SilverBow Resources Inc (SBOW) 2006 Q3 法說會逐字稿

Good morning, ladies and gentlemen. My name is Tiara, and I will be your conference operator today. At this time I would like to welcome everyone to the Swift Energy third 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 period. [OPERATOR INSTRUCTIONS] Thank you.

It is now my pleasure to turn the floor over to your host, Mr. Scott Espenshade, Director of Corporate Development and Investor Relations. Sir, you may begin your conference.

Good morning. I'm Scott Espenshade, Director of Corporate Development and Investor Relations, and I would like to welcome everyone to Swift Energy's third quarter 2006 earnings conference call. 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 third 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 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 have allowed ample time for questions. With that, I would like to turn it over to Terry.

Thanks, Scott. And thank you, again, for joining this morning's conference call. I'm pleased to report that Swift Energy Company had record production and earnings for the third quarter 2006, showcasing the opportunities and embedded value of our operations. A year ago, our momentum was challenged. We needed to focus on a hurricane recovery effort. Our folks have done an outstanding job. Today, we can say that the storms of 2005 are behind us, and our momentum is restored.

Our continued success in Lake Washington, and more specifically in the Newport and Bondi areas, should demonstrate that our organic growth efforts are adding shareholder value. These drill bit successes are the direct result of subsurface, integrated geology, and geophysics activities, based on our 3D seismic data sets. Our longer term strategic initiatives, which we began to implement in 2002, are continuing to create new 3D opportunities for the Company, which we exploit and develop and add to the existing inventory.

In addition to our organic growth efforts, we continue to add strategic acquisitions. The recent acquisition of the BP properties in south Louisiana, and the consolidation of acquisition interests in the South Bearhead Creek Field are such examples of our strategic acquisition effort. Through these activities, we have been diversifying our portfolio of assets. But more importantly, adding strategic anchor assets in a very productive fairway that should benefit Swift Energy Company for many years to come. We continue to apply the technical expertise of our talented staff, and expect to grow through the drill bit and through acquisitions. We are very excited about the increasing potential of our developing opportunity set.

We believe that Swift Energy is in a very enviable position to face the ever-present uncertainty of the commodity markets. First, we strengthened our balance sheet. Second, we've built a large regional 3D seismic data set that has helped us to create deep value through 3D seismic prospects, in a very productive province that we believe can deliver strong economic returns.

Lastly, our folks have been executing and delivering on our plans, which of course has led to significant production growth. The Lake Washington field averaged 18,500 net barrels of oil per day of production during the third quarter. This was our planned exit rate for 2006. So we're particularly pleased to have averaged this rate ahead of our schedule. As a result of activity to date, as well as our recent Louisiana acquisitions, we are increasing our 2006 annual production guidance to a range of 70 to 71 Bcf equivalent from our previous guidance of 68 to 70.5 Bcf equivalent for the year.

In the fourth quarter of 2006, and throughout 2007, our south Louisiana drilling program will continue to target material exploration projects. We will also begin to explore and exploit the recently acquired properties in south Louisiana. We also expect to increase our activity, using recently processed 3D seismic data at Bay de Chene in early 2007, and newly-acquired 3D seismic data in Cote Blanche Island in late 2007.

Swift Energy plans to spud some impactful seismic-generated exploration projects in Bay de Chene in the fourth quarter of 2006, with results expected in 2007. If successful, these wells will help confirm the seismic interpretations for this area, and should also help further de-risk similar opportunities in other fault blocks associated with the same salt feature in Bay de Chene. The process data from the new seismic that we acquired in Cote Blanche Island will be delivered during the fourth quarter. We expect to begin benefiting from this new 3D data with our drilling programs in the latter half of 2007.

We should also note that we expect many more opportunities out of our data sets, especially in Lake Washington. We expect the first set of our pre-stacked depth migration from our Lake Washington 3D data, to be completed in the next month. This PSD seismic project will also help us understand Newport's deeper subsalt potential, as well as the overall opportunities that we believe are ever-present in the deeper horizons of Lake Washington.

As Swift Energy continues to execute its 2006 plan, we believe our activity and the results will lead to further visible shareholder value. Swift Energy is in the midst of our 2007 capital planning, and is keenly aware of the importance that this winter could hold in the 2007 commodity pricing. For budgeting purposes, we have once again used conservative price decks. With approximately 70% of our production coming from crude oil, we are less impacted by short term natural gas price decreases than we were in the past. We are taking appropriate steps to execute on the opportunities from our portfolio, and continue to look for strategic investments as they avail themselves.

Our opportunity set for reserves and production growth is the best in the history of our Company. South Louisiana 2007 plans call for more wells than last year, which should be significant. Not only for production, but also reserve growth, especially in Lake Washington, Bay de Chene, and Cote Blanche Island. With that, I would like to turn to Alton, and have him present the 2006 financial results for the third quarter.

Thank you, Terry, and good morning, everyone. Very proud to report that the Swift Energy team set yet another record for earnings during the third quarter of 2006. Revenues were $173.5 million, up 72%, over 3Q '05. Net income set a Company record of $50.8 million, up 85%, and diluted EPS increased 82% to $1.68, while cash flow before working capital changes increased 78% per diluted share, to $4.10. Global production increased 39% to a record 18.8 Bcf equivalent, while domestic production actually rose 67% when compared to the same period in '05.

