SilverBow Resources Inc (SBOW) 2004 Q1 法說會逐字稿

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

Good morning and welcome, everyone, to Swift's first-quarter earnings call. As Ashley (ph) mentioned, I'm Scott Espanshade, Director of Investor Relations. Today's call will cover our first-quarter results for 2004. Terry Swift, President and CEO, were give an overview. Then Alton Heckaman, our Senior VP and CFO will review the financial results for the first quarter. Joe D'Amico, Executive Vice President and COO, will cover our domestic operations, and then Bruce Vincent, Executive Vice President, Corporate Development and President of Swift Energy International, will update our New Zealand activities. Terry Swift will then wrap it up before we open up to questions.

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. Our actual results could differ materially. We expect our presentation to take approximately 20 to 25 minutes, and have allowed additional time for questions.

Thank you, Scott. Again, I'd like to thank you for joining us for our first-quarter 2004 conference call. We are very pleased to announce the results of this quarter. As I think you can see, the Company has shown very impressive operating and financial success. Clearly, the commodity price environment remains strong as well. For example, NYMEX crude oil for June settled at $38.98 per barrel yesterday. NYMEX June natural gas settled at over $6 per MMbtu. This is clearly exceptional pricing, well in excess of our budgeted pricing expectations at the beginning of the year.

We recognize the volatile nature of this commodity market, and yet, at the same time, we do believe that the demand fundamentals remain strong for both oil and gas. Notwithstanding that strength in the market, we have a price-risk management strategy that does protect us on the downside but allows us to benefit from these very strong price levels that we see today.

While I could talk a lot about the commodity prices, I can't help but want to talk about the operational results that we have had this quarter, because we believe we truly have delivered some exceptional value, and forward-looking, we also think we can continue on this course. First, I want to point out that our first-quarter production, 14.3 Bcf equivalent, represents an 11 percent increase in production from the same quarter last year. I would also like to mention that the domestic production has actually increased 35 percent from the same quarter last year. This increase represents a very important step towards obtaining our 2004 production goals.

We also want to point out that we are making considerable progress in New Zealand and Lake Washington. In particular, on the domestic front, Lake Washington continues to be a very exciting area for us. We have seen a considerable production increase this quarter as a result of all the activity we had last year. We continue to focus a lot of our effort and a large amount of our capital budget in Lake Washington in several ways. I would like to point out three of the ways that we are working there right now.

First of all, we have the continuation of our drilling program; albeit at this time we are only running one rig, we view that as a temporary situation. Last year, of course, we ran two rigs through most of the year. Second in terms of focus, we have a 3-D acquisition program, seismic acquisition program, which is designed to maximize the known resource assets that we have in the field and to further evaluate the probable and possible assets that we see in this area. And finally, we continue to work on optimizing our facilities, as well as possible additions and expansions to our facilities in the field.

In New Zealand, we also see a lot of excitement there in both the operating results as well as the natural gas markets. The improved natural gas prices, of course, can be seen in our realized prices this quarter. We also have focused our development drilling opportunities in New Zealand in what I would call some creative ways. For example our Kauri-E4 well, which is a Kauri Sand development well, was actually taken deeper to test the potential of the Tariki Sand on the Kauri structure in the Rimu Kauri area. Early indications look very positive. We are being cautious as we evaluate this complex reservoir. I will have Bruce give us further details on our preliminary results during the conference call.

But before I turn it over to Alton, I want to reiterate our 2004 goals. For 2004, we anticipate that our production growth will be between 11 percent and 17 percent, that our reserve growth will be between 5 and 8 percent. We're going to focus and are focusing in 2004 on improving our per-unit operating margins. Specifically, we have targeted our finding and development costs to be between $1.30 and $1.50 per Mcf equivalent. We also maintain focus on lowering our per-unit operating costs.

We also have set as a goal this year to manage the reserve base in terms of any potential acquisitions we might have, as well as any potential exploitation opportunities that we put our capital on, to have our undeveloped reserve base in the 30 to 40 percent range as a percent of the total. And of course in 2004, we are still focused on growth. We want to enhance our existing core areas or add a core area. Preferably, we would be looking at the Gulf Coast salt dome types of acquisitions or exploitation. We think we've got some considerable skill sets there. And additionally, in New Zealand we see new core area opportunities through exploration and exploitation.

