SilverBow Resources Inc (SBOW) 2003 Q1 法說會逐字稿

Good morning ladies and gentlemen, and welcome to the Swift Energy Company First Quarter 2003 Earnings Conference Call. At this time, all participants parties have been placed on a listen-only mode and the floor will be open to your questions and comments following the presentation. It's now my pleasure to turn the floor to your host Mr. Scott Espenshade, Director of Investor Relations. Sir, the floor is yours.

Thank you JT. Good morning and welcome everyone to Swift's first quarter 2003 earnings conference call. Today's call will cover our first quarter results for 2003. Terry Swift, president and CEO will give an overview, then Alton Heckaman, SVP and CFO will review the financial results for the first quarter. Joe D'Amico, EVP and COO will cover our domestic operations, and then Bruce Vincent, EVP Corporate Development will update our New Zealand activities. Terry Swift will then conclude before we open it up to questions. We also have with us this morning Alan Cunningham, President and COO of our Swift Energy, New Zealand.

But first, let me remind every one 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 uncertainty detailed in our SEC reports, and our actual results could differ materially. We expect the presentation to take approximately 20-25 minutes and we have allowed extra time for questions. With that I would like to turn it over to Terry.

Thank you Scott. I would like to welcome you again to Swift Energy Company’s first quarter 2003 earnings conference call. Swift Energy Company has just completed yet another eventful quarter that we also view as very successful, especially on the operating fronts of our financial plans. We continue to make a lot of progress towards those goals. We are going to use this conference call to discuss that progress with you this morning.

Production has increased and is on a path to continue increasing. Profitability continues to improve. The balance sheet remains strong and we are successfully developing out our Lake Washington properties domestically, and at the same time seeing important gains in New Zealand. Our business unit there is a profitable business unit that we are very proud of, where that business unit is positioned. We will give you more details on some of the first quarter activity there in New Zealand as well.

Again, the first quarter was a very eventful quarter, particularly as it relates to commodity prices. We saw some very high commodity prices particularly in natural gas. We are once again -- the NYMEX (ph) bumped $10 in January and by March we were around a $5 dollar range on the NYMEX.

It was a very volatile quarter. The actual natural gas process prices received in the first quarter for the company were $6.03 per mcf, which of course was a three-fold increase from the prices received a year earlier. Crude oil prices were also extremely volatile. Of course we all know the events there, centered around the Iraqi war as well as some production problems in Venezuela as well. We feel that as the market has settled down closer to the $5 range for natural gas and closer to the $26 range for oil, that we are seeing some more stability in the market place. While we certainly want to be in a position with our hedging strategies to capture most of that upside, our budget is not designed for those kind of prices. Once again, I would like to reiterate that our budget for this year was designed on $3.50 gas and about $25-26 oil.

We continue to focus on controlling our cost and maintaining conservatism in the balance sheet. As relates to the first quarter results, of course, we did have exceptional earnings for the quarter. In large part due to the commodity prices that we received, but also we made significant progress towards our production goals. We did have a cumulative accounting effect that we go into in detail but before that accumulative accounting effect, which relates to some certain rules or relative to retirement of assets, our earnings increased 247% from the first quarter 2003, earnings of about $10.5m or 38 cents per diluted share, again, before that accounting effect. Cash flow before changes in working capital increased a 176% to $31.6m, very significant for the company result there, that was actually $1.16 per diluted share.

Despite the temporary and partial shut down that we had in Lake Washington that was the result of a pipeline incident on the purchaser's side, we continued to make progress in Lake Washington. We want to go into detail with that today and particularly, I am going to ask Joe D'Amico, our Chief Operating Officer to update you on the wells we have drilled there, the success rates we've had, and the actions that we are taking relative to building facilities and improving that production, getting it to our goals in that area. We're very confident that Lake Washington will meet our goals this year.

Domestic production was 7.7 Bcf equivalent for the quarter, New Zealand production was 5.2 Bcf for the quarter. Total production for the company increased to 12.9 Bcf equivalent, which is on track. It was, of course, a lower range of our expectations, again in large part due to the pipeline incident that we had in Lake Washington.

