SilverBow Resources Inc (SBOW) 2004 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to Swift Energy's third-quarter earnings release teleconference. At this time, all participants have been placed on a listen-only mode, and the floor will be open for questions following the presentation. It is now my pleasure to turn the floor over to your host, Director of Investor Relations, Mr. Scott Espanshade. Sir, you may begin.

Good morning. As Holly mentioned, I'm Scott Espanshade, Director of Investor Relations. I'd like to welcome everyone to Swift Energy's third-quarter earnings conference call. Terry swift, President and CEO, will give an overview; Alton Heckaman, Senior VP and CFO, will review the financial results for the third quarter; Joe D'Amico, Executive Vice President and COO, will cover our domestic operation; and then Bruce Vincent, Executive Vice President of Corporate Development and President of Swift Energy International, will update our New Zealand activity. Terry Swift will then recap the call before we open up to questions.

But first, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us and our industry. 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 20 to 25 minutes, and have allowed additional time for questions. Terry?

Thanks, Scott. And once again, I'd like to thank you for joining our third-quarter 2004 conference call. We're very pleased to announce the results of this quarter. The Company has shown impressive operating and financial success in the third quarter this year. The Company's revenues of $74.9 million have reached a record level for the Company. And this has happened in spite of some recent downturning in prices of oil. But, you know, when you look at $55 oil going back under 50, it's hard to say anything other than we're in a very strong oil market, and it remains strong. In fact, the NYMEX crude oil price for December '04 recently pulled back to just under $50; but the twelve-month strip was still at $48 a barrel. So we're still in very, very premium price territory right now with oil. Same thing on natural gas. It recently settled just under $9; and the strip going forward for 12 months is just under $8. So we see a very robust, exceptional pricing environment, that is well in excess of the budget pricing that we anticipated at the beginning of this year. And in fact, it remains in excess of what we anticipate, or what we'll be planning on for 2005.

We maintain a pretty significant price risk management strategy that focuses on the near-term. We want to make sure that we realize and capture, for the benefit of our shareholders, these higher prices, to the extent that they exist above our budget levels. But at the same time, we use a floor type of approach to protect that downside against serious downturns in commodity pricing. We're going to maintain that strategy through the rest of this year and into 2005. Getting onto the activity that we've actually undertaken this year, it's very high. We have ridge (ph) running in Lake Washington. We'll get into that detail in just a moment. We're working internationally. Our capital expenditures for this year, we believe, are going to come in right between 170 to $180 million at year end, which is very close to the expected cash flows for the year.

Third-quarter revenues -- I'd like to emphasize again, were 43 percent higher than the third quarter a year ago. Quite an achievement for the Company. Alton Heckaman, our CFO, is going to provide more details on that in just a moment.

We continue to focus on our operating results. We want to put the points on the board. Our third-quarter production, which was 13.9 Bcf equivalent represents a 2 percent increase in production from the third quarter of 2003. It's important to continue to realize that our domestic production has been increasing, and we believe will continue to increase. In fact, it increased by 16 percent from the same period a year ago. We estimate that a total, unfortunately, of .7 Bcf equivalent in sales was not realized during the third quarter due to storm-related activities. In particular, we had precautionary shut-ins in our lake Washington area due to Tropical Storm Bonnie and Hurricane Ivan. We consider ourselves very fortunate. Those, of course, were very significant events from a weather perspective, particularly Hurricane Ivan. But the Company is very pleased to say that we are in full operating condition post that event.

We also continue to make important progress in our core areas as relates to the actual production levels. I'd like to focus on the fact that our nine-month average daily production from lake Washington a year ago was 5100 barrels a day equivalent, on a net basis. But this year, our nine-month average daily production in Lake Washington is 9900 barrels of oil equivalent a day.

We're focusing our efforts in Lake Washington in several additional ways. I'd like to go into that in a little bit of detail here, and talk about two of what I would call visible or very apparent value drivers. First and foremost is that we're getting some really high-quality 3-D seismic results in the field. We shot that data in the third quarter of this year. We've been processing that data. We're already beginning to use that data in our programs. It's setting up some really wonderful events going forward. Obviously, it's going to help us with our intermediate depth targets throughout 2005. But it's also going to provide us some insights relative to reservoir management in the field, future facility designs, and additional activity and expansion of what we think is a very vibrant and dynamic opportunity in South Louisiana.

