SilverBow Resources Inc (SBOW) 2004 Q2 法說會逐字稿

Good morning, and welcome to the Swift Energy second quarter earnings conference call. At this time all parties have been placed in a listen-only mode, and the floor will be open for your questions following the presentation. It is now my pleasure to turn the floor over to your host, Mr. Bruce Vincent, Executive Vice President of Corporate Development. Sir, the floor is yours.

Thank you, Maricia, and good morning, everybody. I'm Bruce Benson, Executive Vice President For Corporate Development of Swift Energy and President of Swift Energy International. And I'd like to welcome everyone to Swift Energy's second quarter earnings conference call. Today's call will cover our second quarter results for 2004. Terry Swift, President and CEO, will give an overview, and Alton Heckaman, our Senior Vice President and Chief Financial Officer, will review the financial results for the second quarter. Joe D'Amico, Executive Vice President and Chief Operating Officer, will cover our domestic operations. And I'll update our New Zealand activities, and then turn it back to Terry to wrap it up before we open for questions.

Before we begin, though, let me remind everyone that our presentation will contain forward-looking statements, which are based on our current assumptions, estimates, and projections about us and our industry. These statements involve risk and uncertainties detailed in our SEC reports, and our actual results could differ materially. We expect our presentation probably take about 20, 25 minutes, and we've allowed some additional time for questions. I'll turn it over to Terry.

Thank you, Bruce. And thank you again for joining our second quarter 2004 conference call. We're very pleased to announce the results of the second quarter. We're very convinced, and feel strongly we're achieving strong operating and financial success, not only in this quarter, but as we're going forward.

Clearly the commodity price environment remains very strong. As you're aware, the NYMEX September crude oil for 2004 settled at a 21-year high last week, over $43 per barrel. The NYMEX September natural gas settled above $6 as well. While we recognize the strong environment, we clearly don't plan to have these kind of pricing in terms of our projects. We're still operating at a much lower price deck in terms of justification of projects. We still believe we're in a volatile market, but having said, that we're in a very strong pricing environment and receiving the benefits of it. As we look forward, we have to also recognize that we do have an active price/risk management strategy that does allow us to keep benefiting from this market should it continue. And at the same time, we've got a capital budget program that we have to protect against short-term severe down -- decreases in the commodity prices. We think it's still a volatile environment. And you've probably seen that we've had some crude oil trounces recently where we've locked in about 1500 barrels a day in the third and fourth quarters. We post that on our website.

We've also bought some floors to protect crude oil and natural gas pricing. We view this as short-term protection for the capital budget. We recently increased our capital budget expenditure estimates to the 160, $175 million range. We've brought forward additional projects that will be receiving capital allocations. Specifically, there's about $5 million of additional capital we're putting into 3-D activity, both in terms of the project that we've initiated directly over Lake Washington, as well as 3-D in the surrounding area as we shoot out that program. We've also looked at additional allocations for expansion of our production platforms on the Lake Washington area. Some of that expansion will begin in 2004. We believe a good bit of it will be completed in 2005.

We're also planning for additional wells in Lake Washington, and finally we're planning for additional wells in New Zealand, specifically, the deepening of some of our development wells that will allow us to intercept some of the deeper, higher-risk, higher-potential formations we call the Tariki sands in New Zealand. Again, we're pleased with the commodity prices, but we can't help but want to focus this conference call on our operating results that we've delivered this year, so far. We believe it's some deep core value that we're experiencing as part of our growth.

Our second quarter production, which was 14.3 Bcf equivalent, represents a 7% increase in the production from the second quarter of last year. I'd also like to mention and point out, that the domestic production has increased by 20% from the same period a year ago. This is a record for us as a Company, a six-month record, first-half production record for the Company, and the organization is very proud of this achievement. We look forward to continuing our growth, going forward.

Specifically, a lot of our growth effort is in Lake Washington, and New Zealand, our core areas. Lake Washington needs some particular discussion here, because of all the opportunities we see there, and all the results we've already recognized in this area. We're focusing our efforts in Lake Washington in several different ways that I'd like to point out in this part of our presentation. First, and the foremost driver that's going on in terms of growth right now in Lake Washington, in terms of current event, is our 3-D seismic project. It's currently being shot in the field and will be processed in the fourth quarter. This project is setting up several different events for us as we move forward. Obviously it will aid us in some of our intermediate depth targets as we continue to drill out our inventory projects in 2005. But it will also help our reservoir management effort and facilities effort as we, kind of, peek into the future and look at additional opportunities, where they might be on the dome, what depths they might be, what types of hydrocarbons, be they sour or sweet, be they gas or oil. It's very exciting to be able to have this project and get a look into our future as our geologist would say here.

Speaking of our geologists, they have been mapping. And we have drilled a considerable number of wells on the dome since we bought this property, over 100 penetrations, lots of new geologic control points, lots of new information in terms of well logs, petro physical data, all the information. And they've been using that to update their maps, principally, as we look at the entire opportunity from the north side of the dome, which has historically been very productive, in the -- principally even farther north of us in the 7 thousand to 14 thousand depth range, there's been a lot of gas discovered. We're looking at that depth range around the dome and to the west and south and east, as well, but also in what we call our low-hanging fruit, we're getting a lot of precision and good well control opportunities. The older vintage 3-D that's in the area, we've also picked up some of that data, and brought into it our well control and refined our ability to look at this dome going into our 2005 budgeting process.

