SilverBow Resources Inc (SBOW) 2002 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Swift Energy Company fourth quarter and full-year earnings conference call. At this time all participants have been placed on a listen-only mode and the floor will be open for questions and comments following the presentation.

It is now my pleasure to turn the floor over to your host, Mr. Bruce Vincent. Sir, you may begin.

Thanks, Holly, and good morning, everybody.

Today's call will cover our fourth quarter and full-year results for 2002. Terry Swift, president and chief executive officer will start out with an overview, then Alton Heckaman, our senior vice president and chief financial officer will review the financial results for the fourth quarter, Joseph A. D’Amico, our executive vice president and chief operating officer will cover our domestic operations, and I will give an update on our New Zealand activities. Then I will turn it back to Terry for a wrap-up before we open it up for questions.

Let me first remind everyone though that our presentation will contain forward-looking statements 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. Expect the presentation to be about 20, 25 minutes and we have allowed plenty of time for additional questions - Terry.

Thank you, Bruce.

Once again, I would like to thank everyone for joining Swift Energy Company for our fourth quarter and full-year 2002 earnings conference call. Today we're going to present our operating results as well as our financial results. I would like to begin by giving a brief summary of what we set out to do in 2002 and what we have actually achieved. Clearly, 2002 was a very important year for Swift Energy Company to realize some momentum and come in to a marketplace that we think is fundamentally very strong for natural gas prices and oil prices as well. We set out in 2002 to increase our reserves, we have done that that. The reserve growth for 2002 was 16%. We set out to increase our production, our production growth was 11%. We recognize that we needed to decrease our finding and development costs. For the year I'm pleased to be able to report that we achieved this at a final number for the year of $1.02 per MCF equivalent. Reserve replacement rate was just in excess of 3% for the year.

Another point to stress today, we'll be talking more about it, we recognize that we wanted to improve the quality of the underlying reserve, production base in various ways. The first way of course was diversity. We achieved that. We have more diverse production and reserve base. The next point of course was geology. We achieved that in the various types of reservoirs we're producing from and reserves are located in. We also recognize we wanted some geographical diversification, we were able to achieve that as well as quality in the underlying sandstones themselves. We clearly had been able to move the company from a higher deliverability, higher decline type of profile to a more predictable certain type of profile with much, much higher quality sandstones and reservoir rocks.

Equally important we sought to optimize the reserve base. We're happy to be able to report that we have done this. Principally one of the measures that we undertook this year was to bring our proved developed reserve category to about a 60% level. We have achieved that. How we did these things, of course are important. We will go in to the detail of that today. Lake Washington we recognized at the beginning of the year was an emerging growth area. It is now clearly a core area for Swift Energy Company. Production in Lake Washington up over 300% as a result of the 2002 efforts. The reserves in Lake Washington increased over 150%, 162% per the numbers reported.

We recognized also that we needed to improve our operating results. There were other areas where we had changed our capital allocations, where we weren't going to be drilling as much in 2002. And we recognized that as those areas were maturing, we needed to reduce our operating costs. We did that in those areas. We also recognize drilling costs were a very important item to focus on, particularly in Lake Washington because of the technology issues there, we achieved some significant gains there, reducing our drilling costs. We're very pleased to be able to say that we have positioned the company for not only diversification but growth in the reserve base, specifically Lake Washington does have a multiyear development program ahead of it.

We also believe we positioned New Zealand in a similar fashion, both in our TAWN and our Rimu-Kauri area, we have multiyear growth opportunities there. We set out at the beginning of the year to liquidate our public partnerships, which of course was a planned liquidation, we succeeded in that. We recognized also that we needed to manage the debt to our PBT ratios, we have been successful in that. There is no question that the PV-10 is higher due to pricing but it's also higher due to the nature of the reserve base, this solid and diversified nature of the production that we have underneath it. Year end 2001 debt to PV-10 ratio was about 43%. We're able to report that year end 2002 debt to PV-10 ratio, these are SEC PV-10s that are reported in the financials, that year end 2002 debt to PV-10 is now 28%.

We also recognized early in the year we wanted to improve the balance sheet, maintain flexibility, principally liquidity. And in so doing we set out to have a $200 million senior subordinated debt offering that was successful, in addition to that we had a $30 million equity offering which of course positioned the company so they could properly implement its plans.

What's next? Going forward into 2003, we of course are very optimistic about the fundamentals of the natural gas and oil markets. We think we're observing some long-term shifts in pricing towards a positive manner. We expect growth in our production base and reserves to be 7 and 12% for the year. We're setting out to double the Lake Washington production in 2003. We clearly recognize AWP is a rock of Gibraltar gas property for us so we will be seeking to maintain our production levels there through additional drilling as well. We will be increasing Rimu-Kauri and TAWN production levels as part of our 2003 objectives as well.