Crude oil prices stayed strong during the quarter, and as Terry mentioned, was 71% of Swift's production for 3Q '06 coming from crude oil and liquids. The current oil pricing environment continued to have a very favorable effect on Swift's financial results. Swift's average composite realized price for 3Q '06 increased 24% to $9.24 per Mcfe versus 2005. And domestic composite prices actually averaged over $10 per Mcfe, up 13% from the prior year, with crude oil averaging over $69 per barrel for 3Q '06.

The results. A 72% increase in oil and gas revenues over last year. We continue to stay very focused on per unit cost and metrics, especially in this current pricing environment. And specific to the third quarter of 2006, G&A, including the 123R stock option expensing, came in at $0.43 per unit, which was below our guidance. DD&A per unit came in at $2.45, in line with guidance.

Production costs actually came in at $0.69 per unit, well below our guidance, although a portion of this was due to the timing of hurricane-related insurance reimbursements. And while production costs are increasing across our sector due to tight industry conditions, it should be noted that production costs for 3Q '06 for Swift would have been in line with our guidance, excluding this insurance settlement. Production taxes increased in tandem with higher prices in Swift's production mix, and interest expense came in at $0.31, slightly below our guidance. We therefore realized net income of $50.8 million, $1.74 basic, and $1.68 diluted, again, beating the First Call mean estimate.

Cash flow before working capital changes for 3Q '06 came in at a record $123.9 million, or $4.10 per diluted share, while EBITDA was $134 million for the quarter. The results for the 9-month period were equally impressive, for virtually the same reasons as discussed for 3Q '06. CapEx for the third quarter was $107 million, well within our cash flow from operations, allowing us to increase our cash balance at quarter end to $95 million. But a lot has changed since September 30th.

Although we've accessed our bank line since quarter end to fund the acquisition activities, to echo Terry's opening remarks, we have plenty of available capital for any additional value adding strategic opportunities that avail themselves. Our line of credit -- actually the drawdowns on it fluctuate daily, as you can imagine. But to give you an idea, as of close of business yesterday, November 1st, we had a drawdown balance of only $39 million, with all of the activity we've had since quarter end.

With respect to Swift Energy's hedging activity, we have oil price floors in place for October through December, 2006, production, with an average strike price of approximately $64. You should see our website for more detailed information. And as always, we've included additional financial and operational information in our press release, including revised guidance, as Terry mentioned, for the fourth quarter and full-year 2006.

This year is shaping up to be the best year ever in Swift's 27-plus year history. We've had a great 9 months, and the rest of 2006 looks strong. But we are just as excited about what we see on the horizon. And with more on that, I will turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton. And good morning, everybody. Today, I want to discuss third quarter 2006 production, our recent drilling results in our core operating areas, and Swift Energy's plans for the fourth quarter of this year. Swift Energy's record production during the third quarter of 2006 totaled 18.8 billion cubic feet equivalent, an increase of 39% from the 13.5 billion cubic feet equivalent produced in the the same quarter of 2005, which was impacted by hurricanes last year.

The record production this quarter was an increase of 15%, when compared to production in the immediately preceding quarter of this year. Third quarter 2006 domestic production increased 67% to a record 15.2 billion cubic feet equivalent, from the 9.1 billion cubic feet equivalent produced in the hurricane-affected third quarter in 2005, primarily due to increased production from the south Louisiana region.

Due to the hurricanes last year, approximately 2.9 to 3.1 billion cubic feet equivalent of domestic production was deferred from the third quarter of 2005. Third quarter 2006 domestic production was also 16% higher than the comparable production in the second quarter of 2006, principally due to the higher levels of production from the Newport area in the Lake Washington Field.

Third quarter 2006 New Zealand production of 3.5 billion cubic feet equivalent decreased 19% from production in the same quarter in 2005, but increased 12% from levels in the prior quarter, primarily due to an additional crude oil lifting occurring in the third quarter of 2006, as compared to the second quarter. As for our drilling results, Swift Energy successfully completed 11 of 14 wells in the third quarter of 2006, including 9 of 11 domestic development wells drilled, for a success rate of 82% for the quarter.

Let me briefly review our activity in each of our core operating areas, beginning with our south Louisiana region, where production during the third quarter of 2006 averaged 19,000 net barrels of oil equivalent per day, or 114 million cubic feet equivalent per day, in Lake Washington. This compared to our second quarter 2006 average net production of 16,600 barrels of oil equivalent per day, or 99 million cubic feet equivalent per day.

As Terry mentioned, this rate surpasses our projected year-end exit rate of 18,500 barrels of oil equivalent per day. I should note that early in the fourth quarter, we were producing at a reduced rate in the Lake Washington area, due to a third party natural gas pipeline maintenance project, which did constrain our output for about 10 days. This is reflected in our production guidance for the fourth quarter and full year.

The fourth well at the Newport prospect, the state lease 17990 number 8 well was completed and tested in 3 separate zones, and is undergoing production testing for reservoir engineering data in each of these 3 zones to obtain additional production and pressure data. A fifth well at the Newport prospect, the state lease 17990 number 9, was drilled and completed in the third quarter of 2006.

