SilverBow Resources Inc (SBOW) 2007 Q2 法說會逐字稿

At this time, I would like to welcome everyone to the Swift Energy second-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (OPERATOR INSTRUCTIONS) If you would like to withdraw your question, press the pound key. Thank you.

It is now my pleasure to turn the floor over to your host, Mr. Scott Espenshade. Sir, you may begin your conference.

Thank you. Good morning, everyone, I'm Scott Espenshade, Director of Corporate Development and Investor Relations. I would like to welcome everyone to Swift Energy's second quarter 2007 earnings conference calls. In today's call, Terry Swift, Chairman and CEO, will provide an overview; Alton Heckaman, Executive Vice President and CFO, will review the financial results for the second quarter; and then Bruce Vincent, President, will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on the call are Joe D'Amico, Executive Vice President and COO; and Mike Kitterman, Senior VP of Operations.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on current assumptions, estimates, and projections about us, our industry, and 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 will allow ample time for questions. With that, I'd like to turn it over to Terry.

Thanks, Scott. Thank you again for joining this morning's conference call. Swift Energy Company has just concluded another successful quarter. Our net income before a one-time debt retirement expense increased 4% to $39.5 million or $1.29 per share for the second quarter of 2007. As compared to the same period in 2006. Reported net income was $31.5 million or $1.03 per share. Please see this morning's press release for the reconciliations.

Cash flow increased 14% to $114 million for the first quarter, again, compared to the second quarter of 2006. Production during the second quarter increased 9% to 17.8 Bcf equivalent when compared to the comparable quarter in 2006. Average domestic commodity prices were essentially flat while per-unit costs excluding debt retirement costs increased 12%. The oil and gas sector including Swift Energy Company continued to see third-party vendor cost increases during the second quarter.

Although costs continue to rise, we are benefiting from a more liquid rig market and higher quality equipment being deployed in our fields. Due to timing delays in some key projects and lower than expected production results from our Bay de Chene area, some of which is due to the gas marketing constraints, we are also adjusting our 2007 annual production growth forecast to a range of 1 to 3%. This includes domestic production growth of 10 to 13%. While no change is being made to our reserve growth guidance of 4 to 6%, we currently believe that it will come in at the lower end that range.

Of particular importance during the second quarter, Swift Energy Company was able to refinance our 9 3/8% notes with 7 1/8% notes during a very favorable market window. Mr. Heckaman, our CFO, will discuss this successful transaction in further detail this morning. Geoscience and engineering expertise is the backbone of our organization. Demonstrated by our continued success during the second quarter. The first oil drilled on the Faria project in Bay de Chene is now on line. Production from this well has been slightly constrained by the capacity of the local gas, natural gas pipeline. Planning for and expansion of pipeline capacity began during the quarter and is expected to be complete in 2008.

Despite the expansion challenges that we are facing, it gives me great pleasure to report that our folks achieved very strong domestic production levels at 15.5 Bcf equivalent, which is a 19% increase over levels from a year ago. To allow for further production increases in our Lake Washington field, construction has also begun on a new barge-mounted production facility which will add 10,000 barrels a day of handling capacity during the first half of 2008. Although production is somewhat constrained in the near term, activity in our South Louisiana fields has continued to demonstrate success and should allow for further growth when these expansion projects are completed. As an example, at Lake Washington, the state leased 17990 number 11 and the state leased 212 number 140, each tested at over 1,000 barrels of oil equivalent per day recently. These wells were both drilled and completed during the second quarter and will be on production during the third quarter.

These drilling results continue to reflect the high quality of our project inventory. At Bay de Chene the UA number 139 Faria prospect was well in production during the quarter while the BDC UV number 142 logged 78 feet of net pay in five zones at intermediate levels and is still drilling. Although we are experiencing short term constraints in the field it is evident to all of us that the opportunity for continued growth will exist not only today but well into the future for Bay de Chene. Swift Energy will continue to utilize our proprietary merged 3-D seismic data set to create new opportunities and to add value to our existing assets. This data set is allowing our high-impact exploration inventory to grow in conjunction with an improved developmental and drilling program. During the second half of 2007, we expect to drill one well in Cote Blanche Island, three wells in Bay de Chene, six wells in Lake Washington, and up to five wells in various other south Louisiana fields which were acquired from BP last year.