Our new 3-D project will go a long way to enhancing the inventory that we already have. In fact, we believe that the current inventory that we have represents a 3 to 5-year drilling inventory, in terms of activity on the dome. Again, focusing on Lake Washington and some of the events that we have there, facilities expansion is an ongoing opportunity for us. We clearly have achieved a lot, taking the dome from approximately 700 barrels a day when we got it, to well over 10 thousand barrels a day, and that's required facilities. We've had sweet oil, we've had sour oil, we've had differing associated gas, and as you can imagine, we had old facilities that we had to expand and upgrade. We're currently looking at expansion of two of our platforms in the field, and even adding a fourth into the future.

Near term expansion, which is likely to begin this year, will be at the CM3 platform, which is the platform that processes our sour crude and is currently having a liquid handling -- is at liquid-handling capacity. We've married some of the existing equipment in the field to some of the new equipment, and as we've done that, as you'd expect, we'd had some down-time kinks that we've been working out. In that regard, we had our amine unit recently go down. That particular event, which is just part of the buildout that's gone on, we're getting that fixed. We had about 3,500 barrels a day, just from that one little event there, which is clearly just a kink.

We remain very confident and excited about our Lake Washington project. In fact, we still have our exit goal on a net basis to achieve over 12 thousand barrels a day production from this very important core area. Lake Washington finally, as I kind of note the focus we have there, continues to have a shallow drilling program, what we call the intermediate or low-hanging fruit in the area. We kept one rig working there because of the 3-D that's being shot out there. There's been a lot of activity, and we felt it appropriate to get this information in front of us before we go back up to a two-rig program. Again, I want to note we've got over 100 drilling locations in hand, approximately a 3-year drilling inventory. So, while this property has had some challenges as we've brought from the 700 barrels a day to over 10,000 barrels a day, it's still got lots of opportunity and we're very excited about that. In fact, as we've been waiting on the 3-D, the geologists have maintained a very high success rate in their drilling. Using the existing control, they are still achieving about a 79% success rate in the development program.

Moving on to New Zealand we have continued focus on our development drilling program in New Zealand where we've got various sands that we've had success in. For instance, the Manutahi Sand, it is a shallow, crude oil play, had 5 wells drilled in the second quarter. Early indications are very positive, Bruce will give more detail on that Manutahi program, as well as further plans that we have in New Zealand as concerns some gas opportunities, and exploration opportunities we have there. At the halfway point of the year, we're very pleased with our operating and financial progress in 2004. We believe we're making a lot of strategic decisions that are creating momentum into the future.

At this time I'd like to turn it over to Alton to present these financial results that we're so proud of.

Okay. Thanks, Terry. And good morning, everyone. Swift, clearly, had another successful quarter. Starting with setting another new record for revenues, which exceeded 71 million. As Terry said, production for the quarter was 14.3 Bcfe. Diluted EPS came in at 46 cents, 52 cents without the effect of the 2Q '04 debt retirement cost charge. Net income was 12.9 million, about 14.6 million without the debt retirement cost charge. Net cash flow provided by operating activities was $1.26 per diluted share, and the actual 2.7 million pre-tax charge for the debt retirement cost relates to the early retirement of approximately one-fourth of our 10 and a quarter notes, which were tendered in conjunction with the June 2004 issuance of our new 150 million 7 and 5/8% notes. As we indicated in our press release, the remaining 10 and a quarter notes have been called and retired, which will result in debt retirement cost charge in 3Q '04 of approximately 6.9 million pre-tax.

For the second quarter of 2004 Swift had a production increase of 7% over 2Q '03, while remaining virtually flat when compared to the first quarter 2004. Domestic production actually rose 20%, as Terry said, from the 2003 second quarter, and contributed 72% of the production for this quarter, primarily the result of our continued Lake Washington success. Swift's average composite realized price for the quarter increased 31% to $5.04 per Mcfe. Domestic prices actually averaged $5.86, while New Zealand prices increased 31% to just under $3. Oil and gas sales revenue were therefore 41% above the second quarter 2003. Total revenues for 2Q '04 thus came in at 71 million, an increase of 40% over the comparable 2003 numbers. Swift realized 12.9 million in net income, as I mentioned earlier, which is 46 cents, both basic and diluted. But excluding the debt retirement cost net income was 14.6 million which is 53 cents basic, 52 cents diluted, both slightly above consensus First Call estimates.

Cash flow before working capital changes for 2Q '04 came in at 40.3 million, or $1.42 per diluted share, while EBITDA was 46.8 million for the quarter, 51% and 39% over the 2003 comparable quarters, respectively. Per unit cost continue to be quite a high priority for Swift. As to the results for the second quarter of 2004, our G&A costs came in at 29 cents per unit, which was on the high side of guidance, primarily due to continued Sarbanes-Oxley compliance costs and some increased state franchise taxes. DD&A per unit was higher than guidance, came in at $1.37. Domestic production costs came in above guidance, primarily due to some Lake Washington facility repair costs, as we mentioned in our press release. While New Zealand production costs actually came in below guidance, even as scheduled plant maintenance costs and currency exchange rates came in favorable. Production taxes increased in tandem with higher prices in the production mix, though slightly below guidance. And interest expense came in within guidance at 50 cents per unit.

Swift's 6-months numbers for 2004 were equally as impressive, for virtually the same reasons I described for the second quarter. We've detailed first half results and they're included in our press release. As to Swift's strong liquidity position, our bank line remains virtually untapped. We've actually extended it until October 2008, while increase the facility to 400 million from the original 300 million providing with us maximum flexibility. Our borrowing base was recently reaffirmed at 250 million, while we've kept the commitment amount at 150 million. As Terry mentioned, with respect to Swift's hedging activity, we continue to layer in both oil and gas floor protection in this very strong commodity market as we continue the same strategy of protecting the downside without giving the up side away. The details of all our price risk positions are posted and updated on our website.