We're going to continue to focus on improving our operating margins in three principle manners -- again, we want to focus on keeping our finding and development costs in the dollar to $1.25 per MCF range, that is a stated internal goal that we believe we can achieve. We also recognize that continuing to work on the efficiency of our operation can of course lower our per unit operating costs, as well as working on our GNA cost to be more efficient as an organization. We're going to continue to optimize the reserve base, our strategic objective is to have our undeveloped inventory of reserves at approximately the 30 to 40% level. We feel that's the appropriate level for a company such as Swift which of course is a growth oriented company.

We also are seeking in 2003 to begin the development or emerge the development of a new core area. We clearly have identified in south Louisiana some new operating capabilities that the company has in shallow waters as well as gravel-pack technology, drilling around salt domes, so that would be on our target list. We believe we have been very successful in the past at doing exploration, this is what we're really, really good at. So that's part of our effort to develop a new core area. We have positions already in our exploration effort. We have got an area down in south Texas we call the Garcia (ph) Ranch, that could also become an emerging or core area for the company. We'll be concentrating down there this year -- we have a 3D in that area, we have already had some significant gas discovery successes in that area. So we will tell you a little bit more about that today.

And finally, as we set out in 2003, we are going to continue to focus on keeping the balance sheet strong and maintaining a very conservative posture. We want to keep our debt to PV-10 ratio in the 25 to 35% range as one of our stated goals. We want to maintain our liquidity to both deal with potential threats in the future as well as opportunities that present themselves to us. And we will continue to have an active prosperous management program in order to try to capture some of this upside that we're seeing in the pricing environment.

With that, I would like to turn it over to Alton Heckaman, our CFO and will give us our financial review.

Thanks, Terry. Good morning, everyone.

There's a lot of very detailed financial information included in our press release and I will quickly hit some of the highlights. Swift's fourth quarter 2002 production volumes of 12.6 BCFE increased 10% over the same quarter in '01, 3% from the most recent sequential quarter. Domestic activities contributed 60% of the production for the quarter, while New Zealand contributed the remaining 40% in both cases at or above the high side of guidance. New Zealand production actually well exceeded our guidance for the quarter, as the TAWN acquisition continued to produce excellent results.

For the entire year '02, production rose to an annual record of 49.8 BCFE, an 11% increase over '01, again, at the high end of the most recent guidance. As another example of our sector's volatile nature, Swift's realized hydrocarbon pricing increased in the fourth quarter when compared to 2001, but actually declined for the full-year. Swift's average global deposit realized fourth quarter price for MCF equivalent rose 30% to $3.15 in '02. Domestic pricing actually rose 62% over the '01 fourth quarter pricing. Oil and gas revenue was therefore 41% above the comparable 2001 quarter. Swift thus realized 3.4 million in net income for the quarter which is 12 cents both basic and diluted and exceeded first call estimates. Cash flow before working capital changes for 4Q '02 came in at 19.3 million or 71 cents per diluted share, again exceeding first call estimates.

Full-year 2002 resulted in 11.9 million in net income, which is 45 cents per share, both basic and diluted, and cash flow for '02 came in at 67.6 million or $2.53 per share. As Terry mentioned, we remain keenly focused on reducing our controllable per unit cost. And as to the fourth quarter of '02, GNA came in at 25 cents a unit while DDNA per unit came in at 1.15. Domestic and New Zealand production costs both came in below our guidance as economies of scale and cost control measures continued to kick in at both Lake Washington and TAWN. Production taxes increased in line with guidance and in tandem with the price and production increases, and interest expense came in at 53 cents per unit which is 3 cents less than the low end of the guidance.

As to our liquidity, as we previously mentioned, our tandem debt and equity offering in the second quarter netted the company approximately $225 million. This, along with our 195 million bank line which we had zero drawn upon at the year end '02, we feel like we're in strong financial shape to continue implementing our strategy. Recent pricing improvements allow to us continue layering in hedges for '03, again in the form of participating cashless collars and floors for both oil and natural gas. Our actual detailed price risk management position is posted and updated on a regular basis on our web site. Further price appreciation will likely allow us to continue to lay in, layer in even more protection in this volatile pricing environment. We feel this method of hedging is very much in line with our historical strategy of protecting the downside without giving away the upside opportunities. As to cap-ex for the fourth quarter, we incurred 23 million, which ended up totaling 155 million for the year, resulting in an all-end financing cost of $1.02 per MCFE for 2002. Additionally in the release we have included a page which compares current quarter operational results, the most recent quarter, and finally we have a summary balance sheet as of year end '02.

With that, I will turn it over to Joseph A. D’Amico for a quick overview of our domestic operations.

Joseph A. D’Amico: Thanks. Good morning.