This well encountered 5 distinct sands with 327 feet of net pay, that's true vertical depth net pay, with 52 feet of net pay in a newly encountered sand, and had a maximum production test rate of 7,989 barrels of oil equivalent per day, on a 48/64 inch choke with a flow and tubing pressure of 1,969 psi. This newly encountered sand is located just below the set of 4 other sands previously encountered or seen in the Newport prospect.

The Company is currently drilling the state lease 18907 number 2 well in the Newport prospect, and plans to drill 1 more operated well at Newport in 2006. Additionally, a non-operated well, with state lease 990 -- 17990 number 1, which Swift Energy has a 50% working interest in the completed horizon, was successfully drilled and completed in a recently formed unit in the Newport area south of where our operated area is in Newport, and is producing greater than 1,000 barrels of oil equivalent per day.

Swift Energy also has a 50% working interest in another non-operated well currently being drilled in the unitized horizons at Newport in this same unitized area, with at least 1 more non-operated well expected to be drilled this year. In order to help handle the expanding production at Lake Washington, Swift Energy has begun the early planning for a fourth platform on the west side of the field. It is anticipated that this facility will cost approximately $50 million, and will be available by mid-2008. The new facility will add approximately 10,000 barrels a day of capacity.

The Bay de Chene and Cote Blanche Island fields averaged approximately 11.5 million cubic feet per day of production in the third quarter. This is about 3 times the rate of production from when we acquired these fields. In the Company's south Louisiana region, Swift Energy successfully completed 5 of 7 development wells.

We successfully completed 4 of 5 development wells in the lake Washington area, which includes a successful non-operated well. Swift Energy also completed 2 of 2 development wells in Cote Blanche Island, and had 1 unsuccessful well in Bay de Chene. 3 rigs are currently drilling in Bay de Chene, and the remaining 1 is located in the lake Washington area. A fifth barge rig has been contracted, and will arrive in the field late in the fourth quarter. Additionally, there is the rig drilling the non-operated well in lake Washington.

Our plans for the remainder of 2006 call for Swift Energy to drill 4 additional wells in the Lake Washington area. The other major project for the Lake Washington area is the pre-stacked depth migration work that is ongoing, which will enhance our 3D imaging around the salt and for the deeper sand objectives. This new data is expected by the end of of the year. In Bay de Chene, we plan to drill up to 5 additional wells, with at least 2 in Bay de Chene being potential high impact exploration wells. Results are expected from these in 2007.

Swift Energy has closed on the acquisition of certain additional interests, for approximately $9.5 million, of several wells outstanding from the previously announced acquisition of properties from BP America, the majority of which closed on October 2nd. To date, the Company has closed on approximately $169 million worth of properties related to this acquisition. There are a few wells that remain outstanding in this transaction, but fairly insignificant dollar amounts.

In the south Texas region, production in the third quarter of 2006 averaged approximately 21 million cubic feet equivalent per day in the AWP Olmos Field. We successfully completed 3 of 3 development wells targeted in the Olmos sand in the AWP area. The Toledo Bend Region contributed approximately 11 million cubic feet equivalent per day of production in the third quarter of 2006.

Swift Energy has 2 rigs operating in the South Bearhead Creek area in Beauregard Parish, Louisiana. And we expect to drill 2 to 3 wills targeting the Wilcox in the fourth of this year. Additionally, the Company has acquired virtually all of the outstanding interest in the South Bearhead Creek Field from undisclosed sellers. Approximately 5.2 billion cubic feet equivalent of reserves were acquired for $4.5 million effective November 1st, 2006. Swift Energy now has nearly 100% of the working interest in the South Bearhead Creek Field.

Our operating region in New Zealand produced 3.5 billion cubic feet equivalent in the third quarter 2006, and was with approximately 19 million cubic feet equivalent from both the TAWN area and the Rimu/Kauri area. The third quarter increase in production was primarily due to additional crude oil liftings occurring in the quarter. For the third quarter of 2006, New Zealand accounted for approximately 19% of Swift Energy's total production.

During the second quarter 2006, there were only 2 tanker liftings, while we typically expect 3 or 4 per quarter. A lifting occurred in early July, that was accounted for as sales in the third quarter. But the production was -- actually came from the second quarter. During the third quarter of 2006, we had 4 crude oil lifts. As a reminder, Swift Energy's crude oil production in New Zealand is not recorded until the sale has occurred, as the timing of the liftings can have an impact on our reported sales of production. But this does average out quarter to quarter.

During the third quarter, the Company was successful on 1 of 3 wells drilled, and suspended operations on another one of these. The Company drilled 2 wells targeting the Tikorangi limestone formation in the TAWN area, and completed the Waihapa H-1 well, which is currently on production. The Waihapa 4 oil was suspended for mechanical reasons until next year. The Kowhai-A1 exploration well was drilled on petroleum exploration permit 38742 in the northern Taranaki Basin, and was unsuccessful. The Trapper A-1 well, which had previously been plugged back from non-commercial [inaudible] was planned to be completed in the Tikorangi formation, but is now being plugged and abandoned due to mechanical reasons.