To summarize, Swift Energy's efforts have once again delivered solid operational and financial results. We understand the challenges of this tight market for products and services, but we are striving to deliver long-term value to our shareholders. All of our efforts go to improving the bottom line as we have demonstrated this quarter, and we believe Swift Energy's high quality assets will continue to provide a deep inventory of developmental and exploratory opportunities for continued success. With that I'd like Alton to present the second-quarter 2007 financial results.

Thank you, Terry, and good morning, everyone. I'm pleased to report Swift's midway through '07 has posted very strong results. Including another very solid quarter. Revenues for 2Q '07 were $168.2 million, up 14% over 2Q '06. Net income was $31.5 million. And diluted EPS came in at $1.03 even after the $12.8 million of debt retirement costs, it's about $8 million after tax, related to our very successful redemption and refinancing of our 9 3/8% senior subnotes.

Diluted EPS adjusted for the debt retirement cost was $0.26 per share higher at $1.29, which exceeds the 2Q '06 diluted EPS of $1.27. Cash flow before working capital changes increased to $3.72 per diluted share. Production for 2Q '07 increased 9% as Terry said, to 17.8 Bcf equivalent and as also, as Terry reiterated domestic production actually rose 19% when compared to 2006 levels.

The continued healthy commodity prices contributed to our strong results. With over 70% of Swift's current production for the quarter coming from crude oil and NGLs which is quite favorable given the current relative premium. I should note we continue to receive improved crude oil differentials both domestically and in New Zealand and expect continued strong Louisiana light sweet and heavy crude pricing in our south Louisiana areas. We have, therefore adjusted our guidance to reflect this trend.

With the current weighting of crude oil liquid, Swift's average composite realized price for 2Q '07 was $9.44 per Mcf equivalent. Domestic composite prices averaged $10.06, up slightly from 2Q '06, while New Zealand prices rose 18% to $5.11 due to the strength of the New Zealand dollar and stronger crude prices. All resulting in a 16% increase in oil and gas revenues over 2Q '06. While prices stay strong at Swift, we remain vigilant and focusing on the margins, and our per-unit cost of metrics which continue to increase sectorwide. As to the second quarter of 2007, G&A came in at $0.59 per unit, above guidance as our human resources and associated costs increased.

DD&A per unit came in at $2.80, which is on the high side of guidance, production costs came in at $1.15, slightly above guidance. Production tax increases, of course, increased in tandem with the production weight, mix weighted toward domestic crude oil, and interest expense came in at $0.41, on the low side of guidance. Swift Energy realized net income of $31.5 million, which is $1.05 basic and $1.03 diluted, and $1.29 when adding back the $0.26 for debt retirement costs. Again, beating the First Call mean estimate for the quarter.

Cash flow before working capital for 2Q '07 came in at $114 million or $3.72 as I mentioned earlier, while EBITDA was $106 million for the quarter, both above the '06 topical amounts. CapEx in the second quarter of '07 was $76 million, well within our cash flow from operations. As we previously announced and as Terry mentioned, we issued $250 million of 7 1/8% senior notes in June with a 10-year maturity.

In combination with the redemption of our 9 3/8% senior subnotes which had been outstanding for five years. Obviously it was a very successful and accretive refinancing, and our timing was excellent. This refinancing further solidifies our balance sheet, and it validates our strategic commitment of matching long-term obligations with our long-term asset base. As of quarter end we have nothing drawn on our bank line which recently was increased to $350 million. Therefore, we have plenty of available capital for any value-adding strategic opportunities that might avail.

With respect to Swift Energy's hedging activity, we have purchased floors of approximately 35 to 40% of our third-quarter domestic natural gas production at an average NYMEX-stripe price of $7.11 per Mmbtu's. Please see our website for detailed hedging information. And as always, we've included additional financial and operational information in our press release, including guidance for the third quarter and full year 2007. 2007 looks to be another great year for Swift Energy Company. With a strong first half behind us, we look forward to the remainder of 2007. And with that, I'll turn it over to Bruce Vincent for a review of our operations.

Good morning, everyone. And thanks, Alton. Today I want to discuss second-quarter 2007 activity including production volumes, recent drilling results, activity in our core operating areas, as well as our plans for the rest of the year.