Our technical teams are identifying and evaluating additional oil and gas opportunities in the field beyond our original expectations. I would classify many of the things we're seeing in the potential and probable range right now. So we've got our work cut out ahead of us to bring more value there. But just to show you how confident we are that we'll do that, the geologists had correlated and mapped some of the deeper gas potential that we've been seeing on the north side of the dome. They've been prospecting from that productive north plank of the salt dome all the way around the dome, looking at various untested traps. Depth ranges were in the 7000 to 14,000 range. Typically believing that as we go deeper, we are more likely to find gas. The new 3-D is just giving us a really exceptional view of some of this earlier work, helping us high grade that work and expanding our drilling inventory. We believe that we will have a 3 to 4-year drilling inventory of opportunities, possibly even expanding it to 5 as we finish out this work.

We further enhanced our South Louisiana position recently by acquiring 550 square miles of 3-D data to the west of Lake Washington, and we're in the process of merging this data in with the existing chute that we just accomplished.

Another value driver in Lake Washington, and this can be seen in our facilities expansion program, we're planning further expansion of the two platforms in the field, maybe even an additional platform. The expansion in particular needs to occur at the CM3 Platform, which processes our sour crude oil, and is currently at or very near capacity. We also will be expanding the 6700 platform and installing additional compression throughout the field for our gas lift system.

I'd like to also note with great pride that we've already surpassed our year-end exit rate goal for the field, which was 12,000 net barrels of oil a day equivalent of production from Lake Washington. In lake Washington, we have averaged, for the month of October, 12,500 barrels of oil equivalent per day.

We've curtailed some of the shallow drilling program here at year-end in favor of some of our exploration opportunities, and in recognition that particularly around the sour crude prospects or sour crude oil-related prospects, our CM3 platform is somewhat constrained. As we approach the year-end, these exploration targets are slightly deeper than what we've typically drilled. And it's important to note that we have over 100 drilling permits in hand right now, which -- that's actually in hand as relates to the 3 to 4-year rig inventory I spoke of earlier. And our geologists are using this fast track -- what we call a first iteration of the seismic data processing to high-grade this fourth-quarter activity as it relates to the drilling. The integration of this data is very exciting to the whole organization as we step forward, not just in Lake Washington itself, but in our South Louisiana program.

I really should stop here as it relates to the domestic operation, but Joe will fill you in in just a moment. But moving onto New Zealand, I'd like to also mention that we've had some recent and significant activity in New Zealand. In particular, we've been doing some fracturing of the Kauri sands down in the Rimu/Kauri area. And we've been drilling up in the Tawn area, what we call the Tariki-D1 well, which is our first well in the Tawn area. Bruce will give you more detail on those exciting results that we're seeing there.

The first three quarters of the year have just been excellent for the Company. The Company is looking forward into the fourth quarter. And we want to recognize that this is our 25th year anniversary. And it would just only be appropriate that the 25th year anniversary be one of the best, if not the best financial performance the Company has ever had. We're certainly looking forward to that opportunity. With that, I'll like to turn it over to Alton and let him present this quarter's financial results.

Okay. Thanks, Terry, and good morning, everyone. Swift, indeed, had a great third quarter, setting another new record for revenues, as Terry mentioned. Revenues were 74.9 million. Production exceeded 13.9 Bcfe, even with two specific events mentioned in the release, which combined for a 1 Bcfe effect. Net income was 14.1 million, after taking into effect the 3Q '04 debt retirement costs of 6.8 million related to the call of our 1999 high-rate bonds. Excluding these costs, net income came in at 18.5 million. Diluted EPS came in at 50 cents after the debt retirement costs, and 65 cents excluding these costs. Net cash flow provided by operating activities was $1.56 per diluted share.

For 3Q '04, Swift had a production increase of 2 percent over the third quarter of '03 and decreased just slightly when compared to the second quarter of '04. As Terry said, most importantly, domestic production actually rose 16 percent from the third quarter '03 and contributed 73 percent of the production for this quarter, primarily the result of continued Lake Washington success. I should also note that almost 60 percent of Swift's domestic production for 3Q '04 was in the form of crude oil, contributing to Swift's average composite realized price for the quarter, which increased 40 percent to $5.36 per Mcfe; domestic prices actually averaged $6.25, an increase of almost $1.70; while New Zealand prices rose 20 percent to $2.97.

