SilverBow Resources Inc (SBOW) 2006 Q2 法說會逐字稿

Good morning, ladies and gentlemen. My name is Lawrence and I will be conference facilitator today. At this time I would like to welcome everyone to the Swift Energy second quarter earnings conference call. [OPERATOR INSTRUCTIONS]

It is now my pleasure to turn the call 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 2006 earnings conference call.

Participating in today's call is Terry Swift, Chairman and CEO, and he 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 and available for questions are Joe D'Amico, Executive Vice President and COO, and Mike Kitterman, Senior Vice President of Operations. Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our 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 we'll allow additional time for questions.

With that, I'd like to turn it over to Terry.

Thanks, Scott. Thank you again for joining this conference call. I'd like to begin today's conference call by reading a few words written by A. Earl Swift in 2004, as he reflected on Swift Energy Company's past 25 years.

"Looking back on the last 25 years, I can say that, together, we have seized most of the opportunities that have come our way. Thanks to all of you, as well as many others who went before you, we can be proud of our past accomplishments. As I had hoped when I founded the Company, we have made a difference for our shareholders, for each other, and for those communities in which we operate. We also have a bright future. With our dedicated employees and an experienced and capable management team, we can sustain growth and value for all our stakeholders. And having established a corporate culture that believes in honesty integrity, and responsibility, we can serve as a good example to society at large.

I see Swift Energy as a Company of role models, an organization filled with people who constantly work to change things for the better. I want each of you to know that I'm proud to be your chairman and have every confidence that you will continue to do great things in the future."

Once again those words were written by A. Earl Swift in 2004. On May the 30th, this year, Aubrey Earl Swift, my father, our founder passed away . We at Swift will carry forward the vision and mission of Swift Energy Company with hard work, diligence and the ethics Earl, as our founder, firmly established at Swift Energy.

To his credit and the accomplishments of many other dedicated people, Swift Energy continues to do great things. Swift Energy set several new financial and operational records during the first half of 2006. We have continued to focus considerable geologic and engineering effort in south Louisiana, specifically in our Bay de Chene, Cote Blanche Island, and Lake Washington fields. In the second half of the year we should have more results from our south Louisiana drilling programs These programs will be targeting material exploration potential.

Successful exploitation and facility fuel projects in Cote Blanche Island, which I'll refer to as CBI, and Bay de Chene, which I refer to as BDC, have already led to significant production increases for those two fields, once again in South Louisiana. The measured pace that we are demonstrating in CBI and BDC is similar to how we started in Lake Washington. We think that additional meaningful growth is possible out of these two fields over the next several years.

The CBI state lease 340 187 well is a good example. We're about to complete this new well, which has two very nice gas pays and a possible oil pay in it. We have just finished the 3-D data application at Cote Blanche Island, CBI, and we are now processing this new seismic data set. The new seismic data should greatly improve our ability to identify and target additional opportunities at CBI. In Bay de Chene, we plan to drill two to three high-impact exploration wells this year that also have significant reserves potential. Success at any of the Bay de Chene prospects will help confirm seismic signature and interpretations, and should also further derisk similar opportunities in other fault blocks at Bay de Chene.

Meanwhile at Lake Washington, our success is much more visible. We recently completed our testing of the state lease 17990 number 10 well. During an initial short-term flow test, this well flowed up to 9,200 barrels of oil equivalent per day from one sand. This initial test was, of course, a short term test on a 50/64-inch choke.

Following the initial flow test and subsequent pressure build-up test, the number 10 well was production tested using a 24/64-inch choke, and flowed over 3,600 barrels of oil per day with no water. We're also in the process of completing the number 8 well, which had three sands and a combined net pay of over 100 feet. Obviously, we're very pleased with these production test results. Our geoscientists and engineers are integrating this new information into the Newport appraisal and development plan. Post stack depth migration of our Lake Washington 3-D data set is also under way.

These projects will complete understands the near future, and together with additional drilling results should give us a better understanding of Newport's proven and probable reservoirs. These projects will also help us understand Newport's deeper possible horizons and the ultimate potential at Lake Washington. Preliminary plans are also underway to add at least 10,000 barrels of oil per day of new oil processing capacity on the west side of Lake Washington, which will take -- which we plan to implement over the next 18 months.

We are also taking this opportunity to increase our capital spending program to the $375 million to $400 million range, still within our projected cash flow. Swift Energy reiterates that we plan to grow production 14% to 18% in 2006. We believe that our 2006 plans will continue to deliver solid performance to our shareholders. We are continuing to deliver value through our current operations, and are always looking to add to, or enhance our portfolio of opportunities and assets. Proper execution of our operational strategy in 2006, as planned, should bring us yet another record year. Our opportunity set for reserves and production growth is the best in the history of our company. South Louisiana plans call for more wells than last year, which should be significant, not only for production, but for reserve growth, specifically, and especially, in Lake Washington, Bay de Chene, and Cote Blanche Island.

With that I'd like to have Alton Heckaman present the second quarter 2006 financial results.