And finally throughout 2004, we are going to maintain the strength of our balance sheet and maintain the financial liquidity that we have. While it's early in the year, we feel confident in the progress that we have seen so far, and at this time I would like to turn it over to Alton to present the financial details.

Thanks, Terry. Good morning, everyone. Swift had a great first quarter, setting new records for both revenues and production. First-quarter 2004 revenues exceeded $65 million. Production exceeded 14 Bcfe. Net income was $14.6 million. Diluted EPS came in at 52 cents, and net cash flow from operating activities was $1.41 per share. As Terry said in the intro, for the first quarter 2004, Swift had a production increase of 11 percent over first quarter '03 and 7 percent sequential increase over fourth quarter 2003.

Domestic production actually rose 35 percent from 1Q '03 and contributed 73 percent of the production for this quarter, primarily the result of continued Lake Washington success, which Joe will elaborate on. Swift's average composite realized price for the quarter increased 8 percent to $4.62 per Mcf equivalent. Domestic prices averaged $5.24, while New Zealand prices increased 36 percent to $2.93 on average. Oil and gas sales revenues were therefore 20 percent above the 2003 first quarter. Total revenues for 1Q '04 came in at $65.4 million, an increase of 22 percent over 2003. Swift thus realized $14.6 million in net income, which is 53 cents on a basic basis and 52 cents diluted, well above consensus First Call estimates.

As noted in the press release, Swift's first-quarter 2004 provision for income taxes included the reduction from the U.S. statutory tax rate due almost entirely to the favorable currency exchange rate effect on the 1Q '04 New Zealand deferred tax provision. This effect was about a 4 cent adjustment, but even with that, we clearly exceeded First Call estimates. Cash flow before working capital changes for 1Q '04 came in at 38.8 million, or $1.38 per diluted share, while EBITDA was $45.5 million for the quarter -- both of these 20 plus percent over the 2003 comparable quarter.

As Terry also mentioned, per-unit costs remain a focus for Swift. As to the results for the first quarter of 2004, G&A came in at 28 cents per unit, on the high side of guidance. This is primarily due to continued Sarbanes-Oxley compliance costs. DD&A per unit was within guidance at $1.28. Domestic production costs came in actually below guidance as economies of scale continued in our core areas of operation. New Zealand production costs came in slightly above guidance, due primarily to currency exchange rates and facility maintenance costs. Production taxes increased in tandem with higher prices and our production mix, yet they ended up being slightly below our guidance, and interest expense came in well below guidance at 48 cents per unit.

As to Swift's strong liquidity, which Terry mentioned, our bank line remains virtually untapped. We have had $32.5 million drawn at quarter end, but we still have plenty of room and plenty of flexibility relative to our liquidity. Our borrowing base was recently reaffirmed at $250 million, but we have kept the commitment amount at $150 million.

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 Terry also mentioned, we continue the same strategy of trying to protect the downside without giving away the upside. The details of our price-risk positions are constantly posted and updated on our website.

CAPEX for the first quarter was $45 million, which was in line with our cash flow. And as always, we have included additional financial and operational information in our press release -- a summary balance sheet, per unit income statements, statement of cash flow, the GAAP to non-GAAP reconciliation, quarterly operational and financial comparisons, both sequential and year-to-year, and updated guidance for the second quarter and full year 2004. 2004 is off to a very strong start, providing us with a great foundation for the rest of the year. And with that, I will 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 first quarter 2004 total production increased by 35 percent to 10.4 Bcf equivalent, compared with 7.7 Bcf equivalent produced in the first quarter of 2003 and increased 18 percent sequentially compared to the 2003 fourth-quarter production of 8.8 Bcf equivalent.