Oil and gas sales revenues were therefore 43 percent above 2003 quarter. Total revenues for 3Q '04 came in at 74.9 million, an increase of 45 percent over '03. Swift thus realized 14.1 million of net income, which was 51 cents basic and 50 cents diluted. And excluding the debt retirement costs, came in at 18.5 million, which is 66 cents on a basic basis and 65 cents diluted, well above consensus First Call estimates.

Cash flow before working capital changes for 3Q '04 came in at 41.9 million, or $1.47 per diluted share, while EBITDA was 46.8 million for the quarter, both well over the 2003 comparable amounts. Per-unit costs remain a focus for Swift. And as to the results for the third quarter, G&A came in at 32 cents per unit, slightly higher than guidance, primarily due to continued Sarbanes-Oxley compliance costs, and production of course being slightly lower than guidance due to the previously-mentioned specific events. DD&A per unit was slightly higher than guidance at $1.43. Domestic and New Zealand production costs were both well within guidance. And production taxes, of course, increased in tandem with the higher prices and the production mix. And finally, interest expense came in slightly above guidance at 53 cents per unit.

Swift's nine-month numbers for 2004 were equally as impressive, for virtually the same reasons as we discussed for the third quarter, and as seen in the results detailed in the press release. As to Swift's strong liquidity position, our bank line remains virtually untapped. We actually had 6.2 million drawn on the line at quarter-end. And as previously mentioned, we extended -- in the second quarter of '04, we extended the line through October of 2008. With a facility amount of 400 million, our borrowing base currently is 250 million, while the commitment amount remains 150 million. As Terry mentioned, with respect to Swift's hedging activity, we continue to layer in both oil and gas forward (ph) protection in this very strong commodity market, as we continue the same strategy we've used for years of protecting the downside without giving away the upside. You can see the details of our price risk positions, as they are posted and updated on our website.

CapEx for the third quarter was 42.6 million, in line with our cash flow of about 44.4 million, trying to say cash flow neutral, as Terry mentioned. As usual, we've included additional financial and operational information in our press release, including updated guidance for the fourth quarter and the full year 2004. The third quarter was strong. But we firmly believe the future looks even stronger. And with that, I'll turn it over to Joe D'Amico for an overview of our domestic operations.

Thanks, Alton. Good morning, everyone. It is with great pleasure that I report domestically, third-quarter 2004 production increased by 16 percent to 10.2 Bcf equivalent compared with 8.7 bcf equivalent produced in the same 2003 period, and was flat sequentially compared to the 2004 second-quarter production of 10.2 Bcf equivalent. As Terry mentioned, this was in spite of the two storms which forced Swift to set-in production in Lake Washington.

Just to touch on hurricane set-in procedures, Swift is always monitoring storms that have the potential to turn into a hurricane in the Gulf of Mexico. Approximately 72 hours in advance of a storm, field personnel make the call to set in the field that if the storm path looks like it could set in the field. Folks are then sent to turn off each valve at over 100 wellheads in the field. Meanwhile, production is pumped down at our storage tanks and they are then refilled with saltwater. Any loose equipment is tied down or removed and chemicals are moved to shore. The drilling and completion rigs are often towed to safe harbor and secured to protect against the storm. After the storm passes, facilities and infrastructure are inspected, and then the wells and gas lift system is turned back on and the rigs are moved back into the field. This process takes anywhere from 24 to 72 hours, depending on the severity of the storm and assumes little or no damage. In Lake Washington, production for the third quarter averaged over 12,000 gross barrels of oil equivalent per day of production, or approximately 10,000 net barrels of oil equivalent per day.

Daily production was up slightly compared to the second quarter of this year, but as Terry mentioned, an increase of approximately 94 percent of the first three quarters of 2004 compared to the first three quarters of 2003. We have surpassed our year-end exit rate in the field of 12,000 net barrels oil equivalent per day with an October average of 12,500 barrels of oil equivalent per day.