Thanks, Terry, and good morning, everyone. I'm very proud to report Swift set yet another record for earnings during the second quarter. Revenues were $147.2 million, up 41% over Q2 '05. Net income set a Company record of $38.2 million, up 37%, and diluted EPS increased 32% to $1.27, while cash flow before working capital changes increased 39% per diluted share, to $3.34. Global production increased slightly to 16.3 Bcfe, while domestic production actually rose 10% for the '06 quarter when compared to '05. Commodity prices stayed strong, particularly crude oil. With 65% of Swift's production for 2Q '06 coming from crude oil and liquid, this current oil pricing environment is quite favorable for Swift. With current weighting of crude oil and liquid, Swift's average composite realized price for 2Q '06 increased 35% to $8.19 per Mcfe versus 2005.

Domestic composite prices averaged over $10 per Mcfe, up 33% from the prior year, with crude oil averaging over $69 per barrel for 2Q '06. The results, a 38% increase in oil and gas revenues over last year. While these prices are great, we continue to vigilantly focus on per unit cost and metrics. As to the second quarter of 2006, G&A, including the 123(R) stock option expensing, came in at $0.47 per unit, in line with our guidance. DD&A per unit came in at $2.39, which is slightly above our guidance. Production costs came in at $1.14, also above our guidance.

Let's talk a little bit about the production costs. These costs are increasing across our sector due though tight industry conditions. But 2Q '06, Swift actually incurred Hurricane Katrina and Rita repairs, which added approximately $3.1 million to this cost category, primarily in the Bay de Chene and Cote Blanche Island areas. Without these hurricane-related charges, all-in production costs for Q2 '06 would have been $0.95, almost $0.20 lower than that reported.

Production taxes obviously increased in tandem with higher prices in the production mix, and interest expense came in at $0.36, slightly below our guidance. We therefore realize net income of $38.2 million, $1.31 basic, and $1.27 diluted, as we mentioned, again beating first call mean estimates. Cash flow before working capital changes for Q2 '06 came in at $100.2 million, or $3.34 per diluted share, while EBITDA was $105 million for the quarter, both well over the '05 comparable' amounts. The results for the six-month period ended June 30 were equally impressive for virtually the same reasons discussed for the second quarter.

CapEx for the second quarter, net of the $20 million in proceeds from the sale of the Brookeland Master Gas Processing Plant, was $86 million, well within our cash flow from operations, allowing us to increase our cash at quarter end to $72 million. Our bank line remains unused, providing plenty of available capital for any value-adding strategic opportunities that should avail themselves.

With respect to Swift Energy's hedging activity, we have oil price floors in place for August through December 2006 production, with an average strike price of over $64. Please see our website for more information regarding our hedging activity. And as always, we've included additional financial and operational information in our press release, including guidance for the third quarter and full-year 2006. This year is shaping up to be the best year in Swift Energy's long history. We had a great first half. And as Terry said, we're even more excited about the great things to come,

And with that I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, everybody. Today I want to review second quarter 2006 production, our recent drilling results in all of our core operating areas, and Swift Energy's plans for the second half of 2006. Swift Energy's second quarter 2006 production increased 2% to 16.3 billion cubic feet equivalent from the 15.9 billion cubic feet equivalent produced in the second quarter 2005. Domestic production increased 10% to a record 13.1 billion cubic feet equivalent, from the 12.0 Bcfe produced in the same quarter in 2005, primarily due to increased production from the south Louisiana region.

Second quarter domestic production was also 3% higher than the comparable production in the first quarter of 2006, principally due to the return of Cote Blanche Island into to production, following its hurricane repairs, and increased production from the Lake Washington area. Second quarter 2006 New Zealand production of 3.2 billion cubic feet equivalent decreased 20% from the same quarter in 2005, and decreased 17% from the levels in the previous quarter, due to reduced crude oil liftings in the second quarter 2006, as well as scheduled facility maintenance and natural production decline.

As for drilling results, Swift Energy successful the completed ten of 17 wells in the second quarter of 2006, including ten of 11 domestic development wells drilled for a success rate of 91%. In the south Louisiana operating region, production during July 2006 averaged approximately 16,900 net barrels of oil equivalent per day in Lake Washington. This compares to our second quarter of 2006 average net production of 16,500 barrels of oil equivalent per day in that area. For one 2006, we expect to exit the year with net production of 18,500 barrels of oil equivalent per day from the Lake Washington area. We believe the Newport wells should certainly help us reach this goal.

The Newport number 10 well rates that Terry mentioned earlier were test rates, and we will more than likely produce these wells at average rates between 1,000 and 2,000 barrels per day. We are studying the Lake Washington facilities for efficiency gain and further capacity increases. Alternatives include increased pressure in the field for gas [lift] purposes and the potential for a fourth production platform on the western side of the field. Additionally, the Bondi well he announced earlier this year is expected to be connected to production facilities in the fourth quarter.

The Bay de Chene and Cote Blanche Island fields averaged over 12.5 million cubic feet equivalent per day of production in July. This is about three times the rate of production from when we acquired these fields. As Terry mentioned, we have one well, the CVI state lease number 340 number 187 waiting on completion in Cote Blanche Island, and this should be a very nice well. In the south Louisiana region, Swift Energy successfully completed all seven development wells drilled in the Lake Washington are in Plackman Parish, Louisiana.

Swift Energy had four barge rigs operating in the second quarter in this area, one of which is just for about 45 days to another operator, but will return to Swift to work in this area for the remainder of the year and into next. At this time, one rig is drilling in Cote Blanche Island, and the remaining two are located in the Lake Washington area. Swift Energy continues to utilize one completion rig in this area, which is alternating between Bay de Chene, Lake Washington, and Cote Blanche Island. A fifth drilling barge rig has been contracted for later this fall.

