important here. The deeper wells are -- typically the allowables are going to be around 1,000 to 1,400 barrels a day on those wells. But to the extent that we get maximum allowables and can get off of some of the restrictions there, we can say 3 to 4,000 barrel types of wells being drilled in this area. And so the upside I would simply say we haven't found yet. That is being very positive, but clearly that is what we believe.

And then last question. I know you're looking at a regional sort of view from in terms of seismic. Any other opportunities that this is setting up in terms of targets -- acquisition targets?

That is a great question. The answer is yes, but the specificity has to remain unannounced at this time.

The hope is that with your large regional seismic database your actual wells and data -- in this area you should have a better feel for possibly overlooked opportunities, I guess particularly between the salt dome areas and what is considered maybe the [subprime] areas?

That is absolutely correct. That is actually part of the strategy. That is exactly what we're looking for. And obviously with the success we have at Lake Washington, that allows as to recalibrate that seismic picture elsewhere in the merged data set. We believe we're seeing things that other people don't see. We process this data in a proprietary way. We have merged all of it together. And then we're putting the drill bit in a number of places. And we think that gives us a very clear competitive advantage. We are obviously excited about Lake Washington, Bay de Chene -- resulting from that, but we also see very significant other opportunities within that area.

Excellent. Okay, guys, thanks.

(OPERATOR INSTRUCTIONS). Adam Leight of Credit Suisse First Boston.

Very nice results. According to the guidance -- first a simpler question. I didn't catch what you said was -- if you said -- when you expect Cote Blanche Island to be back on.

You're cutting out on us.

I'm sorry. Did you say when you expect Cote Blanche Island to be back online?

Yes. During this quarter.

In the guidance, I had a couple of questions. One, it is probably simple, the New Zealand oil volumes for the quarter, are there lifting catch-ups in the second half? You are assuming that there will be short liftings in the second quarter. It looks like a big tick up in the second half.

Again, you are cutting out on us, so we're not hearing all your questions. (multiple speakers).

Sorry. How is this? Is this better? Second half production guidance for oil in New Zealand. Does that imply that you expect a greater number of liftings, or is there some significant new production coming online?

We actually expect fewer liftings in the second quarter, but as we --.

Second half.

(multiple speakers). There are a couple of things that we're doing. One, the Kauri-E11 well that we mentioned is undergoing production testing out of the Taranaki sand. As you may recall, that is really [balsam] oil reservoir. It does have a significant amount of gas production, but it is more oil. If that tests successfully that will provide some additional oil production.

Then the other planned activity that I mentioned earlier is we're going to evaluate additional potential in the Tikorangi formation. This is a fractured formation in the [Waihapa Nori] field. We believe there is still some additional potential here. Those are high rate wells -- high rate oil wells. And we're going to drill our first additional test on that, I guess, in the third quarter. But the rig that is currently drilling down in the Rimu/Kauri area, and the Kauri-E12 well -- after that is completed it is going to move up to test the Tikorangi. That is where that is coming from.

There is exploration success built into the second half assumptions.

Yes.

U.S. gas production you're cutting down for the quarter? Is there a significant reason for that versus first quarter?

No, there is no significant reason that I can think of off the top of my head.

Okay. And then on lifting costs U.S. You are being conservative for the second quarter. Is there something going into the cost assumption? And then it looks like again a big drop for the full year. Can you just explain -- walk me through that?

That is really just recognizing that there is a cost inflation going on out there. We think you're going to have some cost go up. Obviously for the full year -- we expect higher production levels in the full year, so it is the same cost. You're (inaudible) numbers are going to be small.

Okay. That's great. That's all I have.

Gentlemen, there appear to be no further questions.

I would like to thank everyone for joining Swift Energy on our first quarter earnings call. Thanks for joining the conference.

Thank you. This does conclude today's Swift Energy first quarter earnings conference call. You may now disconnect, and have a wonderful day.