We have come a long way from when we purchased the Lake Washington Field three short years ago. However, we feel we have only just begun in this area. And in fact, we expect to be talking about this deal for years to come. With the progress we're experiencing on the geologic site, we have also been reviewing current configurations and planning for growth in Lake Washington with regards to the facility. Swift Energy continues to develop plans for growth and to optimize the operating performance of all these facilities, which Terry highlighted earlier.

A look at our third-quarter drilling results finds that Swift Energy completed 11 of 14 wells domestically in the third quarter of 2004. All of these wells are development wells, and of these, we were 6 and 7 in the Lake Washington area. We also completed three of four development wells in the AWP Olmos Area. In South Texas, Swift successfully drilled two development wells, one in Kennedy County and one in Goliad County, and was unsuccessful with the development well in Willacy County.

Swift Energy currently has three drilling rigs operating domestically -- two drilling for oil in the Lake Washington area, and one drilling for natural gas in South Texas. To focus on our plans for the remainder of 2004, we brought a second rig into Lake Washington during October and plan to drill 8 to 12 wells in the fourth quarter for these two rigs. We have recently completed our drilling program in the AWP Olmos Area for 2004, and plan to have a rig back in the area early next year. We also may begin drilling another dual horizontal well in the Austin Chalk later this year, most likely in the Brooklyn area. And we also plan to drill one more well in our South Texas area by year-end.

I want to wrap up by letting everyone know that we're particularly excited about the opportunities that lie before us for 2005 and beyond. Now, I'll turn you over to Bruce to talk about our news in New Zealand.

Thanks, Joe. We have significant activity currently underway and some exciting news going on in New Zealand. In particular, I want to tell you about our recent drilling and cracking activity at both Tawn and the Rimu/Kauri area. But I also want to talk about our production results, the markets and New Zealand pricing, and about our future plans.

Starting with the Tawn area, Swift finished drilling the Tariki-D1 well in the fourth quarter this year. The Tariki-D1 well was a development well, targeting the Tariki sand, and it was drilled at a total depth of 8,570 feet. This was the first well that was attempted in the Tawn area since Swift acquired these properties back in early 2002. We believe that the Tariki-D1 well would be targeting some fault-separated reserves, as indicated by observed well performance since we acquired the properties. The Tariki-D1 well has intersected a similar sand as seen in the Tariki-A1 well. The A1 well has been the primary producer in the field since 1996. The Tariki-D1 well will be completed and production tested over the next few weeks. I want to caution everyone that this testing and evaluation does need to take place, but we would expect that this well will be connected in the second quarter of next year after permitting and laying a short pipeline spur to our facilities.

Moving to the Rimu/Kauri area, let me begin with the Kauri-E6 well that was drilled in the third quarter. This well was drilled targeting the Kauri sand, but we took the opportunity with this particular well site to take it slightly deeper to try to encounter the Tariki sand in the area. The well was initially completed in the Tariki sand, but encountered a limited reservoir at this location, and is now awaiting a recompletion in the Kauri sand. We also plan to drill another Kauri sand well before the end of the year, the Kauri-E7 well at another location, and it should spud later this month.

Three Kauri wells that were drilled earlier in the year were recently fracture stimulated in the Rimu/Kauri area. The Kauri-E3 well is flowing back fracture fluids at a test bank, and the results are inconclusive at this date. The Kauri-E4 well has been flow tested on various choke sizes at rates up to 10.3 million cubic feet equivalent per day on a 28/64 choke at a flow and tubing pressure of about 1870 psi. While the E5 well has also been tested at various choke sizes with rates up to 10.8 million cubic feet equivalent on a 32/64th in. choke, at flowing tubing pressure of about 2400 psi. Further testing and diagnostic production will continue with both of these wells, but our initial post frac results are extremely encouraging.

Also during the third quarter, we drilled the final well of a six-well drilling program targeting the shallow Manutahi sand, that's also in the Rimu/Kauri area. This well was a development well, and in the main fault block, and it is currently on production. As we mentioned before, we've used various completion methods in the six Manutahi wells that we drilled this year, and we're evaluating the optimal method to use for the future development of the field.