Our plans for the remainder of 2006 call for Swift Energy to drill eight to ten wells in the Lake Washington area. At least two to three of these wells will be additional wells drilled in the Newport prospect.

The other major project for Lake Washington area is the pre-stacked depth migration of the entire 3-DQ, which will help enhance our 3-D imaging around the salt and the deeper initiatives, particularly at Lake Washington and Bay de Chene. At Bay de Chene and Cote Blanche Island we plan to drill five to eight additional wells, with at least two in Bay de Chene being high-impact exploration wells. And I'd also mention that during the second quarter, we completed the 3-D shoot at Cote Blanche Island, and that's in the process of being processed, and we expect to get that in the fall.

In the south Texas region, production in the second quarter of 2006 averaged just over 20 million cubic feet equivalent per day in the AWP Olmos field. We successfully completed two of three development wells targeting the Olmos sand in the AWP area, and we were unsuccessful on four shallow, very shallow exploration wells, targeting the government well sand in the same AWP Olmos area in McMullen County, Texas. I will note that all of these shallow government wells sand tests were all drilled for a total cost of approximately $100,000.

The Company also expects to have a rig operating back in the AWP Olmos in the third quarter, and we plan to drill up eight additional development wells in the second half of the year. The Toledo Bend operating region contributed approximately 9 million cubic feet equivalent per day of production in the second quarter of 2006. Swift Energy successfully drilled and completed a development well in the Brookeland field in Newton County Texas, and will have one rig operating in the South Bearhead Creek area in Beauregard Parish, Louisiana parish later in the third quarter, where we expect to drill three to four wells targeting the Wilcox the second half of the year.

Our operating region in New Zealand produced 3.2 billion cubic feet equivalent in the second quarter 2006,, with approximately 16 million cubic feet equivalent per day coming from the Tawn area, and approximately 18 million cubic feet equivalent day from the Rumu-Kauri area. The second quarter decrease in production was primarily due to the reduced crude oil liftings and the scheduled facility maintenance at Tawn during the second quarter. For the second quarter of 2006, New Zealand accounted for 19% of Swift's total production. Swift had only two tanker liftings in the second quarter of 2006.

We typically expect to get three or four liftings per quarter. A lifting did occur in early July, and will be accounted for as production sales in the third quarter. As a reminder, Swift Energy's crude oil production in New Zealand is not recorded until the sale as occurred, as the timing of these tanker liftings can have an impact on a reported sales of production's quarter to quarter.

During the second quarter, the Company began testing the Goss and Trapper prospects. Both exploration prospects have intermediate depth objectives that will be tested. However, the deeper objectives in both wells were deemed to be noncommercial after testing. The Company was unsuccessful with one development well that targeted the Kauri sand in the second quarter of 2006.

Swift Energy currently has two drilling rigs operating in New Zealand, one drilling the [Kofi] exploration well in permit 38742, and another targeting the [Tickerangi] limestone in the Waihapa area. The Company also plans to drill up to two wells targeting the [Manatahi] sand in the Rumu-Kauri later this year. Swift Energy New Zealand also negotiated a new 3.5- year gas contract on its existing natural gas production from the Rumu-Kauri area, and this contract recognizes this current supply shortfall situation in New Zealand.

Lastly, in our Alaska operating region, the Company's Endeavor prospect in Alaska was drilled in the second quarter and was plugged and abandoned. This was our initial commitment well that allowed us to earn into 54,000 acres in the onshore Cook Inlet Basin area. We have previously identified several oil and natural gas prospects on this acreage, and the work is currently being done to determine our capital plans for next year.

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

Thanks, Bruce. Before we open up for questions, I want to reiterate where Swift Energy Company's 2006 operational plans are concentrated and review of the second quarter highlights. Swift Energy had impressive financial results in the second quarter, and we expect to continue delivering on our operational plan in 2006.

In the second quarter of 2006, our revenues increased by 41% to $147 million, earnings increased 32% to over $38 million, and cash flow increased 44% to more than $100 million. These results all lead directly to increased shareholder value and further solidify our strong balance sheet. In the first half of 2006, we had record production of 32.9 Bcf equivalent, and we are well on our way to meeting our 2006 goal of a 14% to 18% production increase. Swift is drilling deeper, higher-impact prospects, especially in Lake Washington, and specifically around our Newport prospect.

We will also use this year to drill deeper in Bay de Chene and Cote Blanche Island. These deeper wells will target material reserve growth opportunities developed using our 3-D data sets. Finally, we continue to have a strong and flexible financial position, which allows us to take advantage of future opportunities, whether they are organic growth through drilling, or strategic growth through acquisitions.

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

Thank you. [OPERATOR INSTRUCTIONS] Your first question is coming from Rehan Rashid of Friedman Billings.

Good morning, Terry. On the Lake Washington number 10 well -- Congratulations, first of all, on a great test rate here. Could you talk to us about, one, the 3.,500 barrels per day rough deliverability rate. How many days did we test that for? Take us back, maybe, to the earlier two wells. Are those on-line, and if so, where and what rates are they producing? And then lastly, on the same subject, 16,500 feet, could you talk to us a little bit more about what exactly happened on the deeper objective? Did you say pay or not, structural integrity or not?