Production for the fourth quarter of 2002 increased by 10% from the fourth quarter of 2001 to 12.6 billion cubic feet equivalent, average of approximately 137 million cubic feet equivalent per day. This was a 3% sequential increase from production of 12.2 BCF equivalent in the third quarter of 2002. Domestic production totaled 7.6 BCF equivalent for the fourth quarter of 2002, an average of 82.6 million cubic feet equivalent per day, which was reduced by approximately 300 million cubic feet equivalent as a result of production being shut in due to Tropical Storm Isidore (ph) at Lake Washington and downtime at the Brookeland Masters Creek plant.

Natural gas represented 44% of the domestic production, crude oil 40%, and NGL 16% of the total production for the fourth quarter. Total production expectation for 2003 had been set at between 53 to 56 BCF equivalent, increase of 7 to 12%. Domestic production will begin to increase in the first quarter of 2003 with expected volumes to range between 8 to 8.5 BCF equivalent, sequential increase of at least 5%.

During the fourth quarter of 2002, the company drilled 7 wells, of which five were development wells, two were exploratory wells. Most of the company's drilling activity this quarter was concentrated in the Lake Washington field in south Louisiana, that is six of the seven wells in Lake Washington. A second drilling rig was moved into the area January 2003 and a completion rig was recently moved in to begin completing the newly drilled wells.

In Garcia Ranch located in Kenedy County in south Texas, the burns number one well was an exploratory well that was completed in a Freo-sand (ph) at about 2.7 million cubic feet equivalent, I mean at 2.7 million cubic feet per day and 112 barrels of condensate per day. This brings the company's domestic results to date for 2002 with 74% success rate on development wells with 17 to 23 successful development wells and 3 of 7 successful exploratory wells for the year. In Lake Washington, we have begun a 50 to 60 well drilling program this year. We will continue to drill the shallow wells, but will also look at more of the deeper sands seen in wells today, that is the F, H (ph) and deeper sands. In fact, one rig is currently drilling for the deeper sands while the second rig will also target the deeper pays after it finishes the well it is currently drilling. Swift recently drilled the Moran (ph) number 208 well, which is a downdip offset to the number 187 well.

As you may recall, the Coppler (ph) Moran 187 well was our first completion of the F sand and has produced over 150,000 barrels of oil to date and is currently making 1200 barrels of oil per day. day. The number 208 well had about 140 feet of pay in the upsand with oil to the base of the sand. This extended the oil column downdip and has increased the reserves in this fault log (ph). Swift currently has over 28 drilling permits, 24 flow line permits and has begun permitting for emissions discharge permits to further increase gas lift capacity in late 2003. Swift has also selected over 84 additional locations to initiate the permitting process. Swift is now capable of handling its own water disposal in the field. This will lead to some cost savings in the field.

In Masters Creek we're looking to form super units in the field with one infill well planned in the second half of 2003. In Brookeland, current plans call for an additional development well to be drilled in the second half of this year. In AWP we plan to drill 10 development wells as well as continue with coral tubing jobs and refrags of existing wells. We received an entity for density permit in AWP which removes internal lease lines on the Bracken (ph) lease, and has allowed us to high grade our plots (ph) towards more of the sweet spots.

I would now like to turn it over to Bruce to give you an overview of the New Zealand activity.

Thanks, Joe.

To cover New Zealand I want to break my remarks up into three basic areas, talk about the TAWN properties, then cover Rimu-Kauri and then touch on the natural gas markets, because there have been some new developments that all of you may not have seen in the press from down under.

With regard to TAWN, this property continues to perform exceptionally well. In the fourth quarter it produced an average rate of about 48.8 million cubic feet equivalent per day. We hope to average similar levels in the first quarter of '03 and in fact based upon the January activity we see that happening at least so far. We will continue to work on some exploitation activity in the field. We think there is some additional upside that we will focus on this year and we're also continuing to evaluate some deep potential where there had been prior production tests conducted in the deeper Kapuni (ph) sands, although I don't currently foresee any specific activity targeting those this year.

Down at Rimu-Kauri, fourth quarter production volumes averaged approximately 6 million cubic feet equivalent a day, or about a thousand barrels equivalent a day as we had forecasted. We would expect to see those production levels continue to average at those rates through the first quarter, although they might be slightly lower than that because of some downtime while we're working on certainly one of those wells during the quarter. We have three particular activities that are focused in the Rimu-Kauri area in the first half of this year, and we think will be somewhat telling for the productivity down there.

To begin with, as we have discussed before, we have had some formation damage around the well bores of the wells in the Rimu area that were completed in the Tariki sands. We are planning a CO2 injection in one of those wells this first half, that well will be shut in for about 30 days or so while that -- after the CO2 is injected to try to see if that can remediate, or mitigate some of the damage around that particular well bore, and that will tell us something about that effort and how we want to go forward.