On the production side, New Zealand accounted for 27 percent of total production with 3.8 billion cubic feet produced in the third quarter. This was a 23 percent decrease from the 4.9 billion cubic feet equivalent produced in the third quarter of last year, and a 7 percent decrease from the second quarter of this year. But in the third quarter, a tanker lifting of approximately 0.3 billion cubic feet equivalent that was scheduled for the last week of September, was delayed until early October and, therefore, the sales will actually be reflected in the fourth quarter.

Production in the Rimu/Kauri area averaged just over 13 million cubic feet equivalent in the third quarter, which was essentially flat with the second quarter. And production in the Tawn field averaged just over 31 million cubic feet equivalent per day in the third quarter, which was also flat with the second quarter of '04.

Let me talk to you about the markets and the pricing. As we talked about before, another bright spot in New Zealand is the improving pricing environment for natural gas coupled with the stabilized and improved value of the New Zealand dollar. Both of these factors have led to an improved net realized price for Swift Energy over many of the previous quarters. Currency rates did strengthen again in the third quarter, which, aided by increased sales of natural gas under our newer long-term contracts, brought a slight increase in the average natural gas price of $2.21 per Mcf for the third quarter. But it was an 18 percent increase over the $1.87 per Mcf that we received in the third quarter of last year.

Also in New Zealand, the sales price of our McKee blend crude oil averaged $47.75 per barrel, which is a whopping 66 percent increase over prices for the same period last year. Now this is skewed a little to the high end due to the higher crude prices received at the time of the liftings this particular quarter in New Plymouth. Additionally, our contracts for natural gas liquids yielded an average price of $18.63 per barrel for the third quarter of 2004. Let me remind you as we've done in the past, that New Zealand natural gas and NGL price contracts are denominated in New Zealand dollars, which strengthened compared to the same period in 2003.

On the drilling front, our plans for the remainder of this year are primarily directed in the areas where we had our success last year and so far this year. We will continue testing the newly-frac'ed Kauri wells, which will be produced through the Rimu production station. We will complete and test the Tariki-D1 well, and begin making plans to place it on production by the second quarter of next year. We have one remaining well, which we'll be drilling, the Kauri-E7 well. And then we'll begin our 2005 program with an exploration well. Look for Swift to have a similar Manutahi drilling program next year and also a drilling program that targets the Kauri sand wells, which is proving to be a very encouraging reservoir. We also intend to have an increase in our exploration activity next year in New Zealand.

In summary, let me tell you that we continue to be excited about our position in New Zealand and optimistic for the future. We continue to see the impact of the tightening natural gas market there and we believe that Swift Energy is well positioned to take advantage of it with a significant onshore acreage position. We have several exciting exploration prospects that we hope to drill in order to evaluate this potential over the next two years. We believe that our acreage position, our experience in having drilled more wells than any other operator over the last few years, along with our significant position in infrastructure assets, will allow us to exploit the opportunities of this market and this basin. Thanks for your attention, and I'll turn it back to Terry for the recap.

Thank you, Bruce. Before we conclude and go to question and answer, I'd like to recap and note that this is just an exceptional position for the Company to be in, getting some of the best results we could hope for, and looking forward to even better results. And being in an exceptional commodity price environment, which we believe have strong fundamentals. And this being our 25th year as a Company, it's an exciting time here. Our net income this quarter, again, doubled compared to the third quarter of last year. That's quite an achievement. We've just completed a very impressive nine months for this year. With strong operating and financial results, we're looking forward to the fourth quarter and finishing up this year. In Lake Washington in particular, our development activity and the goals we've set around it have surpassed the initial year-end goal we've set, which was 12,000 barrels of oil equivalent a day. And we're now at about 12,500 barrels a day. We anticipate -- we are planning for this to increase. We're doing it through additional drilling. We're doing it through the 3-D seismic activity. We're doing it through expansions of our facilities in the field. We are very excited about the future there.

We're also very excited and encouraged about our New Zealand activity, the hydraulic fracturing activity that we recently concluded there. Some new technology is being applied. The Company has always been technology driven, and we're getting some very good results there. Lake Washington, as well as New Zealand, as well as South Texas, as well as our chalk properties, are all very important core properties to the Company. And technology is the driving force in how we deliver value there.

I'd like to also note, as Alton did in the presentation, our financial position is strong. We're in a position to take advantage of more opportunities as they present themselves, whether they be drilling or acquisition. But we will remain and we will focus on being financially responsible in any additional activities we take on. We have lots of good projects in front of us right now that we're in control of.