In Lake Washington production for the first quarter, we have averaged 11,400 gross barrels of oil equivalent per day of production, or approximately 9300 net barrels of oil equivalent per day. Compared to the first quarter 2003, it is apparent where the majority of our first-quarter growth came from. With the first quarter last year in Lake Washington, we were at approximately 4600 gross barrels of oil equivalent per day, or at 3700 net barrels of oil equivalent per day. Just assuming a flat run rate in Lake Washington will show significant growth over last year. And we do plan to exit the year at a run rate of 12,000 net barrels per day, still an almost 30 percent increase for this area over the first quarter of 2004 average production rate.

We have come a long way from when we purchased the Lake Washington field three short years ago. However, we are not finished in this area. And in fact, we expect to be talking about this field for years to come. With the progress we are experiencing on the geologic side, we have also been reviewing current configurations and planning for growth in Lake Washington with regard to the facilities. The Lake Washington processing facilities are located in three distinctly separate areas of the field. These facilities currently utilize field wide gas compression, common saltwater injection, and a centralized oil sales delivery system.

One of the field processing facilities, the CM3 platform, is designed to handle heavier gravity crude oil and natural gas with hydrogen sulfide. The success in the shallow sands, which tend to be sour production, has filled this platform, and we are currently expanding its capabilities. The F Sand wells have generally been focused around our 6700 platform, and that is nearing capacity, which we have some short-term fixes to redirect production to the 212 platform. Swift Energy continues to develop plans for growth and to optimize the operating performance of all of these facilities, which will include additions to existing facilities, and they include the addition of a fourth field processing facility in 2005.

Now for a look at our first-quarter drilling results. Swift Energy successfully drilled 12 of 14 domestic wells during the first quarter of 2004. In our Lake Washington field in Plaquemines Parish Louisiana, the Company drilled six of seven development wells successfully. The majority of these wells have been connected and our now producing. One exploration well was drilled but was unsuccessful. One rig is currently drilling in Lake Washington.

Swift Energy also successfully drilled five wells in the AWP Olmos field in McMillan County, Texas, four of which have been fracture stimulated, and brought on production in the first quarter of 2004. The other completed well will be fracture stimulated later in the second quarter of 2004. One rig is currently drilling in the AWP Olmos area. Additionally, Swift Energy has drilled a development Austin Chalk well in the Masters Creek area in Vernon Parish, Louisiana, which is currently being tested.

Swift Energy also has a 25 percent working interest in a successful nonoperated exploration well in the Guadalupe Pasture acreage adjacent to the Garcia Ranch area in Kenedy and Willacy Counties Texas, which is currently undergoing completion procedures. Swift has two rigs working in South Texas, one drilling a development well in the Garcia Ranch area, another nonoperated exploration well in the Guadalupe Pasture area.

And as a reminder, we will begin shooting the 3-D on Lake Washington field later this month. We are currently going to focus the survey on the intermediate depths with a surface image of the salt, but the 3-D will benefit us with images of the shallow and deep horizons in Lake Washington as well. The current plan is to take the second quarter 2004 for the field work and then process the data so that the 3-D information is available for our planning process for the 2005 budget.

Swift currently has over 70 permitted drilling locations in hand, so we already have a multiyear inventory of drilling locations. We believe that the 3-D will be a great benefit and should greatly enhance our future drilling program for years to come in Lake Washington. As a reminder, our 2004 budget cost was set (ph) 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 15 to 18 development wells. We plan to drill a Brooklyn (ph) dual horizontal well in the Austin Chalk later this year. And we also plan to drill up to five wells in our South Texas area this quarter -- four will be operated wells and the other will be a nonoperated well.

I want to wrap up by reminding everyone of the diversification that Swift has added to its reserve and production base that should serve us well in 2004, and we can't be more excited about the opportunities that lie before us in the next two years. Now I will turn it over to Bruce Vincent for an overview of our New Zealand operations.

Thanks, Joe, and good morning, everybody. I'm going to talk first about our drilling activity during the quarter in New Zealand, then cover our production results, and then give you some flavor on the current pricing environment down there and then more importantly talk about our future plans. In terms of drilling activity though, let me obviously start with the Kauri-E4 well.