The Kauri A4 well, which you may recall was completed last year and tested in the Kauri sand, the original test was about 2 million a day and 75 barrels of condensate -- we have set protection liner in that, reperforated a smaller zone in preparation for a hydraulic fracture stimulation effort that also will take place in the first half of this year, and we hope to get some good production history on that. We think the Kauri sand could be a significant opportunity for us.

Then in the shallow area, we also have the shallow Manutahi (ph) sand that we're going to continue to evaluate. We do plan a shallow well in that area, also in the first half, to further evaluate the productivity of that sand, and this well will be drilled obviously based upon the new recommended drilling procedures that have come about because of the previous identification of formation damage, but also will be gravel packed in a way similar to our Lake Washington wells and a pumping unit will be installed to test rates of flow for that particular well.

We also do have some additional exploration activity planned in New Zealand, but that's planned for the second half of the year.

Couple of comments on the natural gas market. New Zealand has an established natural gas market with established infrastructure, but over 80% of that gas market has been supplied by one large field, the offshore Maui (ph) field, which was originally expected to produce a little over 4 trillion cubic feet of gas. Went on production in 1978, and previously been forecasted to deplete in 2009 or 2010.

There has been some recent news, though, where the gas users and the operator of the field hired a third party firm to do a redetermination of the future recoverable Maui reserves, that actually was made public over this last weekend and confirmed what the operator Shell had said last year, was that there was a downward revision in the recoverable reserves and they now expect Maui to really deplete closer to 2007. It's a clear indication of a looming supply crisis for the country. The only other identified or two other identified fields, one of which is the offshore Poho(ph) -Kaura field that Shell also is the operator of -- there were two recent delineation wells drilled in that area.

Our knowledge of the public available information has told us that the northern well offshore was successful and they were pleased with the results. But the southern part of the field delineation well was more disappointed. And that instead of a projected recoverable reserve base of around a trillion cubic feet, they're thinking it's probably more like 500, 600 billion cubic feet equivalent. So these are just further indications of sign that we have seen in talking to the gas users of a strengthening market for natural gas in New Zealand.

Turn it over to Terry at this point to wrap it up.

Thank you, Bruce.

Once again, I would like to point out that we are committed to our operating plan and our focus in 2003. We're very focused and we feel we have an excellent strategy to implement this year. We feel like we're very well-positioned. The company will grow its reserves and its production when we believe we can do that at a low cost, and take advantage of the current environment of the commodity prices, which are well above our budgeted numbers.

In fact it's probably worth while to state that we budgeted this year on a 25 dollar oil deck and $3.50 gas pricing deck, clearly we're seeing significantly higher prices than that. And we will focus our efforts in capturing that upside as it presents itself in the commodity markets. Our capital budget for 2003 is going to be focused on the development of our longer life oil reserves, which have flatter, more predictable, more certain types of production profiles in terms of quality and in particular we find a lot of that opportunity in Lake Washington -- our development program is focused there. Notwithstanding that, we have a lot of opportunity in AWP, it's been a tried and true gas property for us for quite a long time and we will be deploying more capital to that area this year. In fact as Joe mentioned, we plan to drill ten wells the first of which should begin very shortly.

Then later in the year, we'll be putting some rig activity back into Brookeland and Masters Creek per the plan that we have for 2002. In New Zealand, we expect to be able to maintain some high deliverability production at TAWN. We have done the operational things that are necessary. We continue to do the exploitation opportunities there. And as Bruce also noted, we have several operations in the Rimu-Kauri area that will tell us a lot about our future productivity there, what we can expect in the way of future plans and the way of production. We think we're well positioned to solve certain problems and to reap benefits from those solutions. We expect to increase the reserves of the company and production of the company in the range of 7 to 12% during 2003. And we believe we can do that at a finding and development cost in the range of $1 to $1.25 per MCF equivalent.

It's clearly important to our investing public that we state that we are focused on our balance sheet as much as our income statement and we will do those things that are necessary to maintain financial liquidity and at the same time take advantage of the opportunities that present themselves to us.

At this time we would like to turn it over to questions and answers.

Thank you, sir. The floor is now open for questions. If you have a question, please press the numbers 1 followed by 4 on your touch tone phone. To remove yourself from the queue, please dial the pound sign. We do have that while you pose your question, please pick up the hand set to provide optimum sound quality. Once again, ladies and gentlemen, that is one followed by 4. Please hold while we poll for questions.

Thank you. Our first question is coming from Adam Light (ph) of Credit Suisse First Boston.

Good morning, guys.

How you doing?

Pretty good. A couple questions for you, variety of areas. New Zealand production expectations for the first quarter and the year look like they're going down. Is that primarily the result in the first quarter of the Tariki shut-in and other remediation? Is that seasonal?