CapEx for the first quarter was $41 million, in line with cash flow, basically on a cash neutral position. And, as always, we've included additional financial and operational information in our press release, the summary balance sheet, the per-unit income statement, statement of cash flows, the GAAP to non-GAAP reconciliation, quarterly operational and financial comparisons, we've included both sequential and year-to-date, year-to-date operational and financial comparisons, and updated guidance for the third quarter of 2004 and the full year. As Terry said, the first half of 2004 has indeed provided a great foundation for the rest of the year.

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, second quarter 2004 total production increased by 20% to 10.2 Bcf equivalent, compared with 8.5 Bcf equivalent produced in the same 2003 period, and decreased 2%, sequentially, compared to the 2004 first quarter production of 10.4 Bcf equivalent. This year-to-year production growth is a result of Company's successful shallow drilling efforts in the Lake Washington area. We have continued to have particularly success in targeting the F and deeper sands.

In Lake Washington production for second quarter averaged nearly 12 thousand gross barrels oil equivalent per day of production, or approximately 9,800 net barrels of oil equivalent, up slightly compared to first quarter of this year, and an increase of just over 75% compared to second quarter of 2003, when we were at approximately 6700 gross barrels of oil equivalent per day, or 5,500 net barrels of oil equivalent per day. Just assuming a flat run-rate in Lake Washington, we'll show significant growth over last year. And we do plan to exit the year at a run-rate of approximately 12 thousand net barrels of oil equivalent per day, still an almost 30% increase for this area over the 2003 average exit rate. We have come a long way from when we purchased the Lake Washington field, 3 short years ago. However, we feel we have only just begun in this area. And, in fact, we expect to be talking about this field for years to come.

With the progress we're experiencing on the geologic side, we have also been reviewing current configurations and planning for growth in Lake Washington with regard to facilities. As a reminder, the Lake Washington processing facilities are located in 3 distinctly separate areas of the field. These facilities currently utilize field-wide gas compression, common water injection, and centralized oil sales delivery system. One of the field processing facilities, the CM3 platform, is designed to handle heavier crude, and both crude and natural gas with hydrogen sulfide . The success in the shallow sands, which tend to be sour production, has filled this platform to current capacity, and we are currently looking at options to expand its capability. The up-sand wells have generally been focused around our 6700 Platform, and that is also at capacity. And we are working on some short-term improvements to redirect production to the 212 Platform, where there is excess capacity.

Swift Energy continues to develop plants for growth, and to optimize the operating performance of all these facilities, which Terry highlighted earlier. A look at our first quarter drilling results finds that Swift Energy completed 9 of 13 wells, domestically, in the second quarter 2004. Of these 13 wells, 11 were development wells and 2 were exploration wells. In Lake Washington, the Company completed 5 of 6 development wells, but was unsuccessful with an exploration well. In its other core areas, Swift Energy completed 4 of 5 developments wells in the AWP Olmos area. In the South Texas drilling program, Swift successfully drilled a development well in Kenedy County, and was unsuccessful with a non-operated expiration well in Willacy County. Swift Energy currently has 3 drilling rigs operated domestically, 1 drilling for oil in the Lake Washington area, 1 drilling for natural gas in Texas, and 1 non-operated rig in Alabama.

As a reminder, our 2004 budget cost for Swift to drill up to 25 to 30 development wells in Lake Washington, we plan to have a rig in the AWP Olmos area for the majority of 2004, which will allow us to drill between 15 and 18 development wells. We may also drill another dual horizontal well in the Austin Chalk later this year, in either Brookeland or Masters Creek. And, we also plan to drill up to 5 wells in our South Texas areas, 4 of these will be operated and the other will be a non-operated well. I want to wrap up by letting everyone know that we are particularly excited about the opportunities that lie before us in the next few years.

Now I'll turn it over to Bruce to talk about New Zealand.

Thanks, Joe. I'm going to cover our current drilling activity, and talk about our production results for the last quarter, and touch on the markets and, in particular, the pricing environment for natural gas in New Zealand, then wrap it up with our ongoing plans for the rest of the year.

With regard to our drilling activity, though, let me start first with Kauri E5 well. The recently drilled Kauri E5 well was drilled with the primary target of the Kauri Sand but a secondary target of the Tariki Sand, which is a deeper exploration target that we hope we might encounter in this particular area. The well did encounter what looks like a very good section of the Kauri Sand, but as we went deeper, it did not encounter the Tariki Sand in this well. This particular location was a little further to the north, and what we suspect is that you just after steeper dip up to the north, and the rig capability didn't allow us to go any deeper than we were able to go. The well is currently being completed, and will be perforated in the section of the Kauri Sands dome at approximately 9 thousand, 9 hundred feet, true vertical depth. We then plan to move the rig over slightly and drill another Kauri Sand well, the Kauri E6 well, the primary target will, again, be the Kauri Sand, but as a secondary target, we hope to take it deeper to evaluate the Tariki sand. This particular location will be a little bit further south, so we hope we have a better chance of encountering the Tariki in this well at this location. This particular well will be spud this month.

The Manutahi Sand, which during the second quarter we drilled 6 wells targeting this shallow, oil-bearing sand. The first well was an exploration test, and that was further to the south of the Rimu/Kauri area, in hopes to evaluate a potential new fault block. This particular well was unsuccessful at this location. The next 5 wells, however, were drilled in the existing proven fault block, and all of them have been completed in the Manutahi Sand and are now producing. We have used various completion methods in the 5 wells, and are evaluating the optimal method which to use for future development of the field.