Well, I can give the big picture, and then I'll ask Joe D'Amico, our Chief Operating Officer, to comment on some of the details about the production itself and how that plan is proceeding. There's no question that the seismic data has been excellent for targeting these horizons. The guys that are working the project, both in-house, as well as some folks we work with externally, have done a great job in both interpreting and coming up with near salt imaging of the way these formations come up against the salt. We do not have our depth migration done just yet. That's going to add a lot of value.

We got the salt on a couple of these wells in the deeper horizons, and one particular well, we actually drilled through the salt. Now, that's a big statement when you're looking at 3-D data set, because it helps you calibrate knowing the top of the salt in an area, as well as the bottom of the salt in the area. It helps you calibrate into you're 3-D, and gives you a great ability to test how good your depth migration is. So the deeper horizons, we need to step back.

We clearly found salt in some of the areas of the deep horizons where we had anticipated not finding salt, but we also got back into [clastics] or reservoir types of sediments, which has us very encouraged for the deeper potential. That's kind of the big picture. Going to the individual wells, we have targeted some nice anomalies that are associated with the normal structural interpretation of the seismic, and those anomalies are holding up real good in the intervals that we're actually producing from.

Joe, you probably ought to comment on the tests versus the production we're getting out of those wells.

Okay. The first well we drilled was was the number 4 and it's produced about 1,000 barrels a day. The second well was the number 3 well, and we tested in two different zones at about a little over 3,000 barrels a day from each zone, and it's currently producing from one zone at about 2,500 to 3,500 barrels a day. The allowable is 4,000 barrels a day.

The number 10 well is a well we just recently put on production, and when we tested that well, it tested at over 8,000 barrels a day, but we're producing it at about 3,500 barrels a day right now. As I said, though, the allowable's about 4,000 barrels a day. Number 8 well, we have a completion rig on it right now, and we should have that on production very shortly. And we're currently drilling number 9 well, and we're just in the process of setting intermediate casing on it.

Okay. Just going back to the initial reserve guesstimate that we had talked about for this Newport area of ten to 30 million barrels, has anything changed in that regard with the deeper sands, the objective you're not about yet, or should we run with that initial statement?

I think we clearly feel real good about the lower end of that range as relates to what we think we can do in moving categories into the proven category over the near future, as we keep drilling and keep working the seismic. I'm not prepared to take the top end off of that range yet, but I do want to get this work done, and that top end does relate to some of the deeper horizons that, right now, we do need more time to get this depth migration done.

When do you think you get that migration study done?

It's due by the end of the year, Rehan, so we'll be able to actually utilize that in the 2007 budget plan. I also want to be sure that I clarify that that reserves potential that we talk about is a gross reserves potential, not a net-to-Swift number.

Plus you had books on that last -- at the end of last year, as well on that.

Yes, we're obviously very encouraged with the drilling activity that we've actually seen in Newport. We're still actually pretty excited about the deep potential, but we're doing this pre-stack depth migration over the entire 3-DQ, which includes Lake Washington, but also includes Bay de Chene. And there are a number of fairly significant prospects that we believe will clear up and derisk from this, and so we just want until we get that information before we actually expend the capital to drill the well.

What depth is this productive horizon, and forgetting about deeper for a second, I guess, from an intermediate standpoint, do you say other Newport look-alikes?

The act -- certain of this information does get reported publicly, and probably ought to refer to one of the public reports for the state. The big test that we've been talking about in the number 10 well was around 11 -- Joe, you go --

11 something.

A little below 11,000 feet. So it's a very manageable depth, and there's a lot of lot of section for sediment underneath that.

And are there other Newport 11,000 feet lookalikes that your see from your seismic signatures above salt?

Well, we definitely have other prospects in and about Lake Washington that have similar seismic attributes, so that alone makes us very excited. Some of them are a little deeper, and some of them aren't necessarily right up against the salt. So they're -- even though in the attribute sense they're very similar, they do have differences, and we will be talking more about that after we get the depth migration.

I might also point out, Rehan, we talked a lot about 3-D at Lake Washington. I know you'll recall that we actually acquired a number of other existing 3-D shoots, including the Bay de Chene shoot, and merged them together for a merged data set of pretty close to 700 square miles, processed that entire data set on the same parameters. And obviously, within that data set, we see a number of interesting things. Just probably leave it at that for the time being.

Some are, as Terry said, near the salt and some are away from the salt. Bondi is actually a good example of one that was away from the salt that we did drill and were successful at. We have done a long-term production test on it not long ago, which confirmed our desire to lay the gathering lines, which is like five miles all the way to the production facilities, and hope to have that on production before the end of the year. So we're pretty excited about what we're doing strategically. We're pretty excited about the way we've gone about this large merged data set. Obviously having drill bits through some seismic signatures that both you can recalibrate and fine tune it around the data set are very encouraging for us.

On the existing Lake Washington, could you remind me, what's the current production apart from Newport? Give me a feel for maybe what's the decline late in that, and how many wells a year would you need -- call it from the shallow formations to keep that, call it just flat, so all of this stuff that we're talking about is additive rather than depletion replacement, basically?

I think you're right on, you're asking all of the right questions. We do need to produce the Newport wells for an extended period of time, and monitor the pressure as we -- as we do that. We have conducted some early and very meaningful reservoir draw -- build up and draw down tests, or draw down and build up, and we don't have all of that analysis in just yet. There's no question to us right now that we don't know exactly how those -- that field will decline. We haven't fully appraised it yet. If we were -- you know, this is just basic, you know, speculation on my part --I've got to be careful when I speculate. If we were to produce these at very high rates, I, of course, would expect a very high decline. But given that we're starting these out at low rates, as Joe noted, I wouldn't anticipate much of a decline, given the information I have right now.