Swift Energy's production during the second quarter of 2007 totaled 17.8 billion cubic feet equivalent, an increase of 9% from the 16.3 Bcf equivalent produced in the same quarter of 2006. Sequential production increased 1% when comparing the second quarter 2007 to production in the first quarter of 2007. Domestically, second quarter 2007 production increased 19% to 15.5 billion cubic feet equivalent from the 13.1 billion cubic feet equivalent produced in the same quarter in 2006. Primarily due to increased production from our south Louisiana region. Compared to the first quarter of 2007, domestic second-quarter production increased 2% from 15.2 Bcfe due to production increases in Lake Washington and South Bearhead Creek Field.

Second quarter 2007 New Zealand production of 2.2 Bcfe decreased 30% from production in the same quarter in 2006 due to natural production declines and no new drilling activity by us in this region. A decrease of 4% for production levels in the first quarter of 2007 is primarily due to scheduled facility maintenance as well as natural production declines. With regard to the facility maintenance, there is an annual requirement to test pressure vessels and compressors that requires a complete plant shutdown for a few days at both Rimu/Kauri and TAWN. This generally occurs in May.

As for our drilling results, Swift Energy completed 10 of 13 wells in the second quarter of 2007. All of which were domestic. The Company completed 10 of 12 development wells for a success rate of 83% for the second quarter. One exploration well was plugged and abandoned during the quarter in the Bay du Chene field.

Let me briefly review our activity in each of our core operating areas beginning with the south Louisiana region. Production during the first quarter of 2007 averaged approximately 23,000 net barrels of oil elk equivalent per day or 138 million cubic feet per day in the south Louisiana region. Which was a slight increase compared to our first-quarter 2007 average net production. The bulk of this production came from the Lake Washington field, where net to Swift approximately 117 million cubic feet equivalent per day or approximately 19,600 barrels of oil equivalent per day and over 10 million cubic feet equivalent per day from the fields acquired from BP in the fourth quarter of last year.

Compared last year, we have added a total of 30 million cubic feet equivalent per day to this region. Also our Louisiana crude quality differentials were strong in the second quarter and had a direct bearing on our corporate crude price differential and margins. In the Company's south Louisiana region, Swift completed five of seven development wells in the Lake Washington area in Plaquemines Parish, Louisiana. In the third quarter, we have just logged the 17990, number 17, a Newport-area well, with 265 net feet of pay in four zones. And also the BDC, VUB number 142, the Bay de Chene well, which was drilled this quarter, has logged 78 net feet of Bay in five zones at intermediate intervals. And this drill is still evaluating to evaluate deeper potential.

As Terry mentioned several wells that were drilled in the second quarter had strong production tests. And Lake Washington we drilled and completed another Newport-area well, stately 17990 number 11, which tested at 1,272 barrels of oil per day, and 235 MCF of gas on a 3264 inch choke. Additionally the state leased 212 number 140 was drilled to a depth of approximately 10,600 feet and tested at 1,002 barrels of oil per day, and 966 Mcf of natural gas, with no water on a 26 64th inch choke. In Bay de Chene the Faria well was placed on production this quarter, producing approximately 6 million cubic feet per day, and increasing production at Bay de Chene by approximately 80%. Production from this well is slightly constrained by market conditions, but access to additional markets is currently being worked on and should be completed by the first half of next year. Our plans for the remainder of 2007 call for Swift Energy to drill 12 to 16 additional wells in the south Louisiana region.

Swift Energy currently has four barge rigs contracted in this region. One of these wells drilled in the second half will be a pressure maintenance injection well in Lake Washington. Most of the reservoirs in Lake Washington are water derived, but there are areas that lend themselves to pressure maintenance to enhance hydrocarbon recovery since they may have weak water support. An example of this, the CM number 222 well is just such a well, and we began pressure support about a year ago with this well by pumping water into a down-dip injector well. The well has now seen cumulative production of over 1 million barrels, compared to the 700,000 barrels estimated from just primary production without this additional pressure maintenance. We've discussed this pressure maintenance before in Lake Washington, and the 222 well was first one that we tried, more of a test pilot and it's worked very, very effectively. We believe that we produced over 40% more crude oil than if this well was just left on primary production. The CM 222 well is still producing just over 1,000 barrels a day with no water.