We are on track for 2003. We set out our goals this year. Clearly, we do believe that from our a stock and equity perspective, we have got a lot of work cut out ahead of us to, as we like to say, put the points on the boards, put the molecules in the pipeline and get the results. We believe that we're on track to do that. We believe we're going to have an excellent year and with that I'd like to introduce and bring forward Alton Heckaman to present the financial results.

Okay. Thanks Terry and good morning everyone. I'll touch on a few highlights from the very detailed financial information we have included in our press release. Swift’s first quarter, '03 production volumes, as Terry said, came in 12.9 Bcfe which was an increase of 5% over the same quarter in '02 and 2% increase over the most recent sequential quarter.

Domestic activities contributed 60% of the production for the quarter, with New Zealand contributing the remaining 40%, in both cases above the recent guidance. Domestic production exceeded recent guidance in spite of the Lake Washington issues while New Zealand production continued to produce excellent results from the TAWN properties.

And as Terry just mentioned, first quarter pricing was very strong. Our average global composite realized in 1Q, '03 price per Mcf equivalent almost doubled to $4.26. Domestic pricing actually rose 145% to $5.68 per Mcf equivalent while New Zealand, with its lower relative gas price component, increased 35%. Oil and gas revenue was therefore 106% above the 2002 comparable quarter. I should note that included another in other revenue for the quarter is $1.4m, due to Swift's derivative product hedging activity, which resulted in a net cost for the quarter. I feel that's a relatively small price to pay for product price protection. Swift thus realized $10.5m in net income before accounting change for the quarter which is 38 cents for both basic and diluted -- exceeding our first quarter call estimates. Net income after the non-cash FAS 143 accounting change that Terry mentioned, equaled $6.1m or 22 cents both basic and diluted. Cash flow before working capital changes for 1Q '03 came in at $31.6m or $1.16 per diluted share. EBITDA was $38m.

As Terry also said in his introduction, we still remain very keenly focused on reducing our controllable per unit cost. And after the first quarter '03 cost, G&A actually came in above our guidance at 28 cents per unit, but it was the result of two main things. Increased corporate governance cost imposed by recent legislation, primarily Sarbanes-Oxley, mainly of an upfront nature -- such as implementation and enhancement of our record retention program, internal audit functions, internal control review and much more. And also, the result of the company's transition out of the public partnership business, thus reducing the reimbursement from such activity. Even with all these added costs as I should note that without the Lake Washington production issues, we would have been within our guidance on a per unit basis.

The DD&A per unit came in within guidance at $1.16. Domestic and New Zealand production costs both came in at or below guidance as economies have of scaled and cost control measures had have kicked in at both Lake Washington and at TAWN. Production tax increases in tandem with price and production increases with the FA (ph) came in below guidance. And interest expense came in at 52 cents per unit below our most recent guidance.

As to our liquidity, our $195m bank line borrowing base, which is has only a small amount drawn, was reaffirmed on May 1st, and as mentioned in our press release we have elected the to lower the commitment amount to a $150m to save on fees with the knowledge that our bank agreement provides for a quick increase if the need arises. We feel we are in strong financial shape to continue implementing our strategy. The strong first quarter pricing environment allowed us to layer in some strong hedges for '03 in the form of participating [audio gap].

Finally, we have included additional financial and operational information in our press release. A summary balance sheet as of March 31, '03, a summary of the income statement with per unit metrics, consolidated statements of cash flows for 1Q, '03 and '02, as reconciliation of cash flows and EBITDA, quarterly operational and financial comparisons both sequential and year-to-year, and of course our updated guidance for the second quarter and full year 2003.

And now I will turn it over to Joe D'Amico for an overview of our domestic operations.