No, that's strictly seasonal. In terms of our guidance, we really put our guidance out on the lower end based upon the TAWN production because some of that is subject to the gas buyers taking the gas, which is demand-related. We don't want to build that in to our expectations. Based upon the January production levels, though, we would see production in New Zealand staying flat with the fourth quarter or possibly slightly up.

Okay.

Strictly related to the variability of TAWN.

All right.

On the finding cost, looks like your domestic PUD component went up a little bit. Can you, I don't know if you have an estimate of what sort of the all-in finding and development costs, particular to Lake Washington, might translate out to relative to that dollar to $1.25 range for this year?

Adam, are you referring to our forward-look for '03?

Yes, I don't know how much of that rolls through, but I guess if you have a lot of PUDs in Lake Washington, can you give us a sense of what the -

I don't have a total, but we have put out the specifics with regard to Lake Washington and included the future finding, development cost to Lake Washington which were about $75 million, and including those, the overall finding cost of Lake Washington by itself is about 77 cents on the ground on a MCFE basis.

I would like to point out that Lake Washington is clearly where we focused ourselves in 2002, and in that focus, we were drilling all around the dome in many different sand stone, this is not one fault block or one sand. As a result of that effort, you of course would only drill where you had permits. So we had to begin a fairly robust permitting program to allow us in 2003 to come in and do the offsets. At the same time, it's very important to note we have been increasing production there substantially and our plans going forward are to increase production substantially even further, so I really think a lot of the undeveloped that you would see in Lake Washington is in real-time being developed literally quarter to quarter this year.

I mean I think as we stated in our goals for this year, we believe that we can keep finding and development costs for 2003 in that $1 to $1.25 range, that obviously includes some PUD drilling in that but obviously new added reserves as well.

And actually Adam, I'm trying to think through your question, I think to the extent that we're drilling what would be typically classified as cap-ex out of a reserve report, the question I think really kind of relates to do you expect to be able to add additional reserves that are currently not in the proven category as you bring proved undeveloped reserves into service. And our expectation certainly for this year is that we should be able to achieve that and more than that.

Good rephrasing. You segued me in to the next question, which is do you have a production number for Lake Washington, fourth quarter, third quarter expectation?

When you say a production number, are you talking about daily production?

Yes.

You know, what we have said, you know, at year end, 30-day kind of moving average of Lake Washington production from mid-December to mid-January was running net to the company about 4,000 barrels a day, I think it was about 48 or 4900 gross production. We expect the Lake Washington production by the fourth quarter of this year, by the end of the year, to really be above 8,000 barrels a day net. In other words, our goal is to double that net production to the company.

But you don't have a first quarter -

I don't have a first quarter number specifically. What I can tell you, if I look -- I like to look at a moving average rather and daily number because production can fluctuate one day to the next. But we updated that 30-day average through the end of January and the gross production through mid-January was about 4900 barrels a day, I think, through the end of January running closer to 5200 barrels a day. Even in a 15-day period with a moving average you're seeing that cumulative effect of the Lake Washington activity bidding production. And we expect that to continue through the quarter, through the year.

And I might add that, that actually is not going to necessarily be a nice smooth type of growth. We have got some facilities additions and we have an internal assessment by quarter of what our minimum targets are, but we have also clearly put some higher targets before ourselves internally. We just haven't broke those out for objects just reasons because of incremental nature of how that's brought on with facilities. But we're giving you our best estimate on domestic production.

Great. And one last question, if I might. My cash flow estimates show you kind of overspending a little bit this year and that's based on my price forecast. You have talked about balance sheet. Are you willing to kind of draw the revolver a little bit to spend in that 100, 130 range if you don't -

We are willing. We have done a lot of sensitivity to our outlook for the year and we have actually developed a budget that has some variables in it and is performance-based. We expect both to get, you know, certain levels of performance and we may beat that, and obviously then you have the price outlook and I'm sure ours is different than yours, and we actually have multiple cases because our budget case is only $25, $3.50 gas. But we have - about 20% of the budget is discretionary and then we also have dispositions planned in the budget, we may do a little bit higher levels of dispositions if we see better opportunities in our core properties. Obviously if we have higher prices, it may be at the higher end. If we have higher performance, same thing. But if you're on the lower end you have the ability to pull back because you have a discretionary component in the budget.

Great. Thanks very much.

Thank you. Our next question is coming from Chris Miller (ph) of Morgan Stanley.

I guess following on Adam's question a little bit, the one thing that you haven't touched on is acquisitions, you have done those the last couple years. Given that commodity prices are kind of above budget, cash flow should be good, how does that enter in to the picture and would you be comfortable running, let's say with a little more debt if you employed something like a buy and hedge strategy?