Again, I've got to further delineate. I think in the comments we've given you, we also have drilled down dip and found more oil, so we need to drill further down dip. And to the extent that that production goes into the central facilities right now of the Lake Washington field, it does have some pressure issues where it can potentially back out existing production. So we're having to bring that in slowly and make sure we optimize. One of the things we have had to do is, again, shut in some other wells that were higher water in order to allow more room at our existing facilities to get the Newport wells in.

So you don't see a -- you know, a one-for-one increases in what you produce at Newport right now into the field, a little bit of an optimization that has to come after you bring them in. But more importantly is this west side facility, in answering your question, and I -- right now, we're going through that. Given the rates that we see on these Newport wells, it won't take very many wells to develop this up and produce it from a production standpoint, but it does take more wells for me to find the down dip water, which, you know, that's what we have to do in order to finalize the bookings.

The number 9 well is further down dip?

Joe?

Yes, the number 9 well is going down dip in the -- in several of the sands, yes.

How many --

-- going to drill another well further down dip. The number 8 well was full to base in the lower sand.

So once again, the number 9 well, which is currently drilling, you don't think that is also -- still hasn't reached the down dip yet? You're already planning for number 8 to test the down dip?

We have another one planned to go even further down dip.

8 is one we have just drilled and are completing. Number 9 is --

We're currently drilling.

It is a little down dip, and also to the north, further in some of these sands, and then we're planning, I think it's 13 --

13.

-- that would follow that, that is further down dip from the number 8 well.

Got it. I think I'll yield in the floor to other people. I've asked too many questions.

Thanks, Rehan.

Your next question is coming from David Adams of Jefferies Company.

Hi, guys, great quarter.

Thank you.

To follow up to the Newport, what do you think the aerial extent of the discovery could be? How far is the number 13, and is that specificly looking for the down dip water contact, or do think it could be further out? What's your seismic information telling you?

Well, again, I'd love to just be able to give you a firm answer on the area. I can't, because we're still appraising it. What I can say is in Lake Washington proper, we've drilled a lot of two-acre reservoirs that had 400 feet of sand, real shallow, gross sand, and we've drilled some four-acre reservoirs, and 10-acre reservoirs when we were basically implementing our shallow drilling program. This is maturely different than the production we brought in in the past. Here we are looking at acreage compliments that are ten times that amount, something maybe 20 times that amount. We need to work forward on that.

We clearly have delineated what we believe is the top of the reservoir, or the acreage that's in the top and we don't find a gas cap. It's just full of oil, and as we prosecute our drilling down dip, you know, just gut check on the thing. You know, I'm pretty sure we're well over -- my gut check is we're well over 100 acres and moving out. Be careful how you use that.

I'm just trying to give you an understanding of acreage in the area. So it doesn't take very much acreage to have a lot of oil at these depths, and in particular, one also needs to know these are stacked pays, and there's a very high dip angle here, a very large oil column that we're seeing, and by traditional measures, oil columns aren't generally this high. So that gave some folks pause early on, but we've now proven that we've got an extensive oil column.

Okay. And then you said you expect to exit the year with the field producing 18,500 barrels a day net. What's gross, and assuming you continue to have success, at what point do you meet, you know, capacity prior to the expansion on the west side of the field, and what is that capacity in your eyes?

Well, Scott 's working up getting the number itself, but I would say that -- you know, we are firmly of the opinion, we're going to have to have that west side facility. It's all a matter of how big we build it right now, and we know the initial footprint has to be at least 10,000 barrels a day in new capacity out there, but all the effort is under way to get the bigger numbers in front of us so that we can marginally increase whatever we start with.

You know, that 18,500 is going to be roughly 23,500 barrels a day gross.

And what is capacity right now?

Well, capacity is not an easy answer, because it depends on some many variables; fluid capacity, gas production capacity, where the wells are coming from, the type of crude oil, the different pressures. You know, it's a system, and there are many, many variables to that, you know. This is Terry, I'll give you a A number and then I'll qualify it a bunch of different ways. We think we've got about 27,000 barrels a day of capacity in the existing central facilities on three different platforms in Lake Washington.

The conditions of which, or the parameters of which is how much water are you trying to put through those facilities? You try to put a lot of water through, you diminish your ability to get to that 27,000. If you have high gas cut in your wells, you diminish, again,your ability to have to use facilities otherwise. We're using a significant amounts of our platform space for testing of wells. We have to test these wells monthly, and we're doing that very rigorously. And that's a good thing, because it helps us know what quality out there, but it means that all of that deck space and a lot of that piping is used for testing, and not actually production of sales.

Okay. And speaking of test rate, what was the Bondi test rate?

We just did an extensive 14-day production test on it, and it averaged about 600 barrels a day, and two million cubic feet a day.

And I want to stress again just for those that are listening, when we talk about capacity in Lake Washington, I'm talking about gross numbers.

And then one more question, I promise. Can you give us more details on the new New Zealand gas contract in terms of price and volumes?