This new injector well will provide water support for two zones in the Newport area. When we started drilling this area, we believed that the wells in the Newport area were water derived as is much of the field. But upon further analysis and production history and testing, we have determined that at least some of the reservoirs may only have weak water drive support and could be aided by pressure maintenance. As a result, we've choked back production until the pressure maintenance project is underway.

Other significant projects that have been delayed are the redrilling of the Horseshoe Bayou well. This well was actually being worked over late last year and into early this year, which we believe was going to be successful, but it wasn't. And the well needed to be redrilled. And it's taken us a little bit longer to get that project underway, but we expect that well to spud within the next couple of weeks. One of the wells that we're finishing up now, the rig will move to drill that particular well.

We also had some wells that were deferred in 2007 into next year for various reasons, whether it's water depths or permitting or the right rig for the right job. We also -- in particularly the BP properties, it's taken us a little longer to get all the data and analyze the data from BP on those properties to get our recompletion program underway. And then additionally in New Zealand because of the strategic review that's underway, we deferred some activity in both the Manutahi and Tikorangi areas that was originally planned in the budget.

In Cote Blanche Island area Swift Energy has received its pre-step debt migration of the seismic data from its 2006 seismic chute, and we plan at least one well there in the second half of 2007. We're pretty excited about what we're seeing with that data. The facility expansion project on the west side of the field in Lake Washington is on track for its scheduled first half 2008 completion. Planning, permitting, and engineering studies are underway with a pipeline in Bay du Chene to alleviate our current natural gas market constraints. This is another project that will be completed in 2008.

Our operating region in New Zealand produced 2.2 billion cubic feet equivalent in the second quarter of 2007. Or approximately 24.4 million cubic feet equivalent from both the TAWN area and the Rimu/Kauri area. The second-quarter decrease in production was primarily attributable to downtime resulting from scheduled plant maintenance, which I mentioned earlier, and natural declines. For the second quarter of 2007, New Zealand accounts for 13% of Swift Energy's total production. Due to the previously announced review of strategic alternatives in New Zealand, no drilling activity is planned there for the remainder of the year, and we do expect the strategic review will be completed by year end.

In our South Texas region, production in the first quarter 2007 averaged approximately 21 million cubic feet equivalent per day, and this came primarily from the AWP Olmos area. In the first quarter we successfully completed one development well targeting the Olmus sand and the AWP area. We have a rig in the field currently and are continuing our drilling program which envisions approximately 8 to 10 wells for the year. The Toledo Bend region contributed approximately 12 million cubic feet equivalent per day of production for the first quarter of 2007. Swift Energy completed three development wells in South Bearhead Creek and Beauregard Parish, Louisiana. We continue to have a rig operating in South Bearhead Creek area and we expect to drill at least two to three additional wells targeted in Wilcox this year. The area is showing good potential, and we are pleased with the results to date. Thanks for your attention. I'm going to turn it back to Terry now for a recap before we open it up for questions.

Thank you, Bruce. Before we open it up to questions, Swift Energy's focus for the remainder of the 2007 will concentrate on reserves and production growth as well as managing our costs. We've seen continued success from our drilling program with changes in timing and previously stated issues have produced constraints that have challenged us causing us to reduce our 2007 production guidance range to into the 1 to 3% range. We expect domestic production, however, to increase 10 to 13% this year. We also expect to have a decision from our review of the New Zealand strategic alternatives by the end of the year.

To review some of the highlights from this morning's conference call, I'd like to focus on the fact that Swift had strong strategic results in the quarter. In the second quarter 2007 our revenues increased 14% to $168 million. Earnings were $31.5 million or $1.03 per diluted share, and cash flow was $114 million or $3.72 per diluted share. These results all lead directly to added value and further solidify our strong balance sheet.

In the second quarter of 2007, production increased 9% for the second quarter, 2000, compared to 2006 to a level of 17.8 Bcf equivalent. Again, I want to emphasize that's with a very strong domestic production component. Swift energy is drilling deeper, higher impact prospects in both Lake Washington and Bay de Chene. We will drill additional deeper projects in Bay de Chene and Cote Blanche Island later this year. We believe these deeper wells clearly demonstrate that material prospect potentials can be derived from our high-quality 3D data sets in south Louisiana.