On the production side, New Zealand accounted for 28% of total production, with 4.1 billion cubic feet equivalent produced in the second quarter of '04. This is a sequential decrease of 5%, but was a -- sequential increase of 5%, but it was a decrease of 15% from last year's second quarter production and is in line with our guidance. Production in New Zealand was expected to be lower from last year, primarily because our largest gas purchaser up at the TAWN area has been taking minimum takes under -- that are required under the contract. There's been an increased use of hydroelectricity in New Zealand, because the lakes there are brimming and full, and it's the cheapest source of energy. And this has contributed to a short-term reduction in market demand for natural gas. We currently expect this to continue, at least through the remainder of this year.

While these fields at TAWN have been able to meet the minimum contract volumes to date, it is anticipated, though, that due to accelerated production in '02 and '03, along with the natural declines in the field that they will not be able to meet the contracted volumes beginning the latter half of this year or early next year, without additional development. We do currently plan, though, on drilling additional development wells in the Tariki field in the second half of this year. Production in the Rimu/Kauri area averaged just over 13 million cubic feet equivalent per day during the second quarter, which was up slightly from the first quarter. And the TAWN field's averaged approximately 31 million cubic feet equivalent in the second quarter, which was essential flat with the first quarter.

On the pricing side, as we've talked 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. However, currency rates did weaken in the second quarter compared to the first quarter, which brought about a slight decline in the average gas price of $2.13 per Mcf for the second quarter under our long-term contracts, but it was a 22% increase over the $1.75 per Mcf received in the second quarter last year. Also in New Zealand, the sales price of our McKee blend crude oil averaged $37.37, which is a 40% increase over prices in the same period last year. Additionally, our contracts for natural gas liquids yielded an average price of $17.69 for the second quarter of '04. New Zealand Natural Gas and natural gas liquids price contracts are denominated in New Zealand dollars, and they also continue to strengthen compared to the same period in 2003.

In terms of our ongoing plans for 2004, they're primarily directed in the areas where we've had our success last year and so far this year. In the Rimu/Kauri area, we drilled 3 Kauri Sand wells this year, and will begin drilling the fourth well this month. We had set out to drill 2 to 4, and we're going to drill all 4 of them. In the Manutahi area, we've actually completed our 6 wells program. You may remember, we set out to drill 4 to 6 wells in the Manutahi Sand, and we completed drilling all 6, 5 of which are on production right now, and we're monitoring that production to get some production history, as well as to determine the optimal completion methods to be a part of our drilling activity in this sand next year. Following the drilling of the Kauri E6 well in the Rimu/Kauri area, we plan to move it up to the TAWN area and drill a Tariki Sand development well at TAWN. And then, we'll begin very early 2005, start out in the first quarter with an exploration well in the Taranaki.

In summary, let me tell you that we continue to be excited about our position in New Zealand, we continue to see the impact of the tightening natural gas market there, and we believe that we are well positioned to take advantage of it with the largest on shore position of exploration acreage. We have several exciting exploration prospects that we hope to put a drilling program together with, and evaluate this potential over the next 2 years. We believe that our acreage position, our experience in having been the leading operator in New Zealand, in terms of drilling wells over the last several years, along with our significant position in infrastructure assets will allow us to exploit the opportunities in this market in this Basin. Thanks for your attention, and I'll turn it back to Terry to wrap up.

Thank you, Bruce. I just after few closing comments before we have question and answer. I'd like to note that, once again, we recognize that we're in an exceptional commodity pricing environment that has strong fundamentals underneath it. But we're also very focused on the activities that we have. And we're very proud of our staff, which is composed of a numerous oil and gas professionals that have delivered some exceptional first half results, both in the operating and financial side of the business, both in the U.S. and New Zealand. I want to also point out that our Lake Washington activity remains robust and exciting to us. And the exploitation effort is on track to meet our year-end goal of increasing production from that project area to 12 thousand barrels a day, net to the corporation.

We have a flexible financial position that allows us to take advantage of additional opportunities as they may come forward, and we're out there looking for opportunities, both underneath existing core properties, within core properties, as well as just keeping our pulse on the market at large. The Company is in a good position to take advantage of both drilling and acquisition opportunities. Our Lake Washington 3-D shoot is particularly exciting, and it's nearly completion. We're very anxious to get those results in our hands so that we can further March forward in this area of Lake Washington, and add additional value. We're very confident that that drilling inventory in Lake Washington will improve significantly, and be hydrated as a result of this project. And finally, I can't help but note and be pleased with the fact that year-over-year our second quarter income is up 79%. We believe that's an exceptional achievement.

And on that note I'd like to end this particular part of our presentation, and turn it over to question and answers.

Thank you. The floor is now open for questions. If you have a question, please press star, 1 on your touch-tone phone. If at any point your question has been answered, you may remove yourself from the queue by pressing the pound key. We do ask that while you pose your question that you pick up your handset to provide optimum sound quality. Please hold as we poll for questions. Our first question is coming from Shannon Nome of J.P. Morgan.

Thanks, good morning. Couple of things. Bruce, your comments on sequential drops in the New Zealand gas price Q2 versus Q1 were noted. You know, if exchange rates stay similar, you know, should we be using something around the 210, 215 level going forward, i.e., the lower level of your guidance, or are there other things that you think will get you to 230 to 240 as you move into '05?

Well, there two are things at work there. Exchange rate, obviously, is probably the biggest factor. And as you probably noticed in our guidance for New Zealand pricing, we did drop the range from what we had seen previously, that's in large part driven by the slightly lower exchange rate.

Mm-hmm.