I cannot give you any details, certainly in terms of price and volumes, as the terms of the contracts in New Zealand are confidential, a very competitive market and only a few players, and so we're not really in a position to do that. But it's actually a pretty important renegotiation. We had previously had two contracts in the Rumu-Kauri area. One was a longer -- I think was originally a ten-year contract that we signed back in 2002 at a lower price.

It was the initial one to get the Rumu production up and running. And then we signed a new one following the Kauri discovery that was hirer price, but it was three-year contract. That one actually was expiring in July, which prompted the renegotiation, And we cancelled -- well, one contract expired, we cancelled the older contract, combined them into a new contract for 3.5 years, and did get a higher price than we had been receiving in the other contract. And it -- so we're real pleased with what we ended up negotiating and it's with the same party, with Genesis.

Okay. Great. Great quarter, guys.

Thanks.

Your next question is coming from Kent green of Boston American.

Good quarter, fellows.

Thanks, Kent.

The question pertains to -- mostly to New Zealand and the fall-off in production in the quarter due to -- it appears to be, you know, two events that could be special abatements and a lifting, you know, sequence. What is the normal decline rate that you think or is there a decline rate? Are you keeping the decline rate in the total New Zealand assets under control, you know, with the drilling program? And, you know, what is -- in this quarter, you know, what personal of the decline rate came from the two that are non-- or especially non-recurring, or only periodically recurring events?

Well, the lifting was the biggest impact in terms of the production in New Zealand. It probably accounted for wonderful 0.2 to 0.3 Bcf during the quarter, depending on what the lifting might have been had you had it in June. The areas in Tawn are depleted and we've mentioned that for some time. The deep exploration activity there with them Goss and Trapper wells, obviously we're targeting deep gas, which was part of the plan to mitigate some of those declines. Those deeper targets, while they found sands with hydrocarbons in the testing of those, turned out to be noncommercial.

We are evaluating some other opportunities, both in the to [Tariki] sand and in the Key sand area, in the Tawn, as well as looking for other areas in the Tickerangi limestone. That's where the initial activity is going to take place. Down in the Rumu-Kauri area, those sands also declined. The production is predominantly coming from the Kauri sand. As I know you know, we've had some successes in the Kauri sand. We've had some that we drilled in the Kauri sand that weren't successful. We need is continued activity neither the Kauri sand or Tariki sand in that area to provide production to mitigate the decline.

One of the wells that we did drill earlier this year, the Kauri 11, did find a successful -- a nice looking Kauri sands section, but we went deeper and also found a nice Tariki section that we're currently producing out of that actually is more of an oil sand with some gas associated with it. In term terms of the actual percentages rates of decline, I don't have those off the top of my head, Kent. I mean, there's so many moving parts that interact with that, I can't answer that off the top of my head.

Just a general question. Swift has been an evolving, you know, Company, as far as their emphasis, and, of course, obviously we're very pleased with Lake Washington and I know you are, too. And we have a couple of more salt domes that are in the earlier stages, along with, for all practical purposes, three domestic areas, two domestic, and then if you lump New Zealand just in one total area.

What is the most critical features of the Company going forward besides Lake Washington? Would it be, you know, the two -- the two other salt domes, as the potential here? Or is it remains New England -- I mean New Zealand there or is New Zealand kind of dropping in significance here as Washington -- Lake Washington and the two salt domes come up?

That's a great question, and you really did say it well in terms of our diversity. I think it's really important that we focus here on strategy, and the strategy, of course, is to use technologies to -- as our driving force for reserve and production growth. And in using those technologies, we've always been very aggressive with our engineering side, from our frac methods to our directional drilling, horizontal drilling, gravel packs and those kind of things. We have done a wonderful job, we're very proud of the staff, the folks we work with, as we've implemented a 3-D technology program and brought in some extremely high-skilled individuals to do this work. Starting in south Louisiana is where we really have begun the effort.

Lake Washington -- to get more specific about assets, we are not through with Lake Washington. We do see a lot of the growth opportunities still in Lake Washington. There's no question that the early effort was focused in the shallow. We used to refer to that as the low-hanging fruit. I don't think you've heard that in this conference call. There's still a little bit of low-hanging fruit, but we've moved to the middle horizons, and we're now beginning clearly with Newport to find some -- to affirm the seismic effort in the deeper horizon. Bondi, also in the affirmation in the general Lake Washington area, so that's definitely one of the growth areas.

This same 3-D data set, as Bruce mentioned, which approaches 700 or so square miles of integrated proprietary data in the sense of the work -- the process work product and how it's been merged has the Bay de Chene field in it. And again, that's another area of great growth potential for us, so we're highlighting that for that very reason. As you jump out of that data set, and we go over to Cote Blanche Island area we have another large 3-D data set we've been putting together over there. And we've been shooting brand-new data, much the same way we did in Lake Washington, that is proprietary to Swift Energy Company, as it will then be merged in with these greater data sets around the CBI, Cote Blanche Island area.

There's portions of that dome that have never been seen with seismic, never been touched with a drill bit. A lot of drilling opportunity for growth also in CBI. And as we expand in south Louisiana, we're staying on trend with that same strategy, and complimenting that strategy with or historical engineering prowess.

We're also beginning to develop 3-D data sets in south Texas. We see a lot of opportunity. This pricing environment does give us a lot more opportunity. Now, that doesn't take New Zealand off the strategic menu. It's still there.