Finally, I'd like to say again that the Company is extremely proud to be celebrating our 25th-year anniversary. And we're particularly proud of the dedicated and talented people of Swift Energy Company, and the contribution that they have made to bring us to these results and the future that they deliver us going forward. Whether the activity be in the U.S. or whether it be in New Zealand or any other international operations that we take on, we believe we've got a strong and talented complement of people. The combination of these talented people and the strategic opportunities we have and the rewarding pricing environment we have leaves us well positioned to add additional value through growth in the Company. At this time, I'd like to turn it over to questions and answers.

(Operator Instructions). Our first question is from Frank Bracken of Jefferies & Co.

Good morning. Congratulations on your record production at Lake Washington. Hopefully, some more of my peers will begin to recognize it in their estimates. So I congratulate you there. My question is really focused on these new Kauri wells. These rates are obviously considerably better than those you experienced in the past. And I was hoping you can give us some color. A, as it relates to the extent to which these sands are a better quality or thickness? B, whether you have learned something in your early wells and modified your simulation techniques? C, whether it's a combination of the two? And D, can you walk through with us what these wells have taught you in terms of potential aerial extent of these sands and the potential number of remaining locations you have here? And then E, at what point in time might you have to begin to entertain a facility's expansion there, and what would it cost?

Okay, I think we wrote those down. Bruce (indiscernible) has gotten (indiscernible) the list. I'm going to start -- this is Terry -- I'm going to start out by saying that there is a technology driver going on here. We did, in fact, and we acknowledged this in the past, had a more complex environment there to deal with in New Zealand in terms of the rock qualities and characteristics of the rocks. The Kauri sand area is not too different in any regard there. It is not high -- it is not a Lake Washington type of rock. It is more of a South Texas type of rock. It's low permeability. It does have some natural fracturing in it, but it's minimal. And despite what we think is a nice accumulation of in-place -- I wan to stress it's in-place natural gas, the challenge is to get the technology in place that can give you good recoveries at reasonable investment levels.

In the past in New Zealand, we've had to slow down, bring in experts. We brought in core labs in the past and had them do extensive core work in the area, taught us a lot about the rocks. We did go from drilling these wells with water-based mud systems to drilling the wells, including these recent Kauri wells, with oil-based or synthetic oil-based mud systems. We think that's very important to the success here. We also have had several opportunities now to frac these wells with different types of profents (ph), different types of fluid carrying agencies, different rates at which we deliver it. And then the most recent activity, we changed all that again. We did some very extensive simulation work by the service provider in addition with the company, learning from the prior fracs. And we went out there and did an extensive amount of what you call pre-frac work, where you have pre-injection leak-off tests and these kinds of things. And we used a very significantly different combination of profents -- a larger size profent, larger amounts of profent. And the initial results are very impressive. We have learned in New Zealand that we need to let the wells talk to us. We need to do extensive testing and before we would be definitive in how many additional locations this might mean or how much additional production, we want to conclude that testing. But we do have a lot of optimism here about what we found. So Bruce, do you want to --?

Yes, I think there were two other questions that I recall that you had asked in that. One was the extent of the reservoir, what kind of work have we done there? And, I mean, obviously we are doing work in terms of trying to map the potential extent of the reservoir. Now that's really ongoing. I don't think we're prepared to talk really further about that yet. We are focused kind of in this area. We think we've got plenty of locations in the near-term to keep that focus there. We know that's there. But we are doing some work to try to look at the extent of the Kauri sand, both in the immediate area and perhaps other places.

The other question, which I think your last question related to facilities, and that's a very good question, Frank. The Rimu production station, as many of you may remember, was originally built to process up to 3500 barrels of oil and 10 million cubic feet of gas. But we built it in a way that we could fairly easily take that 10 to 20 million. And we've done that. The plant, right now, can produce somewhere in the 19 to 20 million rate, and we think we can get close to that. I certainly wouldn't forecast that for the -- until we get some production history on these wells. But we have had to shut in some of the other wells so we could get good tests on these wells because you can see the kind of rates we've brought them up to. So that's pretty encouraging.