But the other factor is the mix of gas, and any ongoing discussions that might change the pricing that we get for gas down there with the end users. But just under our existing contracts, we really have three different gas streams, the TAWN gas is a lower price contract, and that's pretty much probably ought to be flat for the rest of the year. Down in the Rimu/Kauri area, there's a very small amount of gas that's under an older contract that's lower priced. But the new gas that's coming out of these Kauri wells is a higher price contract, so as that gas volume increases, obviously, you have a slightly weighted effect to increase the price of gas. So if all things were equal, the composite price of natural gas out to go up slightly, but I think the exchange rate will have the larger effect, at least between now and the end of the year.

Okay. On the note -- on that note, as you're talking about the Kauri gas, your production guidance for third quarter and year, it seems like would imply pretty solid fourth quarter ramp, particularly in New Zealand, is that just Kauri and Manutahi drilling hitting? Or what would be the risk that outlook?

I think the bigger part of the ramp in New Zealand, at least, is this drilling of the Tariki D1 well, which is the development well at TAWN.

Okay.

And the timing of that is probably the greater risk in any ongoing discussions we have, obviously, with end users on what kind of additional, you know, what kind of price we'll get for essentially new gas that we develop there.

Okay. Thank you, Bruce. Wait, just one cleanup question. I missed the number on what net production at Lake Washington was during the quarter.

I don't know that we provided that specifically. It will be in the 10-Q delineated.

Shannon, this is Terry, we don't have that right here in front of us. As Alton, noted it's going to be part of the 10-Q. I think Joe gave some generalized rates, but not the specific Lake Washington rate, or for volumes.

Thank you.

Thank you.

Thank you. Our next question is coming from Van Levy of CIBC World Markets.

Good morning, folks. How are you?

Hey, Van. How are you?

Good. Good. Couple questions, a little more clarity on your increase in CapEx. I guess it was 130 to 150 million, now it's 160 to 165.

That's correct.

You mentioned 5 million for the 3-D, can you put some other numbers on the other activities, and then maybe any amount on increases in service costs?

Yeah, I think we can put some numbers on them, and they're coming from different parts of the table, so let me let them bring that forward. But clearly we did articulate, specifically, the 3-D at an additional 5 million. We also have a couple of wells in Lake Washington that we're adding, and those wells typically run, Joe, --.

Million 2, yeah. Million 3.

Drill some of the deeper wells.

Million 3, million 5, maybe.

To a million 5 on those. And then, in New Zealand we've got two additional deepening of the Tariki, so there's a couple million that's going to that effort there to go deeper. We also -- pulling some numbers here together -- we also have additional facilities activity that's going on in Lake Washington that will give the variance in the numbers that we're looking at here. We may be in a position at year-end to initiate 2 expansions. We may, on the other hand, only initiate 1. And that creates the range and the numbers. Joe, you want to pick up on that?

We plan on increasing our facilities expenditure in Lake Washington by about $3 million this year. We had initially planned on spending around 12 and a half million, and now we're up to about 15 and a half million. That's part of our increase. As Terry mentioned, we plan on drilling several wells at Lake Washington. We also plan on drilling some more wells in South Texas. We just finished the post 3, and we're going to drill a post 4 offset. That's another well. And then in further South Texas, we plan on drilling 2 more additional wells. Out of the increase, the $19 and a half million increase, of approximately 14 million will be allocated to domestic activity, and a little over 5 million to New Zealand activity.

Okay, and any service costs comments?

Well, I think those have been reflected through the year. Obviously steel has been the obvious one for everybody in the industry, and we've -- those have been reflected in our numbers as well.

Okay.

Essentially in Lake Washington, because of the cost of steel, our drilling costs have gone up, like, 4%. We have been managed -- we negotiate 6-month contracts with most of the service companies, so we've filtered in a 4% increase in AFE costs.

Okay. Second question, I guess following what Shannon's question, that third quarter, it looks like you're bringing that down, that implies fourth quarter is going to have to top up. Skeptics, on one hand, would say that shutting in production at Lake Washington, maybe there's some production performance issues there. Would you comment on that?

This is Terry. I'm going to let Joe comment on it more specifically, but I think it's very clear, from our perspective, that we've add very successful drill out, and that we have established some very significant deliverability and capacity from the wells that we've drilled. I do want to emphasize that early on in the program, we reported individual wells from time to time that were drilled and the amount of net pay and those types of things, but we've had so many successes out there, that those particular activities are not near as significant individually as they used to be. But we continue, as I noted, to have a high 70% to 80% success rate in the field. We're bringing in exceptional quality reservoirs as we speak. We've had capacity problems with the fluid handling of some of the facilities. We've had some gas compression issues. We've got 3 feed studies in front of us, kind of give you a little detail, where we're looking at the optionality, and not only how do you make sure that you get all this capacity that you develop, but what about next year and the year after. And that becomes part of the planning issue that we're bringing forward to you now, in terms of additional capital expenditures this year that wouldn't really be completed until next year. I feel very confident that we -- that while you do have natural decline, I mean, we've been developing this field for 2 years, you do have an underlying natural decline, I feel very confident that we've got strong reservoir performance, we've got some short-term kinks we're working out.

Okay.