Plans are underway to complete the Goss well in the Tikorangi formation for testing and evaluation. We continue to believe that there is a significant potential in the TAWN area, but with the complex geology in this area, we clearly need to utilize 3D seismic technology so that we can target the better areas of prospectivity. As a result, in 2007 we currently plan to acquire some 3D seismic in the TAWN area to better map the complex geology in this region. Thanks for your attention. And I will turn it back to Terry to recap.

Thanks, Bruce. Before we open it up for questions, I want to reiterate Swift Energy's exceptional performance thus far in 2006, and review a few of the third quarter highlights. But I would also like to once again note that a year ago, our momentum had been challenged by 2 very significant hurricanes, Hurricane Katrina, and Rita. And that our effort a year ago was focused on the recovery.

Today, I can say with great pride that our folks did an outstanding job in the recovery, and the Company has restored its momentum. Swift Energy Company had impressive financial results in the third quarter. We've announced earnings that increased 85% to a record 50 million -- $50.8 million. We've announced production increases of 39% to a record of 18.8 Bcf equivalent. These results all lead directly to increased shareholder value, and further solidify our balance sheet.

There is also no doubt that as a result of the continuing momentum and the activity to date, our recent Louisiana acquisitions, as well, we're increasing our 2006 annual production guidance to 70 to 71 Bcf equivalent from our previous guidance of 68 to 70.5 Bcf equivalent. Swift is drilling deeper, higher impact prospects, especially in Lake Washington and especially in our Newport and Bondi areas. We will also plan to drill deeper in Bay de Chene and Cote Blanche Island next year.

These deeper wells will target material reserves and production growth opportunities which have been developed using our 3D data sets. Finally, we continue to have a strong and flexible financial position, which allows us to take advantage of future strategic opportunities, whether they be 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.

[OPERATOR INSTRUCTIONS] Rehan Rashid, Friedman, Billings.

Congratulations on a great quarter here. Questions on Lake Washington, Newport. So the number 9 well and number 8 well, what does it suggest? Have you found the down dip water leg yet?

Bruce, do you want to take that? While Bruce is putting the information together, we have found a lot of new things, as we've drilled out Newport. I would say that it has been more complex than we would like. But that complexity has given us more oil pays in different sands.

So as we work through these additional oil pays, and as we correlate them into the seismic, it is particularly important that we use this depth migration activity, or seismic work that we're doing, and get good correlation. We have found some water contacts out there, but it would not be appropriate to say we found them all.

I think we continue to be incredibly impressed andI think we continue to be incredibly impressed and pleased with the development at Newport. There are a number of sands there. I think there is one sand that we have found the water leg in. But that is the only one that we can address specifically. The work is ongoing. We have continued drilling in the area, continued correlation of the different sands, as well with the subsurface geology, and with the seismic. The exciting thing, obviously, is you continue to find new sand, continue to expand the breadth of those -- of the productivity of the sands.

The test rates obviously, as you can see, [inaudible] by the number 9 well are incredibly impressive. Now, those are test rates, that's not what we're producing it at. But we are continuing to do a significant amount of reservoir engineering work to understand the reservoirs. And that work is going to go on for some time, and -- but overall, I would tell you we're very, very pleased with that development of Newport. We continue to see additional drilling opportunities. And this is just that area around the 11, 12,000, 13,000-foot depth horizon, and we mentioned earlier that we're working on the pre-stack depth migration. We're excited about the early work we're seeing on that. That's going to help us a lot, particularly with regard to the deeper prospects. We continue to believe that there is a significant prospective area below Newport in a deeper area.

This is Terry. I am going to give just a little bit more color to that, so that I'm not missing anything here. There are at least 6 different productive sand horizons in this area. And it is also important to note that while we have drilled, let's just say substantially down dip for some of those sands and we have found water in some of them, substantially down dip, that doesn't necessarily mean we found the oil water contact. We have found the oil water contact in a couple of sands, but we still have a few other sands we have not found it in.

Now, why am I not going to the specifics of the sand? Of these 6 sands, we do expect to find even a few other sands. We're looking for some other deeper sands in the area that we think are there, given the seismic information that we have. And it is also important to note that we have created 2 units in the area, or there's 2 areas that have been unitized. And within those areas, there are 2 unitized horizons. And in the southern most portion of that area, there are unitized horizons where we share interest with another operator at 50% in those 2 unitized horizons. Not all of the sands that we've seen out there in Newport area by any means.

Okay. The number 8 well, I would have thought that we would have had some production test rates on these already, that you could talk about. Any thoughts on that front? Am I right in thinking that? And if so, maybe some thoughts as to what were the rates that were already tested? And what is exactly meant by saying that we are testing for reservoir engineering data?

Well, we do have some rates on those, but rather than -- what we don't have, is we don't have the entire sand opened up. This was o1 ne particular sand that had 3 lobes in it. And so we chose to make 3 separate completions, each with a sliding sleeve, and so that we could evaluate the different lobes and also understand whether there was communication with other wells in the area, as well as the different lobes. And that testing is still ongoing with regard to the 3 different lobes.

The meaningful test information is going to be when we open up all 3 lobes to production. And that has not happened yet. And what we're trying to do is collect as much data as we can to understand the breadth, the extent of all of these reservoirs.

Right.