Thanks Alton. Good morning. Let me start in Lake Washington, were barging operations have commenced. Production in this the field is beginning to return to normal levels of operation with no limitations on sales due to lack of transportation facilities. Production is currently expected to reach approximately 6000 gross barrels of oil per day within the next week, and increase to approximately 7500 gross barrels of oil per day over the next several weeks, as the newly drilled wells are completed and brought on production. Seven wells have recently been completed with six additional wells waiting on completion operations, and all of them are waiting on flow line connections. The company has an approximate 82% net revenue interest in this area of the field. Scheduled facility upgrades are underway in the Lake Washington field, that are expected to bring capacity to over 14,000 barrels per day gross processing capacity during the third quarter.

And now for the first quarter results. The company successfully drilled 13 and - 19 wells in the first quarter. The company has successfully drilled three additional wells, two in Lake Washington and one in the AWP Olmos (ph) fields since the last update on April 28th, bringing the year-to-date domestic total 20 successes out of 26 wells drilled. I want to highlight two wells that originally were recently drilled that demonstrate the potential of Lake Washington field. The CM 222 well encountered 230 feet true vertical depth of continuous net pay in the F Sand, with over 30% porosity and permeabilities ranging from one to two Darcies. This is significant, since the best F Sand well drilled to date the CM 187 with a 179 feet of net pay is producing about 1200 barrels of oil per day and has cumulative to production of over 300,000 barrels. Another well, the state lease 212 #139 well encountered two horizons. One of which had approximately 40 feet of net pay in the 8,400-8,500 foot series of sands in an untested fault block adjacent to the state lease 104 well, which is producing about 800 barrels of oil per day.

This new well where will at least double the number of developmental wells in this area, plus increased reserves. The company currently has two drilling rigs working Lake Washington, one rig operating in AWP Olmos field, in the McMullen county Texas. And one rig scheduled to spread to spout a well in the Brooklyn Field in Newton County, Texas in mid-third quarter. One non-operated rig is also working in the Garcia Ranch area, in Kennedy County Texas.

For our second quarter focus, we plan to drill up to 15 development wells in Lake Washington, and we plan to drill 3-5 development wells in AWP Olmos field, plus a well in the Wilcox terrain, while keeping an eye on reducing our LOE.

And now I will turn it over to Bruce Vincent for an overview of our New Zealand operations.

Thanks Joe, welcome everybody. To touch on New Zealand, I want to highlight three areas, the TAWN area, the Rimu/Kauri area, and then I will have really want to touch on the natural gas market in New Zealand, because as we mentioned before we see things changing down there. It will certainly improve profitability for the company.

With regard to TAWN, that asset continues to perform exceptionally well. During the first quarter, it produced and average rate of 53 m cubic feet equivalent per day which is 40-50% higher than it was producing at the time that we acquired the property a little over a year ago. We've been exceptionally pleased with how well that has done, and our people in New Zealand have done an excellent job in increasing the levels of production down there. Second quarter volumes will be down slightly. As we've mentioned, the production station up at the TAWN areas will be down for approximately a week due to normal annual maintenance. We continue to work on exploitation activity in the TAWN fields and are evaluating deeper potential where there has been prior production tests conducted in the deeper Kaputi Sand.

Down in the Rimu/Kauri area, production through the RPS averaged approximately 6 m cubic feet equivalent per day as we had anticipated. This also will be down slightly in the second quarter as the Rimu Production Station will be down for approximately 7-10 days, due to required maintenance activity, 12 months after its has come on stream. Activity in the Rimu/Kauri has been particularly active in the last four months. We've been evaluating several things in that area. In particular, the Kauri Sand, where the Kauri-A4 well was hydraulically fractured in March of this year. Initial tests resulting from that stimulation effort show at least a doubling of the initial test rights rates last fall that were commercial at that time. Plans are underway to connect this well to the Rimu Production Station and place it on a long-term production. We expect this to begin some time early in the third quarter. In the Manutahi Sand, we drilled and completed the Kauri-F1 well in March, and it’s currently flowing naturally and our plans are to install a pumping unit, which should be in place this quarter and place it also on long-term production. In the Tariki Sand, which we've been evaluating some of the past formation damage, we've conducted a CO2 injection of the Rimu-A2A well, the CO2 injection went well and we're currently flowing the well on long-term production test through the Rimu Production Station. While this well is still undergoing evaluation, it appears that this initial CO2 injection has had only marginal success in terms of increasing the level of production from the well. Production rates, however, do appear to have become more steady. Further evaluation is necessary and we'll continue on this well.