The recently drilled Kauri-E4 well was drilled targeting the Kauri Sand, but we took the opportunity with this well to take it slightly deeper to see if we might encounter the Tariki Sand in this area. The well did encounter both the Kauri and Tariki Sands, and it was perforated in a 15-foot section of the Tariki sandstone at approximately 9900 feet through vertical depth. It is important to note that the Tariki sand in this well is approximately 1800 feet up-dip and over 3.5 miles from the initial Tariki sand discovery in the Rimu-A1 well. It is a thinner section, but it is of much higher quality based on log analysis.

The E4 well was tested over the last couple of days at various rates, with the most recent rates of approximately 4 million cubic feet per day and 400 barrels per day of crude oil and condensate. It is currently shut in for a pressure buildup test. We expect to begin sustained production testing in the next few weeks.

We have always believed that the Tariki sand holds further potential and we are very encouraged by this well. However, we believe that it is important to evaluate sustained production testing in this well, as well as target at least one other Kauri sand well deeper to also evaluate the Tariki sand at another location. The Kauri-E3 well was also drilled during the first quarter, and did encounter the Kauri sand as well. This well will be fracture stimulated, but these plans are currently deferred pending the results of the E4 testing.

In terms of production results, on the production side New Zealand accounted for 27 percent of total production, with 3.9 billion cubic feet equivalent produced in the first quarter. This is a decrease of 25 percent from the first quarter of '03, but it was in line with our guidance. Production in New Zealand was expected to be lower, primarily because of minimum takes nominated by the gas purchaser at TAWN. Increased use of hydroelectricity in New Zealand has contributed to a short-term reduction in market demand, and this is expected to continue at least through the second quarter of this year.

It is important to note, however, that while these fields at TAWN have been able to meet minimum contracted volumes to date, it is anticipated, due to accelerated production in 2002 and in 2003, along with natural declines, that these fields will not be able to meet the contracted minimum volumes beginning in the second half of this year without additional development. We are currently considering drilling a development well in the Tariki field at TAWN in the second half of the year, but to some extent, our ongoing activity at TAWN is affected by discussions with the gas purchasers. Additionally, three of our expiration prospects are in the TAWN area.

Production in the Rimu/Kauri area averaged approximately 12 million cubic feet equivalent per day during the first quarter, while production in the TAWN fields averaged approximately 31 million cubic feet equivalent per day during the first quarter.

Another bright spot in New Zealand is the improving price 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. We received an average natural gas price of $2.27 per Mcf for the first quarter under our long-term contracts. This is a 40 percent increase over the $1.62 per Mcf that we received in the first quarter of last year. Also in New Zealand, the sales price of our McKee blend crude oil averaged $36.03 per barrel, which was an 11 percent increase over prices for the same period last year.

Additionally, our contracts for natural gas liquids yielded an average price of $16 per barrel for the first quarter. New Zealand natural gas and natural gas liquid price contracts are denominated in New Zealand dollars. The New Zealand dollar has continued to strengthen during the first quarter of 2004 against the U.S. dollar, when compared to the same period in 2003.

Probably of most importance, though, is what are our future plans? Our plans for 2004 are primarily directed in the areas where we have had success last year and so far this year in the first quarter. In the Rimu/Kauri area, we have drilled two Kauri sand wells and plan to drill two more wells, with at least one of these wells possibly targeting the deeper Tariki sand again. Additionally, we are about to kick off later this month our four to six well drilling program in the shallow Manutahi Sand. One of these wells will be an exploration targeting this formation in a separate fault block to the south. As I also mentioned earlier, we are considering drilling a development well at TAWN in the Tariki sand, and we have one exploration well planned for later in the year.

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 Swift is well-positioned to take advantage of it. We have several exciting exploration prospects that we hope to put a drilling program together with and evaluate this potential over the next two years. We believe that our onshore acreage position, our experience at 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 of this market in this basin at this time. Thanks for your attention. I'm going to turn it back to Terry to wrap up.

Thanks, Bruce. I will do a quick recap before we begin the question-and-answer time. Again, we have had an exceptional quarter, exceptional commodity prices with strong fundamentals behind them. The actual operating results and financial results, we believe, have been right on track with our strategic plans. We think we are gathering a lot of momentum. We are clearly on track through organic methods, or drilling methods, to grow the Company. We are expecting approximately 11 to 17 percent production growth this year, and 5 to 8 percent reserve growth for 2004.