So to, kind of, expand on what Terry just said, our CM3 facility, which handles sour crude and gas production, was at capacity beginning of the year. So we changed our focus and our drilling program to drill deeper than D sands. In particular, the D sands and the shallower sands tend to be sour, whereas the deeper sands tend to be sweet. And so far this year, we've had tremendous success drilling in F sands and deeper sands. And our average initial rates from these wells are much higher than our plan average rates before, because these wells are deeper and have a little bit higher pressure. And because of that, we already had the CM3 facility at capacity. Now our 6700 facility is at capacity, and we've done some work to -- we've laid an 8-inch line from the 6700 to the 212 facility, and that's just coming on line now, so that we can move some of that oil that we have going to the 6700 to be processed at the 212 facility. So we're quite excited about that, but that's taken some time to do. But the wells we've drilled have been exceptional. Our average net pay is running, like, 170 feet, versus 140 feet for the last 3 years.

Yeah. I'll wrap up that particular question by saying, I think we could talk a lot about Lake Washington, but the reality is what are we doing? And the facts are we did reduce ourselves down to 1 rig in order to shoot the 3-D. The 3-D is a future-oriented activity that should show you that we're still very much of the opinion that we're going to get results forward. We are doing additional facilities expansion. Our actions, I think, are consistent with our statements that we think there's a lot more out there.

The other thing I might just reiterate, that we mentioned earlier, is the amine unit on the caseload platform has been down now for several weeks, and it's not back up yet. And that has already cost us 3500 barrels a day of production for that period of time during the third quarter. That's the reason you really see the third quarter guidance a little bit wider swing there because we're not exactly -- you know, predict the exact day it's going to get on stream and get back up to running. Not only does that affect your ability to process the sour crude, but it affects your ability in the gas lift system which lowers production in other parts of the field.

Okay. Last question. 86 -- 87 million in cash, and I guess your short-term -- your current liabilities 142 million. Could you take us through and, kind of, roll us into the third quarter and give us a sense of what you're going to do with the cash? Are you going to -- or maybe what's in the current liabilities and how this reflects in bank debt?

Yeah, that's pretty easy. The cash is now gone. We used it to the redeem the bonds, made that payment on Monday of this week.

Okay.

So that's kind of where we're at now.

Is bank debt going to -- is where roughly, pro forma, for that?

Probably in the 10 to 15 million range, Van, just today, but our projections shows us basically to not be into our bank line absent some particular opportunity that will be cash flow neutral to actually positive for the year.

Okay, and then finally, availability, maybe I missed that. Is it 150?

Currently -- go ahead, Bruce.

$250 million borrowing base.

Okay.

We maintain a commitment amount of 150, which just means we don't have to pay the commitment amount on the other 100, but we can take it from 150 to 250 in a couple days' notice. It's at our discretion.

Okay. Great. Thanks, guys.

Thank you.

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

Couple of them asked and answered already. But, I'll -

Thanks, Adam. How are you?

I'm well, thank you. Could you talk a little about just the follow-up on the exchange rate. We've talked in the past about potential for hedging out foreign exchange exposure. The New Zealand dollar has slid now, seems to be sort of back where it was the beginning of last quarter. Is there any plan or thought about hedging your exposure there?

We've had discussions on that, Adam, and even at the Board level, and have done some analysis work on that. You know, obviously, there's not, just as with commodity prices, there's not a clear consensus on where things are headed. But we've done that, we've looked at it, we've entertained it, you know, and I guess at this point that's really all I can say. It's been a favorable effect on us, the fact that we didn't lock in in prior years, and we're looking into that.

Well, I would add, Alton, that we look at our operating activity there, and we do have a natural hedge in the nature of how the gas contracts are put together in New Zealand, that the in-country pricing is based on the Kiwi dollar, whereas the oil pricing is based on the U.S. dollar, and that creates some amount of natural hedge.

Yeah, and we have some -- our outflow is mixed, too. Some of it's in Kiwi dollars and some of it is in U.S. dollars.

How about on oil prices? You've added to your hedges, at what looks like pretty favorable pricing, at least at the moment. Any thoughts about increasing, since we're well above $40 at the moment and the strip is --

I think you'll see us continue to execute our price/risk management strategy in the ways that we've executed in the past. We do believe in layering them on and strengthening markets. And I think you'll just see a consistent application of that policy going forward, just like we have in the past.

Okay. Then I guess last -- I'm sorry, go ahead. Could you remind me of what your -- if there's any way to quantify your investment so far in Tariki targets? What the success has been, if there's any way to quantify a cash-on-cash return? Have you --

I don't think we've -- yeah, I think the question is trying to quantify the capital investment, just in the Tariki targets. We've not tried to separate that out. We, obviously, do look at a profitability analysis by our core areas. You know, the Tariki, clearly, has been a more complex area geologically, but it's also an area that we believe holds very significant potential. We've seen some really clean-looking sands in a couple of places, we'd hoped to find those. One was wet, the other was relatively small reservoir, but find it that thick sand full but of hydrocarbons the way it is up at the TAWN area. And we're trying to do that cautiously, and that's why we're using these Kauri Sand development wells in a couple of places to take them deeper we can, and, obviously, there's a very marginal excess cost to make an exploration test.

I think one of the best ways to answer that is the way we do our capital benching project -- process. Every project has to stand the test of a strong commercial analysis with a look-back. And it's in that process that we allocate capital. To the extent that the Tariki reservoirs might have a higher risk, and they also sometimes have higher potential, so we'll be doing some of those but the lion's share of the capital has gone to this Kauri development, the Manutahi development because it's got lower risk and it's gotten a larger proportion of budget allocation.

Okay. Great. Thanks.

Thank you. Our next question is coming from Frank Bracken of Jefferies.