Well, I think we have got a very specific debt range that we're comfortable in and we have stated that here this morning. We really don't want to get out of that ratio of PV-10 to debt or debt to PV-10. At year end 2002 we have a 28% ratio. We're clearly aware that prices are, you know, higher than they have been in the past. We really want to look at this on more of a normalized basis and keep that debt to PV-10 ratio on a normalized basis and more like the 25 to 35% range.

So you won't see us making any effort in the way of the acquisition market or in the way of draw-down of our line that would take us out of that range. At the same time there are other ways to do acquisitions as we have noted, we have got some dispositions that we have targeted, but in this particular pricing environment, we might take some other non-strategic properties and actually go at a quicker rate. You're always disposing of properties. That's part of the natural process. But you're also looking at the opportunities in the marketplace and to the extent that we were to increase our dispositions in the short-term, we might redeploy that capital in to a strategic objective. We also, as I noted, we say acquisition, but to develop a core area, we also need to be keenly aware that we have positions already in our unamortized base where we have acreage positions, where we have got significant opportunity that we're working on right now and that in fact may be the way that we build our next core area. In fact, Garcia Ranch is in my judgment right on the horizon of being such an area.

Okay. Thanks. My second question is, what is the cost estimate on the CO2 injection to try to repair those damaged formations? And then if it doesn't work, what alternatives do you have? And with the reserve write-down, does that actually take into account the impact of the reserve damage? Or could there be further write-downs if this doesn't work?

This is Terry. I think the cost is small, it's less than 100,000 dollars, that's the actual service, of course there's probably peripheral costs around there that I'm not including in that. But the CO2 is indigenous to the country, it's in-country. So if you get some good results on what we call our first effort, there's plenty of CO2 in-country to repeat this and maybe even do a larger job later. We really haven't built into our expectations that we're going to have some sort of robust result here. What we're really trying to do is take the recommendations that came to us from core lab, apply those recommendations pretty much the way that they have been made, not changing scope and seeing how their estimates turn out to be. The long and short of it is that in Rimu itself, we do see significant opportunity, be careful how I choose my words, in probable and potential types of reserves that could exist from the Rimu area over to the Kauri area. It's just too early at this time for us to come forward from these core lab recommendations and to give any estimates of how we think they're going to impact production of reserves.

Okay. Thanks, guys.

Once again, to ask a question, please dial the number 1s followed by 4 on your touch tone phone at this time.

Our next question is coming from Nancy Parr (ph) of Loomis Sayles (ph).

Nancy is Andy.

Correct that, Andy.

I had a quick question. I saw a street comment, a passing comment that the Maui field write-down would be negative and I wanted to see if you guys could talk through that and hopefully answer my question regarding how exactly are the gas, how is the gas contracted at this moment? And I guess I'm getting on, your existing gas in the ground right now, how long is that contracted at current prices?

You know, it boggles my mind how someone could view the Maui negative revision as a negative to Swift. It's a real positive for Swift. It may be of greater concern to the country of New Zealand but in materials of the gas market, it's a real positive for the gas market and the price you're going to get.

In terms of Swift's contracts, the way gas is sold in New Zealand is pretty much the way it was sold for decades in America. Sold in reserve-based contracts. You actually contract, carved out an amount of specific reserves to be produced over time at a price. That price is generally agreed upon with a small escalator that essentially relates to the rate of inflation in the country, and that's how ours are. TAWN, when we purchased TAWN, the contract was in place. We knew what the contract was when we expended the capital, made the investment.

At the time we actually assumed the gas price would stay at $1.10 flat because based on the currency exchange rate at the time, that it was outlook. The other thing that should also be noted is the New Zealand dollar has strengthened significantly against the U.S. dollar in the last several months, in the last year and we're getting a much better price than that. There are reserves at TAWN, though, if you do an analysis of the field, it will still be available that are uncontracted. In other words, there's plenty of reserves, proven reserves in the field to supply that contract and more, which you could produce in the new market. But you have to also recognize as I pointed out earlier, we knew what the price was, all the data was available to you when you made your investment. Down at Rimu, what we did is we actually specified a particular amount of gas, which is, as I recall, 38 billion cubic feet under the contract with Genesis (ph). So any gas over and above that amount is uncontracted and would be available to be contracted in to a new marketplace.

When is the first time you would see gas potentially being repriced? Or significant, I mean incremental gas?

I think you see it a little bit of it now. I mean, we have made some arrangements with some of the gas purchasers now to essentially increase the deliverability out of TAWN, essentially producing tail-end gas now and getting a slight premium above the contract. You're not realistically going to see higher prices till new contracts are negotiated and, you know, you have a lot going on in New Zealand right now that has to settle through. Producers and the gas end users have to work through this process of what the price needs to be to stimulate exploration. But the country doesn't have an easily identifiable source of new gas to fulfill the needs of the marketplace. And what has to be determined is a price that, you know, investors can expect to get to make those investments. There is another, as an example, an offshore field called Kupay (ph) discovered in '85, about a 250 BCF field. Wasn't going to be developed in to a market with all the Maui gas, but they're looking at developing it now. One of the key ingredients to that development is what's the price going to be? I think you'll see that work itself out probably in the next one to two years.