I guess what I would tell you is that the productivity of the sand that we've made these 3 different completions in this 1 sand is very similar, or we would expect the combined rates to be very similar to what we've seen in the other wells.

Okay. The post-stack depth -- my pre-stack depth migration studies, if you could take a step back and kind of walk us through as to what exactly -- I know we attempted this. But I'm not catching on to it. What exactly is this -- will this do for the Newport, call it shallower discoveries, what will it do for the deeper? And then what about the sub-salt and when would you plan to drill the Newport deep and the sub-salt?

Those are great questions. And certainly, for folks that have a technical knowledge, I think the answer I will give may fit pretty well, but I don't want to try to go into too much technical detail.

Sure.

The depth migration is absolutely necessary for anything that you might want to target under salt. There is just no question. We can't do a proper job of imaging and doing our structure maps for anything that would be sub-salt until that work is done. That is important for folks to know. But also, in terms of being near salt, do you have some reflection issues, particularly where you have what we call salt ledges. Sometimes the salt is not perfectly smooth, as you come off this dome, and have you salt ledges, so you get salt overhangs. And any place that you either have a salt overhang, or where you have what they call changes in velocity gradients in the area, this depth migration will help us do a really good job of understanding our geometry for the deeper sands in Newport, as well as any prospects that are underneath the salt, or underneath the salt overhang. As for the shallow zones in Newport, and a couple of the sands we've seen in that area, we don't expect very much change at all from this work, as in relation to those shallow zones.

Okay. And 1 last question for me. The Bay de Chene, the high impact well I think was named Teton, I think. Is that kind of TD sometime first quarter, is the rough expectation?

We expect -- I mean, we try not to focus on particular wells in any of the fields.

Okay.

Because quite frankly, there is a number of wells that are impactful to different degrees. We're really operating more of the portfolio. But we would expect to spud that particular well by the end of the year, probably in December, more than likely. But it would be at least late to first quarter before we would expect any results on that.

Okay. So we will call it second quarter. Okay. Thank you much.

David Adams, Jefferies & Co.

Great quarter. I missed part of the call, so if you've already addressed this, excuse me. But in terms of -- I believe on the last call, Terry, you said that you expected at least 4% reserve growth in '06. With all of the success that you've had in Lake Washington, would you care to address your expectations now? Is it higher or lower? Or where do we stand?

Well, obviously, what we say is always dependent on the most current information we have, and I would have to go back and look at that. Certainly 4% is a reasonable type of number. We're always shooting for better numbers than that. But we're doing all of that work now, and it would be premature to say we've got a particular percent. We've got a very significant amount of work going on relative to all the drilling we've done, all of the reservoir engineering, all of the production that we've had. We had a great year in production. Of course, that helps us understand the future reserve base, as well.

We have brought a lot of reserves in to service that were in other categories, so you've got both category moves as well. We have had significant acquisitions that have also given us some reserve growth relative to the acquisition effort. We do expect to have a good year in reserves. I probably ought to just leave it at that.

Okay. And then also, looking into 2007, with all of the success in southern Louisiana, I know you said that you're going to purchase 3D seismic in New Zealand. Does that mean you will slow down drilling activities in '07, and maybe focus more capital in your Lake Washington and Newport areas?

Yes, we expect to slow the drilling down a little bit in 2007 in New Zealand. Although the budget has not been approved by the Board yet, we plan to focus both on some field studies, as well as the 3D. But probably we will drill a couple of wells primarily focused in the Tikorangi area up there in the TAWN.

Okay. And then lastly, are there any capacity constraints at Newport currently, aside from your allocation from the state for production?

We actually -- obviously, we're making the decision to move forward with the production platform, which tells you there are facility constraints. We really expect to be facility constrained during 2007. We expect Lake Washington to provide fairly significant production growth year-over-year. But we expect the daily rate to be relatively flat during the year, because of constraint of production capacity out there in the field.

Great. That's a good problem to have. Great quarter.

Yes, I mean it is a real good problem to have. And we've been planning for this production platform for some time. We've done a lot of work and because it takes about a year and a half kind of from beginning to end to get up to speed. And fortunately we've been doing the front end work, and more importantly we appear to have the reservoirs and the drilling opportunity set to support it.

Thanks.

John White, Natexis Bleichroeder.

Well, guys, you got to be excited with these results. On the Lake Washington, your last comment, production you're addressing for '07 is flat due to capacity constraints, or about 19,000 barrels a day?

Well, I didn't say 19,000 barrels a day. But we think it will be relatively flat as we move through the end of the year, and into next year.

Okay. Thanks. And on New Zealand production, your fourth quarter guidance is a little lower. Is that natural decline rates, primarily?

Yes, that is natural decline rates primarily. We really expect the inventory -- ending inventory to be fairly similar to the end of the third quarter, so it shouldn't be impacted by liftings.

Okay. Thanks very much.

Kent Green, Boston American Asset Management.

Great quarter, fellas.

Thanks.

On the Lake Washington Newport wells, are you perforating and testing for multiple zones?

On some of them, we are. I think we've actually announced that in some of the previous results. One of the wells that, I think it was our second Newport well, encountered multiple sands. And we actually made completions and tested in 2 different ones, both of which had over 100 feet of net pay, and I think both sands individually tested close to 4,000 barrels a day equivalent. But in some wells, I think like the number 9, we just completed in the lower sand and tested it. We did not make completions in the upper sands currently, because we would expect to produce that lower sand for some time.