We have wells drilling in New Zealand right now that we're excited about, both from an engineering standpoint, we're doing what we think are some very innovative things in the Waihapa area, and then we're drilling on 3-D in the Kauri area, and we've shot 3-D, we're processing 3-D in New Zealand. We're applying the same strategy there. A very exciting times for the Company.

Thank you.

Your next question so coming from Adam Leight with Credit Suisse.

Morning, guys.

Morning, Adam.

First, Terry, that was a very nice tribute to Earl, to start off.

Thank you.

A lot has been answered, but I want to follow up on the last question as regards the capital expenditure program. With the incremental CapEx that you've budgeted for this year, can you give us an idea of what the proportional changes throughout the program are going to be? Are you increasing your spending in New Zealand along with the total CapEx? And then for next year, just give us some directional ideas.

I think the proportions are, you know, fairly equitable across the board. I think most of the additionally capital is focused on development and exploration activity domestically. There's a little bit more capital going to New Zealand, probably proportional with what it had. There's not anything that jumps out at you. We just had a number of other opportunities that we've always talked about how we built this discretionary spending wedge into our budget plan. You know, plan on the low side in case prices go against you, but have designated projects that you know can bring capital to quickly and have those projects ready.

Obviously, with the price environment that we've seen, particularly on the oil side, we're well ahead of budget from the standpoint of earnings and cash flow. We used a $50 oil price, and a $6.50 gas price in our budget, so we're really in good shape, and we've got great opportunities. The other thing that's happened, obviously, is we've continued to drill in the southern Louisiana area and had success, and it'll recalibrate that seismic. Work the seismic in Bay de Chene. We've come up with some very interesting, very impactful exploration projects. It's taken some time to do permitting, and in some cases we have to do some drudging and stuff, but we're going to drill some pretty exciting wells there, as well. And as a consequence of that, and increased levels in cash flow and the outlook, we've increased the capital budget with predominantly drilling and exploration activity.

In terms of the '07 plan, that's where we're at right now. We're in our '07 budgeting cycle right now, and we need to work through that. The teams are coming up with a lot of great projects, as they always do. They all want more money than we're going to give them, and so we end up having to scale that capital allocation back, but we're in that process right now from

And how much of this year's numbers approximately targeted for Newport?

Oh, gosh, I don't have that number off the top of my head.

That's a great question, and they're running their numbers here in the background. There is a little bit of flexibility in that Newport number, for two reasons, is obviously as we keep drilling down dip, we're not going to stop drilling wells, So I think we had two to three wells planned in addition to what we had drilled last year, and then we had contingency or discretionary funds for additional wells, depending on how that appraisal worked out by year-end.

There's also the west side facility. We've already dedicated a certain amount of funds to finish up the design work there, and do those things that go ahead and get the project underway. The majority of all of that -- or the vast majority of all of that capital commitment would come in 2007. There's probably about somewhere between $5 to $7 million just on facilities side that has been added to that project. So two to three wells --

Probably for the year, we'll end up spending $30 to $35 million in the Newport area, as a rough estimate.

Yes.

Okay. Great. Thank you very much.

Thanks, Adam.

[OPERATOR INSTRUCTIONS] We have a follow-up from Rashid Rehan of Friedman Billings.

Bruce, you had mentioned eight to ten wells in Lake Washington, two to three in Newport. Were the remainder shallower wells?

It's actually a mixture of wells. Joe, you want to give us a little more color on that

It really depends on rig availability. We have one rig that can drill deep wells is drilling in the Newport area, and it'll stay there the rest of the year. And we have another rig that's capable of drilling to about 12,000 feet, and it'll stay in Lake Washington the rest of the year. We'll have three more barge rigs in the fourth quarter working in the field, and depending on where we decide to place them, if one goes back to Lake Washington, we could be drilling some deeper prospects later in the year in Lake Washington.

Okay. And Bay de Chene, the two high-impact wells, should we expect to hear something on those in the third quarter or the fourth quarter?

Oh, probably the end of the fourth. One of them is relatively deep, probably take 60 to 90 days to drill.

Okay. So we shouldn't expect results of those sometime early next year?

Or the end of the year.

And how many more in the Cote Blanche Island area?

A lot of this gets back to Joe's answer earlier. It does depend on rig availability. One of the nice things that we've possessed ourselves for is lots of flexibility. You know, we have wells we can drill in Cote Blanche Island, Bay de Chene, and Lake Washington. It depends on weather, it depends on tides, where you can get in the barge in. You know, it depends on the rigs.

There's a lot of variables to that, and so I hesitate to be very specific. I think if we had our druthers, we'd be spending most of the time in lake Washington and Bay de Chene this year. Because although we do have a lot of nice targets in Cote Blanche Island, we'd rather get them process queued and interpret that before we do some additional drilling projects.

Bruce has said it well, but I will reiterate. We've drilled a couple of wells in there already. That's been very helpful, both in terms of getting production opportunities, as well as some new reserve looks in there, and we want to integrate that in with the 3-D that's being processed right now. We have a rig in the field right now finishing up another well, and as Bruce says, we've got the flexibility to be come back in there, but we do want to do the smart thing, and make sure that the data that we've just recently acquired doesn't, you know, suggest that we should spot a well in a slightly different spot.

Go you. And one quick mechanical question. The state allowables, did we say it's 4,000 barrel day? I thought it was closer to 1,500.