Our Lake Washington exploitation is on track to meet our year-end goal of increasing production to approximately 12,000 net barrels per day equivalent. And in New Zealand, our core areas are progressing forward, while at the same time the New Zealand natural gas pricing environment continues to improve. We clearly recognize that the organization, the professionals within the organization, both domestically and New Zealand, have worked hard to achieve these results, and going forward we are very excited about what we believe our organization can deliver.

We are in a strong financial position, and that allows us to take advantage of the opportunity sets that we have, whether they be drilling or acquisition opportunities. At this time, we would like to turn it over to question-and-answer portion of our presentation.

Thank you. (OPERATOR INSTRUCTIONS) Frank Bracken of Jefferies & Company.

I have two questions. First, the oil production in New Zealand really looked soft this quarter. Gas made sense to me, but the oil production sequentially really looked beat up. Could you discuss with me what happened there, anything in particular to give (ph) in individual wells that went down? Just give us a handle on that and on the rate in the first quarter and whether it should clean up at all or continued declines in the second quarter. And I'll come back and ask my next question after an answer.

Good morning, Frank. This is Bruce. I can't just off the top of my head think of anything in particular that happened in the quarter that would affect the volumes.

Perhaps the inventory.

There is -- one of the things about New Zealand, and now the rate is probably what the answer is -- is the way we sell our oil -- I mean, we produce our oil every day, but the way production is accounted for is when it is sold, and oil is transported up to the Omata Tank Farm in New Plymouth and then we have periodic liftings when tankers come in and sell. And that's the point in time that we actually record the production. So both the price -- you could see how the New Zealand price was a little bit better than the U.S. price, and that's because it's priced when the tanker liftings occur, and so at that particular point in time, the price was a little bit better than say the average price over 30-day period of time.

The only other thing I would add is that a good bit of the oil we produce in New Zealand is condensate-related, and so it is related to the gas production in terms of the yields that are condensate, which of course precedes any extraction of the natural gas liquids there.

Okay, and secondly can you give us -- one, can I confirm that this Tariki sand test is unstimulated?

That is correct.

So you're getting basically the same rate unstimulated out of the Tariki that you're getting with a big frac job out of the Kauri?

That is correct.

Can you give me a handle on what you have in terms of mapping here? Talk about whether or not you can get any handle on how many potential locations you could have in the Tariki or will you need to come back in here and do some detailed geophysical work?

Frank, this is Terry. That's great question, and of course, we are asking the same question of ourselves. We clearly have a lot of mapping from the seismic work that we had done in the past. That of course led us to want to go deeper here. We need to get the test information back from this well, pressure buildup information. And I believe we've got to now take the log data and do what they call correlate it back into the seismic. They have some real geologic data, good velocity data now, and they will go back and map things.

It is just premature for us to be able to describe the number of acres or area that we might have here -- not that we don't want to, but we're going to the very cautious here. We know it is a complex reservoir. It can be compartmentalized. We just don't want to get ahead ourselves at this time.

But despite the increased depth, these wells could actually be cheaper than Kauri completions? Based on the lack of necessity for fracture (multiple speakers)?

Yes. From the standpoint they don't need to be stimulated, yes. The sand quality, as we mentioned, was better than the other Tariki wells down depth in the Rimu area. These results are unstimulated. That's just perforated and opening it up.

Great, thanks very much.

Ken Green (ph) of Boston America (ph).

Great quarter. My question pertains to Lake Washington production and the drilling scheduled. Correct me if I'm wrong. You were at 11.3 gross average in the first quarter. Goal is 12,000 barrels gross for the year?

The goal for the end of the year is 12,000 net.

Okay. That's what I wanted to ascertain, because obviously you have a lot of drilling going in here. How long does it take to bring these wells into production, roughly, now that you have upgraded the facilities -- or partially upgraded?