Okay.

This is Terry. I think it's also important to note that Kupai is close to our Rimu-Kauri permit area, close to the infrastructure that we have in New Zealand, and we are particularly interested in seeing that field get developed for whatever synergistic reasons might be there commercially.

Okay. Thanks, guys.

Thank you. Our next question is coming from David Silverstein (ph) of Merrill Lynch.

Hi, guys. A question I had was with respect to New Zealand. Can you just comment on this issue with Methanex (ph), and how Methanex being such a large part of the demand for gas in New Zealand, something in excess of 40%, saying now they're going to curtail operations, ramping down to 60% of normal and then how that changes the demand profile that you had presented in January when you did your road trip?

Yeah, the -- a couple things with regard to Methanex . You need to be a little careful of what you read in the press because there's posturing going on between producers and ends users, like athletes negotiating in the press. But the Methanex has a bigger issue because the way the gas was produced out of Maui and taken by the end users, there's more than one buyer of gas, the gas is actually sold to the government and the government then turns around and sells it to the different end users. And just as you do domestically, you have gas balancing issues and Methanex actually took more gas in earlier years, in this redetermination of the remaining recoverable because of their -- they produced overbalanced earlier, someone else gets to balance out and they have little of the remaining recoverable revenues that can be targeted towards them.

That's part of the reasons for comments they have been making recently and you may have also noted they put out that they didn't believe the new reserve report. But Methanex is an important part of the market. We believe they will continue to stay there. They got a billion dollar plant they don't want to shut down. But quite frankly, our forecast, if you look at the forecast of the energy markets without substantial new gas supplies, the country has a supply problem even without the Methanex component, because the growing part of the market is really electricity generation and there is -- one of the electrical providers there wants to build a new combined cycle generating plant but his plans are on hold waiting on an identified source of gas.

We also saw I guess Contact (ph) responding as well, I mean, Contact is buying a facility but they're going to convert to it oil?

That's not necessarily a bad thing because that sets a benchmark in-country for the cost of energy and I'm not saying we're going to be able to get gas to those prices, but certainly does mean people are going to pay that much for energy.

And there are people we have heard are doing studies of importing LNG to the country, again, that's a good thing because it sets a benchmark for energy in the country.

Okay. Thank you.

Thank you.

Thank you. Our next question is coming from Alan Stepa of Gershin Larman Group.

That's Alan Stepa.

Following up on some of the previous callers' questions, if you could provide additional insight regarding your outlook for the acquisition and divestiture market domestically? What are you seeing in regards to pricing on per barrel or per MCF basis in some of the regions at your core areas, if you will?

You know, the prices for -- let me comment first on the acquisition divestiture market. You know, although we look at deals all the time, I would have to tell you we're not one of the most active participants these days but we certainly keep our eye on the market and look for opportunities. But last year was a slow year and I think any time you have a lot of price volatility, it allows for disparity between buyers and sellers, low price environment, buyers want to buy, sellers don't want to sell. As you move in to a higher price environment, sellers want to sell and buyers have to be careful how they buy and I think what you're seeing with some of the recent purchases that have been done, you're seeing a significant amount of hedging activity that goes along with that, that allows people to pay higher in the ground prices. You know, our dominant area, which is the Gulf, south Texas and Gulf Coast area, generally in the ad market getting good prices for properties that have been sold. I think there's publicly available data by companies in that business that would be a better source than me trying to pull a number off the top of my head.

Okay. Just one more additional question. Regarding your development and exploratory schedule, when you look at the whole schedule for next year, as far as the weightings, is it front-end? Back-end or evenly distributed throughout the year for development and exploratory, if you can break out two out separately?

I think it's fair to say that the development is more weighted towards the first part of the year than the second part of the year, though in terms of infrastructure, that's about midyear expansion of infrastructure going on. The development cap we don't view as discretionary. We feel like we have good enough projects that even with weakness in the commodity pricing environment, most of those projects would continue. On the other hand, the exploratory and what I would call the seeding of future opportunities in terms of acreage, seismic, those things, tend to be back-weighted in the year. That's where we tend to have some of our discretion in the use of capital.

I want to comment again on acquisitions. We have a plan in front of us that the significant majority of which is focused on development, is focused on low-cost development, is an organic growth strategy both in the way of reserves and production. And any acquisition opportunity that might present itself to us has got to compete against that. So we're not out there looking to buy something because it's available. It's going to have to compete against any other project we have got, which we know is going to add value to the corporate asset base.

Great. Thank you.

Thanks, Alan.

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

All my questions have been answered, thanks.

Thank, Frank.