We have also begun some work at looking at further expansions of the plant. We believe that it is possible to take that plant gas capacity to 30, maybe even up to 40 million a day. It won't be a significant capital cost, but we don't have that yet. We're analyzing that. It will probably take, though, a good year to get that in place. But that is some work that's underway as well. We're very encouraged by these. It's astute of you to pick up on it. These test rates are probably double what our other test rates were on some of the other wells. But as Terry mentioned and I'll reemphasize, we need to let the wells produce awhile, get some history. It is tight rock so you know you get some initial decline. But we're pretty excited about it.

Great. Thanks very much.

Thank you. Our next question is coming from Adam Leight of Credit Suisse First Boston.

Good morning. Another facilities question on Lake Washington. I don't know if you have an update of how much capacity in total you think you'll have added by the middle of next year, how much sour capacity? And then if you have any thoughts at this point on A, what you'll spend to do that? And how much -- what the production increases might look like once that's on stream? I don't know if that was as many letters or questions as Frank.

A lot of good questions in there, Adam.

Adam, while the guys are kind of looking through some of the numbers -- this is Terry -- we do intend to expand the facilities. And, in fact, we've already begun some of that activity right now, around the CM3, which is a sour facility, and the 6700 facility. We have done some, what we would call some intrafield delivery systems, where we can deliver the crude oil between 6700 and the state of these 212 platforms so that we can tap capacity that might not be utilized at one platform by another platform. But that's only in the case of sweet crude. So with the sweeter crudes, we're in pretty good position right now to be able to continue to grow some, but with the sour crude, we're kind of hitting a capacity constraint, and, therefore, we're expanding CM3. We need to take the CM3 area strategically well in excess of 10,000 barrels a day of capacity. And I would say that on the near-term horizon, that's pretty much where we're headed. And we want to take the sweet capacity in the field on the near-term horizon to about 20,000 barrels a day capacity. Again, I want to emphasize that when you go from say a level -- let me kind of emphasize here -- when you go from a level of about 20,000 barrels a day of capacity to 30,000 barrels a day of capacity, there's a lot of complications because you got gas lift systems that can render some of that capacity not where you can utilize it; you can have sour crude where it can render some of that capacity where you can't utilize it. And so that's why we find ourselves now where we want much greater flexibility in the field. We've got a lot of sour prospects and projects that we had to kind of back off of till we get these expansions done around the CM3 facility.

Yes, Adam this is Bruce. You've got some really good questions in there. I would point out though that you're asking us questions about our 2005 budget, which has not been finalized or approve by our Board of Directors yet. So it's hard to give you all those specific details. But in terms of facilities, we'll probably spend in the neighborhood of 10 to $15 million next year on facility, much of which will be related to the expansion. Terry did kind of summarize briefly what we're trying to do in the sour area and the sweet area. The other thing that has constrained us in terms of capacity has been gas lift capacity, the compression out there. And that's something we plan to expand quite a bit as well.

(multiple speakers). We don't want to be evasive here, but the bottom line is, we do have a very dynamic field of development that's got the both sour crude and sweet crude in the field. And it's got some high-pressure gas out there, too, that we've got to be figuring into the plan as well. We're very excited about the gas opportunities in the field, too. But just to kind of get on the dollar side -- and these are very rough numbers, they're not final -- but 2004 -- we know you have to look at somewhere around $20 million of just roughly. I'd say 18 to $21 million of facility work that was going on in the field. We haven't finished that out, so we'll have to see where that comes in, kind of like the capital budget number.

And going forward next year, I would anticipate something of a similar nature, if you're kind of looking for a benchmark. But as Bruce said, we have not finished up with our Board, our 2005 budget approval. So these would just be kind of shooting from the hip numbers in terms of before we get to the Board.

Adam, we'll be in a much better position when our analyst meeting is next spring to detail all these numbers.

Okay. And then just if I could follow up, I may have missed, if you have a new target for fourth-quarter Lake Washington production.

Well, no, we don't. I think the capacity constraints, both at CM3 and the gas lift system, we believe, that fourth-quarter rates will be somewhat flat with the rate we saw in October. So November and December will be essentially flat with October.

And October is higher than that original goal, so we obviously want to keep it at that level.