Yes, the way the state allowables work in Louisiana, it's kind of an interesting story, actually, that I've found out more about is many years ago, they created allowables. And with oil wells, which are different than gas, they created a rule that said that allowables would be roughly 100 barrels per thousand feet of depth. So, 11,000 barrels a day would be roughly 1,100 barrels a day. At the time they were doing this, they figured in the state of Louisiana that wasn't any constraint at all, because they did have not wells that produced at those rates.

We think the test on the number 10 well is perhaps the most productive tested well in the state of Louisiana in 50 years. But in the process of Newport, we ended up creating units, and that allowed us to go to state and apply for what's called a maximum efficient rate, or MER production rate, which is principally the maximum efficient way to produce that reservoir. And they gave us an MER to 4,000 barrels a day, so that's what we have in that area.

Okay. Thank you.

Thank you.

Your next question is from David Adams with Jefferies Company.

Hi, guys, another follow up here. What's your thought process of hedge some of your oil volumes through '07. You mentioned you're going to plan for lower oil prices. What would keep you from putting some costless collars in and accelerate present value?

We've had a price risk management strategy, or hedging strategy in place for well over a decade in the 15 years of Swift Energy Company. That strategy has been premised around protecting the downside without giving away the upside. We think in looking at that strategy in the rear view mirror, we've been very successful with that strategy. We don't see change in that strategy.

That strategy would have us implement things through protecting the down side by generally buying floors. We have done on occasion collars, but they've been participating collars, generally where we keep some of the upside, and generally we've kept 60% of the upside. And that's a strategy we would continue to implement, and I think that's what you should look for us to do, as we continue to move forward. You can see we've clearly taken advantage of the strong crude oil market and protected third and fourth quarter very well, and we'll be moving into '07 in the same method.

Okay. And can you guys give us any more color in terms of the size and the type of prospects or the high potential prospects at Bay de Chene that you'll drill in the second half of the year?

Dave, that's a good question. We have tried to stay away from getting people focused on particular prospects or particular sizes. We think it's much more important to look at the Company's portfolio in southern Louisiana and the results that we get from that. And that's just the position we've taken. We -- what I would tell you is we're incredibly excited. We think Bay de Chene will be a very notable field, a very impactful opportunity there. We think we'll be facilities constrained, as we were there in Lake Washington, and have to continue to add to facilities, but it does take time.

It takes time to develop those prospects, to permit them, to get the rigs. It takes time to drill them, and then you've got to test them and produce them for a while before you have greater levels of confidence. But that's our sense in Bay de Chene. We see a very good picture. The seismic there has gotten us incredibly excited. We're just beginning that program. I wouldn't want people to get too far out ahead of worrying about a particular prospect one from the other.

Okay. Thanks.

Your next question is coming from Evan Templeton of Jefferies and Company.

Hi, guys. Real nice quarter. A couple of questions for you. Just relating to, I guess the dry holes in the government wells sand at AWP, and also just the Alaska dry hole. Can you just comment on those and kind of tell us what we should take away from those?

Yes, I -- or we'll let Joe talk about the government well sand. It was an idea that we had.

In there's some shallow production around AWP field, and so we did some work looking at some of these shallow sands -- and I'm speaking around a thousand feet deep -- so we picked five wells we thought had potential in these government well sands, and so we drilled these five very inexpensive shallow wells. Unfortunately, we didn't find any pay, but overall, all five wells cost less than $100,000 to drill and plug.

Yes, it was an idea, it was a good idea, didn't spend a lot of money on it. You know, we've encountered that shallow sand before in some of our drilling in AWP, or is that production in places didn't work, but we didn't spend much money on it. With regard to your other question, Alaska. You know, Alaska's really a strategic decision for us in terms of entering a new area. It fits our strategy very well. It fits what we've articulated in the past of things we like to look for; a large acreage position, something we where we could have a retrieval method of operation there, if we're successful. Good markets, low political risk, good economy, good infrastructure, both in terms of economic and as well as energy infrastructure. It's a basin that we believe is very prolific. but is under-exploited.

As you probably know, the Cook Inlet was, at one time, the hot area in Alaska, but with have the discovery of Prudhoe Bay, the majors shifted everything up there, and the Cook Inlet essentially got ignored. Also much of the Cook Inlet is in the water, and the environmentalists have played havoc with the people in the water. Swift built the position up there by farming into a position at Aurora Oil and Gas and created over 5,000 acres. It's all on shore. There's both oil prospects and gas prospects in it. The first prospect that we drilled was the Endeavor prospect. It was a very high-impact oil prospect. We thought it had a very good shot. We were obviously disappointed in it, but we ended up drilling exactly what we thought. We had a very good sand, very good structure. It just wasn't charged with hydrocarbons. The migration paths that we had thought might have existed to charge it with hydrocarbons, obviously weren't there. But it's certainly not the only reason we went to Alaska. We're currently working with the our partner right now to plan the 2007 budget.

And just ballpark, can you give me an idea of whether it's dollar amount or number of wells you might anticipate, just so I have an idea of the magnitude?

For '07

Yes.

We haven't made that decision yet. We're just in the process of working that. I mean, we kind of right in the middle of our '07 budget cycle..

Okay, fair enough. Thank you.

There appear to be no further questions at this time. I would like to turn the floor back over to management for any closing remarks.

Thanks everybody for listening in on the call today. We certainly appreciate the interest and the support.

Thank you. This concludes today's Swift Energy second quarter earnings conference call. You may now disconnect your lines at this time, and have a wonderful day.