To ask a question, please dial the numbers 1 followed by 4 our touch tone phone at this time.

Our next question is coming from Phil Juskowicz (ph) with First Albany.

On divestiture, potential divestitures, any potential areas you're looking at?

Yeah, we actually have a "other" category. We have our south Texas AWP area, our Brookeland and Masters Creek, Lake Washington, Rimu-Kauri, TAWN, we view those areas as our core areas and while we would look within those core areas at what we would call peripheral or off the flank kind of situations, in fact we actually in Lake Washington abandoned some acreage well to the south of us that we have with Hunt. So in the peripheral of some core areas we might do some things, but in terms of what we have identified in our budget and communicated to the market, we only have non-core, non-strategic assets that comprise about, what, about -

It's 8% of the reserve base.

It's a small amount of reserve base.

Okay. Thank you.

Thank you. Our next question is coming from Jeff Robertson of Lehman Brothers.

Good morning. In the press release it talks a little bit about Lake Washington, I think two or five on exploration wells drilled over the last month, which is below the success rate for most of last year. Can you just talk a little bit about those wells and whether or not there was any kind of anomaly in that and what the program looks like going forward for the rest of the 50 to 60 wells you plan this year?

Joseph A. D’Amico: Well, yes, there was an anomaly. We drilled -- out of the five wells we drilled, one well was over on the west side of the dome that was really a step out or the Velacat (ph) well, we were targeting deeper sounds and found the F sand with 24 feet of oil on water, we tried to side track it but we hit salt prematurely and since there is not a lot of control in the area, we decided instead of trying to side track it again we would have to sit back and scratch our heads and think about it. So we end up plugging that well and do some more work on that area.

Then we drilled two shallow wells, very, very shallow wells just around, near the top of the dome, looking for the A 5, A 10, and A 10 50-foot sands, we crossed a couple faults, those wells, we decided p & a. Those wells are so shallow you can't side track them if you cross a fault to get it, to move it updip or move back across the fault, better to drill another well.

The two successful wells we drilled, we drilled one that was in the l sand, which is a deeper sand, and it had a lot of l sand, very excited about it. And it had also a bun of other sands, drilled the 208 well which is a F sand completion, has pay and a bunch of other sands but the F sand has about 140 feet of pay and the rig that was on the 208 moved and is drilling a 209, which is the next fault block over from the 187, about the same depthwise as the 187. We should hit the F sand there, that rig will continue to drill F and deeper sand pays. The other rig is now drilling a 2,000 foot sand well on the northern side of the field, as you recall, 2,000 sand was a sand we found last year and we have had some really prolific production from that sand and once we finished that well, we're going to move over and drill F and deeper sand wells with that rig.

So I would say the first couple wells we drill this year was an anomaly. We had some stuff we're trying to see, areas we're checking out in some of the shallower stuff to see what was there and now we're getting into really what we're planning on doing now, drilling the deeper pay wells. We have the 8400 foot, we have like 14 permits working in the 8400 foot sand well. Those should be, should get approved probably the end of this month or the beginning of March, and so sometime in March we'll move a rig and drill some offsets to the 104 well, which is a 8400 foot sand well that's making about 900 barrels a day. So part of the reason we drill some of these wells is because of permitting and other issues, but now we're in really great shape to drill deeper locations.

Thanks, Joe.

Thanks, Joe.

Once again to ask a question, please dial the numbers 1 followed by 4 on your touch tone phone at this time.

Our next question is coming from Wade Suki (ph) of JP Morgan.

Good morning.

Hi, Wade.

Good, yourself?

Great.

Excellent. I know you guys mentioned possibly bringing in a partner, New Zealand for your wells. Any progress on that front?

Wade, we just started marketing that you.

Did? Okay.

Yeah, we are talking to a few people but I wouldn't expect progress for a couple months. Takes a long time for people to look at that, analyze it, talk to several people and you have to negotiate and sign CAs, you have to give them seismic data, they often reprocess. That's a process that's expected to take several months. We don't expect to spud the well until the third quarter.

I know you mentioned doing something similar here domestically for a couple of your Wilcox (ph) and Woodbine (ph) wells as well?

Yes, we have -- at the Prospect Expo we showed two Woodbine prospects and we showed a couple of Wilcox prospects in southeast Texas.

Essentially, Wade, we and much of the industry kicks off all our marketing and deals at (inaudible), which just occurred two weeks ago, you're just out in the beginning of that process.

Got you. Excellent. Thank you very much.

Thank you.

Gentlemen, there are no further questions. I turn the floor back over to you for any closing comments.

Thank you, everybody, for attending. We're certainly pleased with the results of 2002. But quite frankly, a lot more important than that, we're really excited about 2003 and how we're going to perform and obviously the environment we're in. Thanks again for tuning in. Call us if you've got any questions.

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