Finally, we continue to have a strong and flexible financial position which allows us to take advantage of future opportunities whether those opportunities are organic growth through drilling or whether those opportunities are strategic growths through acquisitions, Swift Energy Company will continue to pursue these growth opportunities. At this time we'd like to begin the question and answer portion of our presentation.

(OPERATOR INSTRUCTIONS) Our first question is coming from John White with Bleichroeder. Please go ahead.

Good morning, everybody. Hi. I have a couple of questions. One, you mention, Bruce, you mentioned permitting at Lake Washington. I was under the impression you had -- had the permitting process pretty well under control. If you could talk about that a little bit, and then a little bit on -- more detail on the south Louisiana gas market and the constraints at Faria?

Sure, I'd be happy to do that. Permitting, as probably everybody knows, is challenging everywhere in North America, or at least certainly in the US, whether it's Louisiana, whether it's Texas, whether it's the Rockies. We've been doing that a long time, and it just requires good planning and lead time. I would tell you that permitting is a challenge, but it has not really affected our drilling in program dramatically. We have had some issues where the water depths for instance were changed because of Katrina. And we couldn't get the barge in we wanted to because of the change in the water depths and so we had to get a new location that repermitted. Stuff like that. Not significant but just day-to-day stuff that has issues. The permitting process. I think we find this in Texas as well as Louisiana, it's taking a little bit longer than it was before. State resources are -- tend to be drained a little bit. I think we've seen it more in Texas than Louisiana where some of the state people who have handled permit have actually been hired by the industry to help with a lot of that particularly like in the Barnett shale area, et cetera.

So while permitting is always a part of our business, I wouldn't tell you that it's dramatically impacted us. But it's something that we always have to plan well for, and keep on the front burner. With regard to the south Louisiana gas market, in general, south Louisiana gas market is very, very strong. These particular issues at Bay de Chene are the gas at Bay de Chene, and there's another field nearby, goes to the alliance refinery. And it's somewhat dictated by what that refinery will take which can vary sometimes during the year. Right now, it's taken a reasonable amount, and we're able to get pretty close to our capacity there. The pipeline provider there has been Chevron Texaco. And last year, we recognized that our plans called for increasing gas production, and we initially had conversations with him about taking the gas elsewhere to provide other markets. And they were initially receptive at the time but they later changed their mind and don't want to be essentially a third-party transporter. It's my understanding that they actually intend to sell that particular pipeline, they just don't want to be in the business of transporting third-party gas.

Because of the potential we see at Bay de Chene though, quite frankly we see the need to open up even bigger markets, and we've been working with some other people down there who have other access and have plans underway, quite frankly, to give us some additional access to substantial, new markets because we believe we have that capacity there. These thing just take time to -- whether it's permitting, whether it's designing, whether it's working with the other provider who has to put in compression or build platforms to do that or make connections, meters, all those kind of things are just part of the process that makes it take -- usually -- it's probably going to take us up to nine months to try to complete that project, to actually get that accent. That's the specific issue relating to Bay de Chene.

Well, thanks very much for all that detail. It sounds like the drilling results continue to look very good. You just are having some delays and little -- little bottlenecks down from the wellhead on down.

That's correct. That's -- that's what I would tell you is the primary thing going on.

Thanks a lot.

Thank you. Our next question is coming from Adam Leight with Credit Suisse . Go

Good morning, Adam, how you doing?

Good. Well, well. Could you just -- a little more color on your reserve growth estimate. How much of the decline towards the lower end is related to New Zealand and lack of capital spending there versus the delays or other issues in your domestic reserves? Maybe you can provide some expectations on growth in one versus the other.

Yes. I'll start the answer to that question. This is Terry. There's no doubt that we did -- when we put our budget together have plans for New Zealand and some capital spending there, and we have as a result of the decisions we made earlier this year, we have deferred certain of those projects. There was a 3D in New Zealand that we think is a very viable 3D that could certainly deliver some nice reserve growth. We've delayed that for now. There's a couple of additional wells in the Waihapa area that we've delayed the drilling on. And then there's some Manutahi wells, as well. But that's not the preponderance of the reason that we're lowering the expectation within that range. We're staying within the range of we want to keep our goals set high. We do believe that's the way to go forward.