In terms of activity in this area for the second half of the year, we're going to follow-up on the success ion the Kauri Sand and plan to drill two delineation wells in the Kauri Sand and also place them on production through the Rimu Production Station. Following up on the success of the Kauri-F1 well and in the Manutahi Sand, we also plan to drill several shallow Manutahi wells and also place them on a long-term production. We plan to further evaluate the CO2 injection in the Rimu-A2A wells as well as other productivity in the Tariki Sand wells. And lastly, we plan to drill at least one, possibly two, exploration wells in the second half of the year.

With regard to the natural gas market in New Zealand, we said for some time the country has a lenient limited supply crisis. It has been quite evident, but it is becoming even more apparent to everybody and we're seeing the impact of that and in particularly when we talk to the gas-end users and the government. Recent moves on the Maui gas field re-determination and the uncertainty of the Foho Kura (ph) delineation joint drilling results had have caused these natural gas markets to improve. The Kauri discovery is not covered under existing contracts and we plan to contract these volumes short-term initially while we conduct further delineation drilling of the seismic anomaly, after which we might expect to get longer term contracts. But we certainly expect to get better prices than we’re receiving under contracts today. The other things that's been particularly important in New Zealand in terms of profitability is that the exchange rate of the New Zealand dollar compared to the US dollar has been moving closer to the 15-year average and increasing profitability of to the company. I'll now turn it back to Terry to summarize it and then we can take some questions.

Thank you Bruce. Once again we've had a very active and productive first quarter for 2003. Joe went through a lot of the operating activities and in like Lake Washington and we clearly are seeing good drilling results where there. We are on track with our development plan in Lake Washington. Despite the problems that we have had out there recently with building facilities that we believe will give us a higher standard of performance and reliability in Lake Washington and at the same time would bring continuing the program to add that productive capacity which of course is going to go through all those facilities. We believe we are on track to more than double the Lake Washington production this year and we will reach or exceed our 8000 barrel a day goal by year end. We are very confident on in that.

We have also had successful drilling and completions in New Zealand, Bruce touched on that. We set out early in the year to have a really methodical approach in New Zealand to implement some improved drilling and completion methods that were presented to us by Core Labs as a result of some of the studies they did. We have seen some good results. We are now tailoring our activity in New Zealand to be able to benefit from the results of those improved operations. We believe we are going to have a successful year in New Zealand again, and are looking forward to adding reserves in production there as well.

I want to put some emphasis on the fact that we recognize it that from an equity perspective, we need to be adding value. And the way we feel that we add value is to get this production on line, to get the earnings to work for the company, and to show the profitability. We are on track to improve our per unit margins this year, both in New Zealand and of course, in domestic. Most importantly, the domestic production is on track, to be rising -- to be increasing as in accordance with our plans.

I'd like to further emphasis that the company is very cautious relative to its cash flow and its access of a very good liquidity. We are going to be very strategic as concerns to any opportunities that we see in what we clearly recognize is a new pricing environment. Gas prices, well, we certainly don’t believe they’re going to go down significantly. Clearly, the $10 price we saw early in the first quarter was not something you want to be banking on or expecting. Yet at the same time, the forward price of $5 is material and beneficial to our operating plan. It gives us guess, as excess cash relative to our initial performance, we are going to use that cash wisely and strategically as we go forward this year. With that, I would like turn the conference call over to question and answers. JT do you want to field the questions for us?

Thank you. Ladies and gentlemen if you do have a question or comment at this time, please press the numbers "1" followed by "4" on your telephone keypad. If at any point you wish to withdraw your question from the question queue, please press the "#" key. Questions will be taken in the order that they are received and we do ask that while posting your question, you pick up your handset to provide optimum sound quality. Due to time restrictions, we please ask to limit yourself to two questions per person. Our first question is from Van Levy with CIBC World Markets. Your line is live.