Hi. Actually, I've got a three-part question, each of it relates to, kind of, areas that you're pointing to for incremental production over the course of the year. First, at Lake Washington, could you help us out a little bit in terms of -- it sounds as though, you know, you just,kind of,have been a little out-guessed in terms of how good some of your wells are and whether you have room at that specific spot to get deliverability through. Can you give us any handle on whether you've had, you know, weeks or significant periods of time at each of the respective facilities when they are up that get your rates that are higher than the current rates? Or, you know, can you discuss the number of wells that are in backlog that are, you know, that awaiting facilities expansion or whatever? Just kind of give us some more -- get a little more mathy on your assertion that you can get to 12 thousand BOE a day. I'm not saying I don't believe you, but just trying to give everybody in the call a little better handle on how much of your production is really being constrained right now.

Okay. Frank, this is Terry. I'll attempt to do that. Again, I want to preface my comments by saying, you know, we can talk, but you need look at our actions, and our actions right now are, that we did slow down the drilling in order to do the 3-D shoot, and we're about got that completed, and we are wrapping up some feed studies for facilities expansion where we're putting more money into facilities. Those are the actions. You'll be seeing another rig get out there in the near future. Now, beyond those actions, how do I quantify, or otherwise qualify, I think it's probably better to qualify. We do production tests on every well out there for individual allocation purposes, both for state royalty purposes, as well as us knowing what each well can do. And we have individual deliverability tests from every single well in the field. We do pressure buildup work at the time they drilled every one of these, and they've got an extensive database of what the wells can do at individual performance levels when they aren't individually restricted into a particular facility. So that's one of the key drivers that you know what your reservoir performance is. I think it would be appropriate to say that when you look at those tests, you have, really, 2 categories -- 3 categories of wells. You have wells that are flowing wells that don't require any gas lift, presently, you know that they will require gas lift in the future; you have wells that require minimal gas lift; and then you have wells that require a small amount of gas lift. And I think it's appropriate to say that in the testing aspect of what's going on out there, and Joe will correct me if I'm wrong, there's about 6 thousand-plus barrels a day of flowing capacity -- flowing well out there. And there's about another 6 thousand barrels a day of what you would call medium gas lift, where you don't need a lot of gas lift to get it to the platforms. And then there's another quantity that's harder to quantify, that needs a lot more gas lift, and in some cases we've shut some of those wells in pending getting more capacity out of the gas lift system. Now, I don't want to -- I want to keep it simple, but I have to say that you further divide those categories into sweet and sour.

Gotcha.

And so that, then, becomes the play that you're trying to work out. And on the east side of the dome, which is where we have the CM3 facility, which is the immediate expansion opportunity for us where we're going to take immediate action, that's where the sour is, that's where most of the capacity throughput limitations exist relative to crude oil getting all the way to the sales market. We obviously lose sleep at night for any -- if we have to shut in a 100-barrel a day well, we lose sleep at night.

Right.

We're working those problems through.

And when will this facilities expansion be complete?

We've taken action in the field as part of this year's budget. We've put some, what I would call, some looping projects in place, where we connected the 6700 Platform with the 212 Platform so that we could access capacity over on the 212 side that was still available to us, and that is -- that's already happened.

Does that really help with you the flowing barrels more than anything else?

Joe, you want to pick up on that?

Yes, it does. Most of our F Sands wells and deeper wells are all the flowing wells that concentrate around the 6700 facility, and that's at capacity. So that this 8-inch line will take most of the flowing wells and divert that oil to be processed at the 212 facility.

Okay. And then so when does this CM3 expansion get done and alleviate your gas lift issues?

Part of it's already done, then part of it gets completed in 2005. You want to go through those 3 issues there?

What has really affected us lately has been, we've had problems with the amine unit, which really shuts in 2 compressors, and we only have 4 compressors in the field. And since we only have 12 flowing wells, and all the rest of the wells are on gas lift, it not only affects -- the amine unit is for sour gas that goes to the compressor at caseload -- well, not only does it affect those wells down there but it affects sweet wells up at 6700 and 212 which need gas lift. With only 2 of 4 compressors working, the pressure in our our gas lift system goes down so far that it really -- as mentioned Bruce earlier, we lost 3,500 barrels a day.

But that solution is imminent with the amine unit.

Right.

Are you just upgrading or replacing it?

We have virtually replaced every piece on it. We have upgraded. And we have now replaced every piece on it, so it's virtually a new unit.

Okay. All right. Secondly, can you talk to us about the Manutahi? You've drilled 5 new wells. Can you give us some handle on, you know, incremental production from those wells? And then review with us, you know, in the fault block that you have proven how many locations you might have remaining to drill there?

Yeah, that's a two-part question. Let me take the first part. I'm not sure I -- I know I don't have the answer to the second part off the top of my head. The 5 wells that we drilled we used several different methods of completion. It's a very high-quality sand, and will actually kind of fall apart if you were to pull a core and put it in your hand. And so, obviously, that helps in terms of the flowing oil. So our initial 2 wells, we completed with a gravel pack for sand control purposes. The negative thing that resulted from that, though, is the gravel pack seemed to impede the flow of production, so those 2 wells are probably producing 20 to 30 barrels a day range. The other 3, though, we've produced essentially with a cavity completion, with different kinds of pumps on them. And we're getting anywhere from say 50 to 250 barrels a day of production from those wells. The 5 wells, collectively, right now are averaging about 100 barrels a day, roughly, or 75 to 100 barrels.

Per well.

Per well, yeah. And obviously, we're looking at the possibility of maybe pulling those gravel packs, and re-completing with the gravity completion, obviously, to increase the flow rates. But a lot of what we want to do, too, is monitor that production over a couple of months to get a better feel for both the decline and pressures and stuff, to help us in our ongoing development of the field itself. We're going through the budget process right now, obviously, so we haven't made any firm decisions as to what we're going to do next year, but I'm pretty sure that that we will have some activity in the Manutahi Sands next year.