We do see a lot of other opportunity in the second half, particularly with drilling out our exploratory inventory, some of the things that we're doing. But obviously as you get to the mid-year with exploration activity and your portfolio, you just can't be counting on all of that. So part of reason that we were saying that we want to move to the lower end of that range is because of the probabilities that are associated with certain of the exploratory drilling prospects for drilling. So some of it's a little bit from New Zealand, but some of it's because we're at mid-year be and we've still got some exploratory wells to drill. We certainly are working as hard as we can to get above that point that we -- that the lower end. But that's the guidance we're giving right now.

Okay.

Adam, lets me just add one other thing. I mean, that -- when Terry talks about the probabilities of the exploration program, we did have a couple of -- two in particular exploration wells in the first half that were unsuccessful. You're looking at your second half program and so you want to be conservative and the probabilities change a little bit. And so we feel like it's better to say we're more apt to be at the lower end of the range at this point in time.

And is there any implications on your finding cost estimates within that?

I don't think there are significant implications at this point in time.

Okay. And one -- one other question on that. You are talking about weaker water drives. Does that change the UR's in those wells?

The ultimate recovery from the Newport wells obviously is dependent upon not only the primary characteristic. These are great reservoirs in terms of permeability and veracity and initial low water saturation. So we have always believed that the ultimate recovery from these wells could be very significant. The issue, of course, is that until you actually get good pressure data and do good history matching which the guys now have not got reservoir simulation models and solid information around everything. We very confident that we're going to get some really good recoveries out of that. Now traditionally, you sit back and you look at the depletion drive reservoir. Its recovery might only be 25% to 35%. But with pressure maintenance and really this is more akin to pressure maintenance than water flow. But with pressure maintenance in this type of reservoir where you get the water far enough down dip and get a uniform piston-type drive, you could get up to 60% recovery. I think the implications are that with a very successful project, we might actually recover more than we had originally anticipated.

That's good. I may have missed this, but the decline in capital spending in the second quarter versus the first quarter, how much of that was New Zealand versus delays versus something else in the US?

I'd have to go look at the specific detail. But off the top of my head, I'd say it probably wasn't significantly from New Zealand. I mean, there would have been a little bit that would have been planned that we didn't do. But it would really have a lot more to do with delays and probably more on the facility side. Not so much in the delays in capital spend accelerates as you get closer toward the end of some of those projects.

Okay. And then two quick housekeeping items if I may. It looks like I may have done my math wrong, but it looks like your hedges for U.S. gas were increased during the quarter. Is that correct?

That's correct.

That's good. And on the cash flow statement, there's an item for distributions related to operated production. Could you explain what that is or why that's up significantly versus last quarter.

Adam, it's mainly a change in our AP trade. Most of it's CapEx related, where we've been invoiced but the checks just haven't cleared at this point. So it's mainly just a timing issue.

Okay. So that's not a sustained--?

No.

Level. Okay, great. Thank you very much.

I think Adam, just a little more color on that if I understand it correctly. We did implement a new computer system, and I think that that's probably what that's related to. Just changing over from one accounting system to another, probably caused a little bit of slowdown in the trade of payables that's creating that impact. That's getting cleared up.

Great. Thanks a lot.

Thank you. Our next question is coming from Brian Kuzma with JPMorgan. Please go ahead.

Good morning, guys.

Good morning, Brian.

Terry, I think you went through real quick the wells that you guys have planned for the second half of the year. Could you go through those one more time by asset.

Yes. Let me get that during the second half of 2007, we expect to drill one well on Cote Blanche Island, three wells in Bay de Chene, six wells in Lake Washington, and up to five wells in various south Louisiana fields that relate to the BP acquisition from last year. And we're characterizing those wells in particular. We'll be drilling some south Texas AWP wells also. But we're characterizing those wells in the context of this is where we're using the merged 3-D. And we've got what we believe are some very high-quality targets we're working with there.

And that could change slightly. Like Cote Blanche Island as an example -- we say one well there, but we've got another one that we may drill also. We're seeing some interesting solid overhangs in the prestage debt migration. And we'll be testing that with the first well. We may also get a second well there.

And you guys are going to keep four to five barge rigs running in south Louisiana?

Yes.

And how many of those wells are injection wells?

I think we just have one well planned between now and the end of the year for injection well. And that will actually be able to inject water into two different reservoirs.