Gentlemen, how are you?

It's going great and Van how about you?

Doing really good. Couple of basic questions, first, at the end of the quarter, what was the bank debt and what is the either, you know, the hedge price for the commodities, both oil and gas before and after pre-hedge, I guess we have realized price -- so pre-hedge price?

Good question. I want to turn that over to Alton, but I want to reiterate our strategy on hedging before we do that. We have not gone long in our hedging. We have not done swaps in our hedging. Our strategy has been to secure floors at what we believe is a reasonable price. We post all that information on our website and to the extent that we do not have a [floor] on production. We've done some collar transactions. Of course the infamous or the notoriety is the no cost Collar. But what we actually do is we keep 60% of the upside above the Collars high -- higher strike price. So that continues to be our strategy and, knowing the strategy I am going to give it our Alton to answer the question.

Yes, Van, at the end of March we were at $5.7m as far as the bank debt goes and that's about where we are right now. Relative to the hedging, I think, I guess, Terry basically just answered it. We've got a combination or a portfolio of both straight up -floors and cashless collars where the ceiling is only on 40%. So that's all posted out on our website and kept current. I think that’d be the best place to --.

Van did you wanted to know more about how the hedge is has affected -- the pricing of commodity in the first quarter was that --?

Yes, both. But you just update my model what is the --?

I'm sorry. The $1.4m that’s shown, that is reflected in other revenues related to our derivative hedging activity, Van, that is the effect on the our first quarter. That's the cost -- the net cost of our hedging strategy in the first quarter. We actually have --.

Is that all gas?

-- accounting where it is related to the production months January to through March. But as opposed to as being netted out of the oil and gas revenue, it is shown as a separate item.

Right, and is that all gas or --?

There would be some oil and some gas in that number.

I think let me give that before the end of the conference call, Van, and I’ll tell you have already the split between oil and gas for the first quarter.

Okay, and again this just to type of a model. Second question, is kind of a bigger picture question. I think historically you guys have been criticized for not having enough emerging areas of operation. I remember people beating on you when AWP was long on the tooth with higher prices you breathed new life into that field. In New Zealand say, obviously a new area, but it with some question mark at this juncture. Like Lake Washington looks like its doing well and that's going to be a new key area. Do you have any another area that you think, for instance would Garcia Ranch become a new kind of core area? Where are we on the risk/reward or the curve for that? And are there any areas that would possibly emerge as a new core area?

That's good question, Van. And of course we you’ve always got to be looking out beyond 2003, we are doing that. Again, strategically we are focused domestically on increasing our gas reserves and gas production as we look beyond 2003. We have a significant inventory of areas, where we believe we can do that. They clearly range from that area where we already have proven reserves that we think we can expand to areas where we have potential or probable type reserves that need to be put through that working process activity. I would note, and then I' am going to ask Joe to give some specifics, I would note that the areas that are on the horizon that are most obvious are the Garcia Ranch area. Because we've got activity there, we're getting that queued up. And then also in the Lake Washington there are deeper horizons there that we’ve are yet to really talk about, because we are doing our G&G on that right now -- our geological and geophysical efforts. Joe, you want to talk about that Garcia Ranch?

Van, in Garcia Ranch right now we are drilling a development well offsetting a well that is producing about a 3m a day and 100 barrels of condensate a day. We are going for a pressure3o sands in this well. Right now we have three prospects in Garcia Ranch that we are planning on trying to drill starting in the third quarter. Two are pressure3o and one is a non pressure3o. We are exited about the non pressure prospects, we also have three other non pressure prospects in the Garcia Ranch area. We just did a small work up on one of our wells in Montalvo and we got production up to over 600 Mcf a day. We feel like we can drill these well for probably the same cost as drilling an AWP Olmos well, so that the economic returns could be really good in this area. So that's one of the -- we have approximately 44,000 acres in this areas so we have a lot of room to expand.