Around 40 days, because we have one rig working and so what we will tend to do is we will make a couple of completions and we will lay the flowlines, but then -- I mean, we will set casing as we drill the wells, and then once we get two or three lined up, then we will get completion rig back and complete three or four wells at one time.

And a second rig is going to be put to work -- a second barge rig, I assume. These are barge rigs I assume.

They are barge rigs. We currently have a one-year rig plan for this year. We could obviously choose to accelerate that, but our current plan is to keep a one rig in the field this year and look at bringing in a second rig next year.

We have one drilling rig working continuously Lake Washington right now. But because of the timing of when we set casing on these wells that will be future producers, we have a completion rig that we will get off and on whenever we get at least three wells that we've set casing on that need to be completed. And then we will get the completion rig and complete those wells.

That's a good point that Joe made. It's more efficient to get a small inventory of wells to complete for the completion rig to get on. But additionally, we do have the 3-D activity going on and we have chosen to focus on that activity. It does involve a considerable amount of activity in the field to conduct that acquisition.

Just a final question. What has been the average time to drill a well here? I know that you're completing in various sands, but just an average. Has that been coming down?

Eight days.

And yes, it's been coming down.

Eight days to drill a well, but on a set casing (multiple speakers).

It does depend on whether we're drilling a shallower well at 3 or 4000 feet versus an extended reach well down to 8000 feet.

And average is 8 days. With the soft formation, you can drill 1000 feet in a day, easy, maybe even more. So a well that is at a 4500 foot depth versus a well at 7500 foot depth, there's very little difference in cost.

Thank you.

Wi Dio (ph) of Salomon Brothers Asset Management.

I was wondering if you could explain to me a little bit how does the accounting work, because on your cash-flow statement, you have cash distributed as an operator and then you receive -- are these, I guess, to account for less than 100 percent working interest. But why aren't they just netted out on the income statement? Instead, I am seeing --

They would already be shown net on the income statement. The income statement would only reflect our particular working interest or net revenue interest in the property.

Right. But why are you taking additional impact on the cash-flow statement? In the past full year, they're pretty mild, but this quarter is pretty significant -- almost $9 million you paid out.

Again, that is just really adjusting for changes in working capital. So that would be -- that's a timing thing, really, with the (multiple speakers) payables as well as your receivables.

Are we talking about the quarterly cash flow?

Right. So is this when you change -- I'm sorry, is when you sell or buy a working interest, or is this really relating to accounts receivable or payable? I guess I am a little confused why it's under the investing activities and not under the cash flow from operations segment. Is this relating to when you actually change, buy and sell working interest -- 8.708 of negative cash out and then you got $106,000 cash coming in?

We have our controller, who is looking at the income and cash-flow statement. We will get you an answer to that.

The receivables and the payables, when we make an accrual to book oil and gas sales or LOE, all of the receivables that we book that impact the income statement are in the operating section. The balances of the accounts receivables and payables, the rest of the working capital changes, flush out through the investing section under the caption you're referencing.

Okay, so why are they going though the investing, not the cash flow? I guess I'm not sure I understand.

Because we've got the receivables that affect the income statement in the operating sections.

Anything else goes through investing.

The rest of the receivables that might be like a liability set up to accrue for CAPEX or whatever, all of the other working capital receivables and payables then flow through the investing section.

I guess what I'm asking specifically is the item that says net cash distributed as operator of oil and gas properties.

Yes, and that's what that is. Perhaps how we have named that caption is causing you confusion. But it is the working capital changes.

That's how we've shown it for a number of years. I think you'll find it to be exactly like that that in every E&P company.

Well, I guess it's not. And I have noticed this is how you have always shown it, but previously on a full-year basis, these numbers have been fairly small and I haven't paid any attention. But given that in on quarter it jumped up to $8.7 million, I thought I would pay more attention to it. And I don't cover every other E&P companies, but I have never seen other E&P companies reporting as such.

And it is misleading, because it sounds like this is what you're paying out because you don't have 100 percent working capital -- I mean working interest. But that should be netted -- when you book revenue, it should already be booked that way, and should it have any timing differences on cash basis, it should be included on your operating activities. That's why I'm a little confused.