Would it be safe to conclude similar levels of activity?

Yes, that probably would be fair to assume. Obviously, we've got to look at allocated capital. Obviously, one of the big things that can happen next year is a little more activity in the exploration area. And to some extent that has to do with the number of prospects we drill and what kind of partners we bring into the program, et cetera. But I would suspect somewhere -- you know, safe to say 4 to 6 Manutahi wells next year.

I would add to Bruce's comment, we're reluctant to say, you know, here's what they make per well because what we're really looking at is the whole reservoir and how you develop the reservoir. Some of the wells are very up dip, with no water leg, and some are down on the flank with some water leg in them. We've seen wells that, you know, 20, 30 barrel-a-day-type wells with what we call tight gravel packs, where you're getting no sand, whatsoever. In this oil market that's extremely profitable at, you know, 3 thousand foot depth, 3,500 foot depth, go after, you know, 30, 40 barrels a day. But we've also seen some -- well over 100 to 200-barrel-a day-types of results. But as Bruce noted, that involves sand production and so you're sorting through those issues. We're coming up with the most appropriate scheme for developing the whole reservoir. Looking forward, we see at least 2 more years of activity like we've had right now.

One of the things that we also have done is really drive down the cost of the drilling here. These wells are actually costing about 50% of what their original F1 well was drilled for.

Okay. Great. And then lastly, can you review for us -- it's a little hard to keep track -- your Kauri activities and discuss with us wells that only had partial contribution, or no contribution in the second quarter that will -- that are anticipated to have positively affect third and fourth quarter production, whether it's Kauri or Tariki?

It's hard for me to keep track of all those wells, too, without something in front of me.

I'm going to do my best to qualify it a little bit. As you're aware, in New Zealand, you have to bring in services at the right times. And we have been on a Kauri, what we call E-pad drilling campaign, drilling those wells, knowing that we intend to defrac those wells, we have not had the frac equipment in country to do that. It's on its way, so there are some timing issues there, but we think we're going to get that done and get it into this year. In particular, though, as we reported earlier, we did take one of the wells deeper to the Tariki, and actually have a -- what I call modest completion, although, certainly profitable completion in the Tariki, and we're going ahead and producing that out. You've seen some of that production, actually, was in the second quarter, some of it will be in the third quarter, but I anticipate that in the third quarter we'll probably plug back from that zone and add it to the frac program that's already underway. We could have as many as 4 wells.

I think the main contributor --

I hope that helps.

-- in the Kauri Sand area were the A4 well and the E2 well. The E3 well is awaiting fracture stimulation. The E4 well was the one Terry just talked that's been producing out of the Tariki Sand. And then, the E5 well, which we've just in the process of completing, that will contribute in the third quarter. And then the E6 well, which we're about to drill, you know, that will take 30 days to drill, so it really won't be until September that you might see some production.

But it will impact this year --

The E3, E4, E5, we may get a little production, but it's really probably more fourth quarter impact.

I think you'll get some in the third quarter, but clearly more in the fourth quarter.

All right. Thanks, very much for your time.

You bet. Thanks for listening.

Thank you. Once again, if you would like to ask a question, please press star, 1 on your touch-tone phones. Our next question is coming from Shannon Nome of JP Morgan.

Hi. Just a follow-up. Thank you. The release had indicated an increase in future development costs that had pushed up your DD&A rate. And, I'm just wondering, you know, is it correct to assume that, combined with bump in CapEx, could that be indicating potentially higher finding costs this year? Or at this early stage of the year, have you bracketed any targets for that yet?

Well, it's a little early to answer that question, because the big variable in terms of finding cost issue is going to be reserve growth. We've got -- and obviously don't really do your reserves in detail until the end of the year -- but we do have some interesting wells that we're going to be drilling in the second half of the year that will certainly have an impact on reserves. You know, the big increase in DD&A was a result of, you know current drilling costs are up, versus what you had estimated beforehand. So when you run your numbers out, you have to have higher numbers for your future development cost, and that is the big contributor, probably the single most largest contributor to the DD&A.

Yeah, it absolutely was.

Thanks.

Thank you. Our next question is coming from Daniel Pratt of John S. Herold.

Good morning.

Good morning.

Bruce, you mentioned the TAWN properties might not meet required contracted volumes. I'm just curious what the consequences of that would be.

There really aren't any consequences to us. The contract is a both volume-based, time-based, and kind of minimum-take based. The contract was signed, I think, back in the early 90s, so we inherited it. But it requires the purchaser, in this case, Contact Energy, to take a minimum amount. But they can take more if they want to and we can deliver it. It's all a best-efforts contract.

Okay.

The contract actually expires in 2007, so whatever they haven't taken, or been produced under that, you know, the contract expires. We do show remaining reserves after the contract expires, and, obviously, that gas is available to be contracted, obviously, at a price at today's market, not the market in the early 90s. If those wells don't produce the minimum takes that Contact's required to take, there is no penalty, they just don't get that gas.

So, I just want to make sure you weren't required to go out and buy gas to fulfill those contracts.

We're not at all.

Okay. Thanks.

Thank you. There appear to be no further questions at this time. I will now turn the call back over to Management for any further or closing comments.

Well, this is Terry Swift. Once again, we'd like to thank you for joining us today at our second quarter conference call for 2004. And we look forward to reporting back to you in the third quarter, as we continue to March toward our results for this year. Thank you.

Thank you.

Thank you, everybody.

This does conclude this morning's teleconference. You may disconnect your lines, and enjoy your day.