All right. And you would probably produce from the bottom up on those sands?

More than likely.

Instead of producing multiple sands, how is the fall-off rates, Bruce, going to be at those wells? Is it going to be pretty rapid?

Well, actually that's the purpose of all the testing that we're doing right now. Obviously, we've got some very prolific tests, but we don't bring these wells on anywhere near these test amounts. When you see the tests that we have, we will typically bring a well on somewhere between 1,000, 2,000 barrels a day, something like that, if it can support that, into the overall system. We don't want to crowd out other wells.

But to date, we are seeing that some of the sands appear to have some nice water drive, but others do not. But it is premature. That kind of comes back to the reserve questions that we had a little earlier. We have got a very extensive amount of work going on to determine the reserve picture of Newport, both today, and prospectively, both in terms of what we would call the primary system, and how much pressure support we have for that, recovery factors that will be appropriate there, versus what would be referred to as a secondary system, where sometime in the future you would be putting some sort of pressure maintenance in.

Have you given us any guidance on say, how many wells, particularly at Newport, that you might drill? Or are you delineating out at a large fashion here? Or are you just concentrating in one particular smaller area?

You know, we've actually had really good news, as we've done the appraisal of Newport. Initially, we would have anticipated that there probably would have been between 4 to 6 wells that might be appropriate for the area that we're actually doing the drilling in. But we found additional sands out there. And deeper sands. And that is a good complication.

I mentioned it is a little more complicated than we had anticipated, so I think we're going to end up with more wells than we had anticipated. Kind of premature to say. But certainly, it wouldn't be unreasonable to think of having somewhere around 8 to 10 wells out there.

You're not permitted to actually co-mingle distinctly different sands out here. So you have to produce one sand at a time. Now, in the case of that number 9 well that we discussed earlier, there was a single sand, we just happened to make completions in 3 different lobes of that sand. We will be able to produce all 3 of those at the same time, but we wanted to do some individual testing in the different lobes. But in some of these well bores, you have multiple significant sands.

And you can work your way from the bottom up. But it may take a long time in the lower sands, so you may want to come and drill an acceleration well for the shallower sand. But we're obviously not going to do that until you have the facility capacity to produce it. So that is part of the support that goes behind this fourth production facility.

On the 2 other salt lobes, Bay de Chene and Cote Blanche Island, as I recall, you had high expectations for 1 being somewhat similar to Lake Washington. That was Bay de Chene?

Well, I would tell you we have high expectations for both of them. They're just kind of at different stages. Bay de Chene is a little more advanced, because there was an existing 3D chute that we were able to acquire and merge into this large regional data set that we built between Lake Washington and Bay de Chene.

And so we're much further along in terms of interpretation there, and we're at the point now where we're going to begin a fairly aggressive drilling program targeting some of the significant prospects in that area. Based upon what we -- and we're also doing depth -- pre-stack depth migration at Bay de Chene, and that is also not in. But we do see some significant, potentially very significant deeper prospects.

I would add to that, that as we have developed this regional grid of 3D seismic, and done the work in somewhat of a screening fashion, when you find us buying what we are calling anchor assets in this area, it is because we already had an expectation of that. We're just not collecting salt domes out here. We're trying to get the ones that we think have some significant upside opportunity and those are the ones we target.

And just as a follow-up on Cote Blanche Island, that is a little bit -- that is kind of the next step behind, although there was some 3D over Cote Blanche Island, it wasn't of the quality that we felt was useful. So we actually made the decision a year ago to shoot a new 3D over Cote Blanche Island. We also made the decision to acquire a significant additional regional 3D in the area of building a large marginal data set around Cote Blanche Island and Bayou Sale, which we acquired. That 3D is being processed. We expect that processing in before the end of the year.

Based on the -- some of the early returns of that data, it is exceptional quality. We're incredibly excited about what we think we're going to see there. It is going to take us at least the first half of next year to do some interpretation and develop some prospects. One of the things about Cote Blanche Island that we felt, is that's kind of a tilted salt feature that we think has -- may have a significant overhang on the north face that hasn't been exploited as much as the south. And so we think there is some significant potential there as well. It is just kind of the next step. So we're building an inventory of projects that for multiple years ahead of ourselves.

And you also have to understand it has actually taken us several years to get where we are now. So this wonderful pipeline of future projects to drill, but we've also created this tremendous momentum of production, both at Lake Washington, and now you're starting to see the early effects at Bay de Chene and Cote Blanche Island. We're adding in the BP Properties, Bayou Sale, Horseshoe Bayou, Jeanerette, Bayou Penchant, and High Island, than we think are going to continue that same kind of momentum, and continue to fill that pipeline to have an inventory out there for years to come.

Good. Following-up on David's question, with all of this enthusiasm of Louisiana here, does that mean that Toledo Bend and New Zealand has got to take a back seat? And if it takes a back seat for a number of years, could it be that you may want to liquidate or pursue liquidation of those, just so that you can concentrate all of your resources on the salt domes?