Yes. And I want to qualify that just a little bit. When we talk about an injection well, we're drilling in an area of the field that's got multiple pay horizons, and so when someone talks about injection, it's really a well to also develop the pay horizons in the area. And there are one or more sands that, where we could use that well for injection. But it's also important an important well in terms of having take points for other productive sands.

And then on your facility ramp-ups in 2008, what should we expect in terms of when those facilities start up, like at the West Side facility? Should we see a big slug of production coming online in the first half of '08? Are there a bunch of wells that are just shut in waiting for that facility, or is it--?

Well, I'll try to characterize it and keep is simple. We clearly, in Lake Washington, where the production is in the field relative to the existing platforms, it does create a little bit of a problem for us. We have got some areas that have H2S, and the wells that produce sour crude have to go to a particular platform. Then we've got other wells that have higher water cuts. They have got to go to platforms that can handle the water. So the West Side facility we've designed in such a way that it's got a lot more flexibility than probably any other facility out there. And we're also designing the pipeline infrastructure out there so that we can move in and out of it and expand it beyond the 10,000 barrels a day much quicker than building a brand-new facility. It's got a different footprint on it than the other facilities.

When we talk about start-up of that facility and when we talk about a nameplate of 10,000 barrels of oil a day, we're factoring in two things that I want to really discuss. We've always said about the middle of 2008. The reality is that you've got -- that will be completed probably in the first quarter of 2008 and go through a commissioning process. We'll be moving crude oil through that facility before that time. One just has to ascertain how long the conditioning will take and how we optimize use of the facility in the field. We do believe it's going to be materially utilized by the Newport area both in terms of gas compression over there and getting more gas to market, but also in terms of water handling over in that area. Again with the way we're building it, we're going to have the flexibility to enhance other areas of the field by throttling or using the pipeline infrastructure there to optimize -- putting the right wells to the right platforms.

So it will help with debottlenecking throughout he sales?

Yes, that's probably the simplest way to say it. I probably overcomplicated it. It will help debottleneck a lot of things.

Okay of all right, that's it from me. Thanks, guys.

Thanks, Brian.

Thank you. Our next economy is coming from Leo Mariani from RBC. Go ahead.

Good morning, guys.

Hey, Leo.

Good morning.

A quick crunching here on the ferry discovery. I think you folks had talked about some follow-up drilling there, routed to better delineate the discovery. I was looking for an update on what your progress has been to date and what your progress is for the rest of the year there?

The well that I mentioned that had logged I think it was five different horizons, about 78 net feet and the intermediate levels is that kind of offset to Foreia, and it's, in addition to the intermediate levels it has logged, it's going deeper really to evaluate potential horizons that the first well didn't get to.

Okay. I guess you mentioned another well or maybe second, maybe two additional wells at Bay de Chene in the second half of the year. Would another one of those be potentially another delineation well out there or a follow-up?

That's quite possible. I think we need to drill this particular well and evaluate it. The guys are working hard in their evaluation and mapping it. There is an adjacent fault block that we believe also has similar potential. And that is one of the ones we're targeting as a prospective well in the second half.

Okay. Last question for you guys real quick. What's the current production running there at Lake Washington?

I think net to Swift is around 19,600 barrels, equivalent.

I might interject there, when we talk about the different wells, I think we might have -- might have been referring to the wrong well there. The Faria well that is the offset that's also drilling deeper, that is the 146-R that we're referring to.

Okay. Thanks for your time.

Thank you. (OPERATOR INSTRUCTIONS) Our next question is a follow-up from John White with Bleichhroeder.

Hi, if you could help me, what is the current quarter the split on cash and deferred taxes, and how do you see that for the rest of the year also? Hello?

Yes. John, actually just looking for the number.

While you're looking that up, how--?

I think cash taxes are about 5%. And I think that's where we see ourselves for the quarter with our current spend rate. We're still going to be on the low end from a cash taxpayer point of view.

Okay. And CapEx unchanged given the new guidance?

Correct.

Okay. Thanks again.

Thanks, John.

At this time, I show that there are no further questions. I would now like to turn the call over to management for any further remarks.

We'd like to thank you once again for joining us in this morning's conference call. And we look forward to getting on with the second half of the year and making our results and our goals. Thank you again.

Thank you, this does conclude today's Swift Energy second-quarter earnings release conference call. You may all disconnect and have a great day.