We can follow up with you specifically on this matter if you want to give me a call. I will get our comptroller together and we can answer specific questions on it.

We appreciate your comments, and we clearly do want to be as clear and concise as we can in all of our disclosures, notwithstanding the fact we do have to make sure that our auditors agree with how we have classified these things. But I think we will look at this much more closely, having had you bring it up, and make sure that we are clear and concise going forward.

Okay. Another question I have is do you expect to call -- I think you have the 10.25 bonds that will be callable fairly soon. Do you expect to refinance those?

It is certainly something that we are considering doing. We have not made any decision with regard to that, but it is something that we are looking at.

Okay and perhaps you have gone through this and I didn't catch it, but it looks like you added more hedges in the quarter. As a percentage for the full-year production, how much are you hedged now?

That is not an easy question to answer. We post all of the details of our hedging activity on our website. We also put out production guidance. And that percentage obviously changes with each new hedge we put in versus what we have reported for production or what we forecast production to be.

Just to reiterate, the Company's price-risk management strategy with regard to hedging is one that is premised around protecting the downside without giving way the upside. We generally implement that through floors or participating collars. For the most part, what we've done this year is put floors in place or do what we call trigger deals, where you presell some oil and gas production just a few months out, some portions of it.

All right. Thank you.

(OPERATOR INSTRUCTIONS) Shannon Nome of J.P. Morgan.

Thanks. Good morning. Just trying to get a better handle on the cost side of the equation, and really pertaining more to New Zealand. You have done it looks like a very nice job on the unit LOE side in the U.S., particularly as your productions ramped up. But I was just checking back at the year-ago quarter, it looks like the unit LOE rate in New Zealand I guess is about doubled. And it erodes somewhat the benefit of the pricing gains you cited. I can see the guidance for the year is down a little from here, but just wondering is this just a pure function of production declines in New Zealand over a relatively fixed cost base, or what is behind that and what can you or are you doing to work down the unit costs from here?

There is really a couple of things. What I would tell you off the top of my head is that the biggest reason is that the currency exchange difference. A lot of those costs are in New Zealand dollars, and the currency exchange rate today is significantly better than it was a year ago. On the cost side, that obviously makes those costs higher. You could have spent the exact same dollars a year ago again this year and it would be higher number when it's translated into U.S. currency.

The second thing obviously does relate to volumes. There is a certain amount of fixed cost. You have two plants there operating. Whether you produce 1 million or 20 million, you have a certain fixed cost there, and obviously the lower production levels also impact that. I think the positive thing, though, particularly with regard to currency, you are seeing that reflected in the revenue side.

So your currency helps you on the revenue, hurts you on the cost. Net-net, it looks like your margin is up, but --.

What we're doing to -- to answer the last part of your question, which is perhaps the most important -- what are we doing about that. Obviously, we do work on our costs. We try to keep our costs down both the U.S. and New Zealand. That effort is pretty intense. We also look at marginal value projects.

One of the things the New Zealand group actually instituted this past quarter was what we call an LPG enhancement program in the TAWN area, where we basically added some equipment there to extract more LPGs out of the gas stream, because the LPG price we were able to negotiate was better than the gas price. And that's a small thing, but it is a marginal thing that will improve both the volume slightly and will improve the margins.

The other thing, obviously, to the extent that we can get volumes up, which we are working on, that will improve that fixed cost burden that you have.

Thanks, Bruce.

Rehan Rashid of Friedman Billings.

Good morning, gentlemen. Question for Joe on the Lake Washington area. Of the 17 locations that you talked about, how much are booked already? That's the first question. And the second, exit the year at 12,000 barrels a day net. What kind of decline rates are you seeing, and in that vein, how many wells a year would be need to keep production -- let's call it on flat, around the 12,000 level?

Off the top of my head, I really don't know how many of these locations are PUDs. I would say maybe one-third could be PUDs. The rest are probables or possibles.

And what kind of reserves are we seeing for location, just generically speaking?

Three hundred thousand barrels, so 440, 450,000 barrels oil equivalent per location.

Got you. And the decline rates here?