Yes, I'm talking about the actual average of October, which we did put in the press release, of about 12500 (ph) net. I believe we should average that same level in November and December, obviously subject to some other downtime. We do have occasional downtime with some wells or some platforms as we do some of this work. Obviously, if we're installing equipment, we have got to shut certain things down to get it installed safely. So that's why we think it's important for people to look at averages as opposed to say single-day production levels.

This is Terry again. We're going through an exciting review of the 3-D data and we're seeing a lot of the development activities of 2005 get high-graded. And as we high-grade all those activities, we find some of the concentration of wells moving around a little bit. And that dictates to a large degree, how we finalize that facility's design for next year.

(Operator Instructions). Our next question is coming from Alexandra Zirtea (ph) of Zot (ph) Partners.

Just to frame again sort of the outlook for Lake Washington, do you have a sense at this point, you know, if you're going to exit this year at somewhere around 12500, sort of how many wells it takes you to keep that flat, given what you've learned so far about the average decline of the field? And how many wells could you drill this year?

Joe, do you want to take that?

We drilled probably 30 to 35 wells this year. The important thing to remember in Lake Washington is a lot of these are completed in two zones. I think since we started drilling the field, we've only drilled about -- had three -- recompletions to date. Quite often in the field, what you'll see as we complete in the lowermost zone, that quite often, even a better zone is shut in behind the pipe; it needs to be either recompleted or we have sliding sleeves through our wireline, and you can pull that and start production immediately from another zone. So well utility is going to be much longer than any production out of any particular zone. So to date, due to facilities and some of the other production, we have not really seen a measurable decline; we've been increasing it over time. We believe the overall decline of the field is going to be 15 to 20 percent though.

(technical difficulty).

Sorry, could you repeat that?

I said, this is probably not going to be an (technical difficulty) decline --

No, no, it's not going to be a decline. We're bumping up against capacity, mainly because of gas lift right now. We're already at capacity in the sour area. You know, we've done some tweaking of the field to divert production to the 212 platform where we have excess capacity, and certainly helped. We've got a number of projects underway to increase capacity from gas lift to compression to new processing facilities to added platform structures, et cetera, that we hope to have completed by mid next year. And a lot of the drilling activity is basically building up production to, not necessarily to arrest the decline, but to be there to take off as we bring this added capacity on.

Okay. And then just a follow-up, minor detail, on the DD&A rate, is the increase, to your best explanation, sort of more like service-cost related?

Yes, there's obviously some increases in our capital cost side. I would say that would be the major contributor to the third-quarter DD&A rate.

You see that reflected in the future development cost.

Thank you. Our next question is coming from Ben Gamble (ph) of Socalick (ph) & Co.

Yes, I just had a quick question. Good morning. Just a question on -- just the change in guidance on New Zealand -- just what that was due to for the fourth quarter, I guess.

Well the big thing is the lifting from the third quarter was pushed in to the fourth quarter. And so you'll see that our crude oil production is up higher -- our guidance, if you look the, specifically for crude oil, is up higher for this quarter. And so that's the predominant reason.

And obviously, we booked the crude oil stales (ph) versus the production.

Yes, the way that works, is obviously we produce every day. We transport it up to the Omata Tank Farm in New Plymouth. But the actual sale transaction doesn't occur until the tanker comes into New Plymouth and it's off-loaded onto the tanker. And that's when we actually book the sales, which, of course, reflects the production numbers. So you can have some unevenness. Actually, for the last couple of years, we've generally been able to have a tanker lifting at the end of the quarter. And so you really hadn't kind of highlighted itself in the third quarter because you didn't have a tanker lifting at all in September. It got pushed into October. That 0.3 Bcf that would have normally been recorded as sales in the third quarter will now be in the fourth quarter.

And we're obviously getting some benefit from the Kauri sand well.

Yes, the way you have to frac -- the frac programs in New Zealand have to be done in batches. You go in and do three or four wells at a time.

There are no further questions. I'd like to turn the floor back to Mr. Vincent for any closing comments.

We'd like to thank everybody for taking the time to participate in our call today. We appreciate your support. We're looking forward to a great fourth quarter, as well, and more importantly, we think an even better 2005.

Thank you. This does conclude today's teleconference. You make disconnect your lines at this time and have a great day. Thank you.