Those are great questions, and we really do have a process where we look at all of our assets, core assets, on a regular quarterly basis, and look at the return on capital that we're seeing in each area. And we prospectively look forward at the opportunities there. I think it is real important to realize that we also want to go where the oil is. And not expect oil and gas to just somehow materialize on lease oil that we've had for a while. So yes, we will in the future, from time to time, you will see us divest of something. But there are no plans at present, relative to the areas that you've discussed.

In fact, to the contrary. In New Zealand, we've got some very exciting projects ahead, that are 3D-based projects there, as well, where we've got a large acreage holdings. So we certainly want to make sure that we fully understand how this same strategy and opportunity could yield value in the TAWN area, where we've already seen some nice production results from the [Peacal] well, and the McKee types of sands, we think there is more of that opportunity there. We are going to after it. And then the Kaheru area, we have been shooting 3D seismic there, as well. I'm a Texas boy. And I believe there is a lot of opportunity in Texas, as well. We are -- in our longer term effort, we are focusing in certain areas of Texas. You will see us be buying and acquiring 3D data sets in Texas, as well. So we think that for a Company our size, and with the expectations we have, there is a lot of opportunity out there.

And we're planning work in all of the areas in the 2007 budget. AWP field, many of you heard me for years refer to that as our Rock of Gibraltar. It continues to be this wonderful cash cow. And we expect to continue to maintain it like that. Toledo Bend really added to South Bearhead Creek Field. So we are just beginning to really exploit that property. We are drilling several wells into this year. We had obviously hoped to do that early in the year, but due to the rig availability in the marketplace, we couldn't actually get the rigs to do that until the second half. But that is happening. And actually based on a couple of the wells we drilled, we're pretty excited about what we're finding there.

Obviously not as glamorous as Newport, but it is meaningful stuff. We're -- actually a part of South Bearhead Creek is undergoing a 3D that we will get and look at. We are actually looking at maybe picking up some acreage in the area. So there are interesting things going on there, as well. You often hear us talk about balance and diversity. It is as important in our business as it is in yours. So we continue to plan to maintain a strategy that has balance and diversity in our asset base, and our capital spending reserves, production, cash flow, et cetera.

What are the things that I guess is -- needs maybe a little more elaboration, is the production take away, infrastructure difficulties, because of this higher-than-expected production in Lake Washington? And you might want to enlighten us of whether you're increasing this 50%, 60%, 70%? Even though it is going to take most of 2007 to get this in place?

Well, facility -- I mean, facility capacity at Lake Washington, you're right. We've had some phenomenal success, although we've planned it and expected it. And but you don't want to go and build the capacity until you have confidence in the reservoirs to produce it. But you got to stay sufficiently ahead of it, so that when you develop the productive capacity, you can produce it.

If you go back and look at the very beginning of our development in Lake Washington, it has been like a kind of a leap frog type of thing. Where, when we acquired the field, the capacity was 2,000 barrels a day. We built up productivity, increased that to 4, increased that I think to 8 or 9, increased that to about 19. And today, we think the capacity at Lake Washington for oil, it is going to vary between the time of year, like in the winter with colder water temperatures and a little less than the summer, but I don't like to get into those details. But it is probably roughly 25, 27,000 barrels a day of oil capacity.

Gross.

Gross. That's a gross number. Not a net number. And we're reaching that. And you got to remember, the production that we report and we guide on, which is important, is the average production we are going to get over time, like any piece of equipment, you don't expect to run it at 100% utilization all the time. We probably expect to run it maybe 90%, plus or minus, utilization over a period of time. So we're adding 10,000 of that. So that's, what, about a 40% increase. The facility that we're putting in, like we actually added capacity at CM3 platform, we're actually going to build on barges.

That will actually make it easier to build, because we can build it in the shipyard, float it out there. It will also make it more useful to us, if you ever need to move it to one of our other fields in southern Louisiana. But we're building it in a way with additional deck space, that we could add another processing train for another 10,000 barrels a day. Now, we're not doing that just for kicks. We're doing that because we think there is the potential for productivity either on the oil processing side, or the gas processing side. Certainly as we go deeper sub-salt, you have to get into pretty prolific horizons that may produce a lot of gas. And our gas production right now is maybe limited to 25, 30 million a day. And at some of the deeper horizons, you can hit a single well that can produce at rates like that. So we're looking at those things down the road, as well.

Thank you.

Adam Leight, Credit Suisse.

I think you steadily exhausted almost all of my questions. Nice quarter. The only things I have left, I guess, are on the production facility. Would that come out of your just normal capital spending? Or would you separately finance that? And then, just the perennial, what about '07 hedging?

In terms of the first question, we expect just to finance it as part of our capital budget, normal cash flow, don't see any needs for any particular separate financing for that, or anything in our '07 capital budget at this point in time. In terms of hedging, our hedging strategy, price/risk management strategy, as we tend to think of it, will continue to remain the same as it has been for the last 10 or 15 years. Premised around protecting the down side, without giving away the upside. Implemented primarily through the use of floors.

Occasionally we use collars, and we participate in collars. We will continue to look out three, six, nine, and twelve months for opportunities in the gas and oil markets. We tend to layer them in in tranches. We tend to do it when the market is strong. I would expect, I would tell you to expect us to continue with the same strategy that we have had in place for some time.