That is a hard thing to put your hands around. Most of our F sand and wells, which we started drilling them about two years ago, and they are all still flowing, and they really haven't shown any decline. Some of our older wells, there are some wells that produce at high water rates and they just stay flat and other wells, once water hits, they start declining. I would say overall, probably the fuel decline rate is around at the most 15 percent.

That's pretty good.

This is Terry. My recollection is that the fuel history itself, if you just take all of the wells in the area, that you are really kind of around 20 percent decline. However, as Joe notes, we did have some really high-quality F sand wells that we have not been producing initially at maximum production, and they are flowing wells. They don't require gas lifts, so we are really not seeing decline on a certain portion of our base.

Overall, probably 15 percent is the number we tend to discuss here, but as you know. we just brought everything into the facilities. We're still ironing out some of the optimization issues. So we don't have a pure decline number that we could present to you right now.

Got you. And the 300 to 450,000 per well, is that just for the F sands or does that include some other ones as well?

That's everything. That's an average. Our F sand wells tend to have a lot higher reserves per well. You're looking at more to 0.5 million to one million barrels reserves.

Got you. So the program for Lake Washington would be, call it, 15, 20 wells a year and then keep production growing past exit rate? Any thoughts on what 2005 average or exit rate would look like, given whatever program that you --?

No, we haven't put those numbers together. One of the things that we mentioned was we're shooting the 3-D later this quarter, and will be processing that and get the results in for the third quarter. That's going to drive a lot of the '05 budgeting activity. We have not obviously made a commitment to whether we're going to have one rig or two rigs there next year.

We're trying to do facilities planning in order to -- if we bring in a second rig next year, we think we can ramp production up. Obviously, you need to be well out in front of these facilities. If we chose to put in a fourth production platform, you would probably need one year, 1.5 years lead time to do that. We are trying to do some of that work now, so we have not really put any '05 numbers on paper yet.

Got you. That's good enough. Just in terms of the seismic, the deeper stuff, remind me again please what are we looking for? What is the hope to find and some generic milestones there, if any?

We're hoping to able to really image the salt. Most of our drilling has been shallow down to say above 6000 feet because of well control. And when you go deeper, there are very few deep wells. And whenever we drill a well, we tend to take it to salt. So say we target a group of sands above 5000 feet or 4000 feet, and we will take the well down, we will drill directionally and take it down to wherever it hits salt. So we are always looking for new zones. And that way, we have found a lot of additional pay sands.

But most of our production is (multiple speakers) coming from the shallower sands, which is above 6000 feet. And so the intermediate stands, from 6000 to 12,000 feet, we have a little production coming from that, but anything below 12,000 feet, we have no production. So we are really hoping to be able to image from 6000 feet down to below 12,000 feet quite well. And we also -- where we are shooting the seismic, we will really be able to image the salt quite well from, say, 4000 feet, so some of the shallow stuff we will be able to see quite well, which will optimize drilling locations.

So hopefully, when we drill well, we won't leave a lot of attic reserves. We can drill well right close to the salt and pick up all the attic reserves. And we will be able to see -- hopefully see some bright spots and see some down-dip limits on some of these horizons to see exactly where the oil/water contact is. Because on a lot of our reservoirs -- in fact on most of the F sand reservoirs -- we have oil from top to the base of the sand, so we only take it down -- and that's our lowest known oil level.

On a lot of what we're doing with the intermediate depth sand is what we did 2.5 years ago with the shallow sands. We have clearly found these sands ring the salt feature. Originally when we got this deal, we started mapping the sands from 1200 feet on down and exploited them. We're doing the same thing with the intermediate. We're mapping a lot of the sands that produced a lot of cumulative production to the North around to the West and the South and that is what we will be targeting.

Okay, sounds good. Thanks.

At this time, there appear to be no further questions in the queue. I would like to turn the floor back over the speakers for any closing remarks.

This is Terry Swift. Once again, we would like to thank you for joining us in our 2004 first-quarter conference call, and we look forward to meeting with you again in the next quarter. Again, the momentum has been very good. We thank you for joining us.

Thank you. That does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day.