So nothing new, and nothing hedged at the moment for '07?

Currently, nothing in '07.

But we've been looking, I will tell you that. We've just been looking for the right opportunity to put something in place. Okay.

We have, I think, presold some production, but that is on the physical side, but not on the hedging side. But nothing of significance.

Great. Thanks.

Sunil Jagwani, Citadel Investments.

Congratulations on a good quarter.

Thank you.

My question was just on these additional discoveries in sands that have you discovered I guess, in your recent wells. How should we be thinking about those and their contribution to reserves? Are they -- are these like PUD locations, or are these going to be additive to reserves?

This is Terry. I'm going to let them take that question. But I wanted to clarify that going back to Adam's question about selling forward, while we have done some deals that are based on index forward, we've not actually presold any actual production. You want to take that question, Bruce?

Yes, if I understand your question, you're asking about the new wells we're drilling at Newport and their impact on reserves. We did have some reserves booked at the beginning of this year, but a very small amount. And without going and looking at specifics, which I would need to look at the detail, I think the vast majority of the new drilling in Newport this year is not -- was not booked at the beginning of the year. So it would be additive to reserves.

And Lake Washington?

Well, in Lake Washington, I mean some of the wells we've drilled would have been PUD, but I think a number of them were also targeted probable possible reserves that weren't booked.

And lastly, I think we talked about a 15% or so increase in capital next year. Now, the capital for '06 has been re-set up a little bit. So should I just be assuming another 15% on top of that from the new base, or -- ?

Well, we've not finalized our budget. The capital, I mean my current -- our current expectations for capital next year is it will be lower than this year, because we had some significant acquisitions this year. And we don't budget acquisitions.

I was talking about excluding acquisitions. Like, I was -- well, to be specific, I had about $475 million in capital next year, previously. And I wondered if that was at least in the ballpark?

Well, I would think that is a little bit high for us going into the year. What we have historically done, and I would expect us to continue to operate with the same strategy, is we use a conservative pricing deck for our capital budget going into the year. And we develop a range of capital spending, with a discretionary wedge that allows us to start at a lower end, and depending upon how physical performance comes out, and financial performance in the way of prices and affects cash flow, we have been able over the last, I think, 5 years to operate that way with an increasing capital budget through the year.

We've generally tried to target our spending to cash flow. And -- but we think it is important to spend realized cash flow as opposed to forecasted cash flow, because that can change. I would expect our capital budget next year to start at a lower range than what you suggest, although it is not approved yet, so it is not finalized. But we would anticipate it moving up through the year, assuming we have good physical performance on the production side, and good pricing environment.

And that would include the platform CapEx also, the 50 million?

Yes.

Okay. Thank you.

[OPERATOR INSTRUCTIONS] Rehan Rashid, Friedman, Billings.

Just on the acquisition, $169 million worth so far, what production are we talking about? And could we kind of -- could you walk us through the thoughts in terms of development exploitation as we progress through next year? How many wells?

I think what we previously guided, and I wouldn't come off of that at this point in time, is we had said I think 0.6 to 1 Bcf for the quarter. We're just closed that and trying to get our hands around it, and trying to take over operations. There is some non-operated production we're trying to get the operators to start giving us that information. But I think that you could carry forward that fourth quarter guidance into next year. That would be my expectation.

In terms of exploitation, yes, when we -- this thing about that acquisition from BP, we had actually targeted, particularly Bayou Sale, as one that we were very desirous of before BP put it on the market. So it fit us perfectly. And we did a really extensive evaluation of that. We were helped because we already had the 3D over 3 of the fields, so it gave us a head start. We were pretty knowledgeable, particularly with regard to Bayou Sale going into it. We see some very interesting prospectivity there in addition to the PUDs. Obviously significant probable possibles.

There are -- some of those, I think most of them are not 100%. So we do have partners we have to deal with. Some of the significant prospectivity in Bayou Sale does have another partner, and we need to get with them and work out a joint plan for that. But I would expect to see us begin important exploitation, certainly of Bayou Sale and Horseshoe Bayou initially, and then focus on some of the other fields, as well.

Another follow-up comment to that, Bayou Sale is not a salt dome per se. But it is a very, very nice, and very productive structure, a very significant accumulation of production from Bayou Sale. We did not acquire all of the deep rights in the Bayou Sale area. In fact, BP retained the deeper rights. Deep is a relative term. We do have some deep rights in there, as we define deep.

As you come off the structure in particular, we have interest in some raw [bell] type of sands. And as we prospect in the area, we've got a lot of expansion and prospectivity on the side of the structure that is down, let's just say, below 15,000 feet, 16, 17,000 feet. So deep in a relative sense, we have to explore and exploit around the dome, but we don't have all of the deep rights in Bayou Sale.

So basically it is safe to assume that any meaningful exploratory work does not take place until at least '08?

I don't know that I would say that. I think we could do some meaningful work next year in the second half of the year.

Okay. That sounds good. And -- yes, that's it. Thank you.

John White, Natexis Bleichroeder.

My question was answered. Again, congratulations on the very nice result.

Thanks, John.

Thank you. There are no further questions at this time.

Well, thanks, everybody, for joining us on the call. We appreciate your support and your attention.

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