I would make a couple of comments to that question also Van, its Bruce. With regard to Lake Washington people tend to think of it as a one field but its really multiple fields, because you have numerous sands. There is over 50 identified sands in the field I think we've encountered approximately 45 different sands, we've made completions in about 24 different sands. And so you really have a good diversification within that field. And we haven't even begun to tap really the intermediate to deep depths. The deepest well we have drilled is been about 85,000 feet. I think we’ve drilled two wells or three wells for that depth, and they are all productive at this point in time. The other thing that I want to add is in New Zealand you mentioned question marks, based on the results that we've seen in the first part of this year from Kauri Sand and the Manutahi sand, we believe that those are very much emerging growth areas and will turn into their own little core area. We do think that we need to finish the work this year. We need to drill the delineation wells in the Kauri and couple other well in Manutahi. We are pretty excited about what we are seeing there to-date just in the operations we have done this year.

Also, Van, we are looking at drilling a couple of infield wells in Masters Creek, you know those wells are on 2000 acre spacing and are about 3 miles apart and elsewhere in the Chalk people have been coming in and drilling infield wells with a great success. So, we are planning that right now in Masters Creek to drill later this year and then we are also looking at Brooklyn Field in Austin Chalk, we have some more infield wells to drill there and we are looking at some other potential in that area. So, between the Chalk and South Texas we have, we think, some areas that have high potential for growth.

And last, the reason I asked that question, when I pencil up the numbers, to look at the liquidation value the company I usually get to $15-16 a share, your stock is obviously much lower than that. So the markets given in my mind is going to be a negative franchise value and indeed if you can expand these new areas Lake Washington, Garcia, New Zealand, if that -- you know it works out then you should have some value should be accorded to you for franchise value, which would be above your asset value. So that brings to my next question which is there is a major disconnect, you guys were nice enough to host a great supper in New York, we had a spirited debate and, maybe I had too many spirits, but my notion was that I now would like to see you buy back stock, could you kind of discuss your thoughts on this?

Well, I think I have discussed my thoughts in numerous forms and clearly, you know, there are different schools of thought, different financial models about buying stock back. One of the key issues of course is what other uses do you have for your capital as opposed to buying the stock back. And we believe very positively in the projects that we have, we reviewed all those with the board in great detail and I think it’s fair to say that we do believe and our actions demonstrate that we -- that this use of capital ought to be in our domestic drilling operations and our expansion of our New Zealand opportunities as well. All that said, we clearly recognize that there is a different school of thought and we are monitoring that situation, you know, on pretty much on quarterly basis we have those discussions at the board level.

Great thanks guys, good quarter.

Hey Van, follow-up to your question related to the hedging activity first quarter with the respect to your model. Of the $1.4m, $1m related to gas, natural gas and $400,000 related to oil.

Thanks, I appreciate it.

All right.

Thank you. Our next question is from Frank Bracken with Jeffries & Co. Your line is live.

Thanks. I was hoping to get into a little more of the detail of what’s going on in the New Zealand gas market. It’s clearly having a very favorable impact on both your price and your volumes. And one, was hoping you could maybe quantify the extent to which the exchange rate has helped your gas price in the last couple of quarters? Two, tell us whether you are making inroads in the different markets? And three, can you give us any handle on the extent to which lack of hydro helped your quarter out and kind of trend out the remainder of the year in that respect? I am basically trying to kind of ascertain how much of the gains we’re getting on price and volume are going to stick and how much may be somewhat seasonal?

Okay, we will break that question down into three components. One is the exchange rate in New Zealand. Two, is the new markets that are different markets that we are able to access in New Zealand and third, is actually the status of the New Zealand gas market in terms of fundamentals. And we are going to see if Bruce can answer all three of those but we all are going to hover over and make sure he gets it right.

Well in terms of the exchange rate, I actually probably need to have someone check some numbers to see the impact on the exchange rate versus the market. But one of the things that we are able to do-- well let me answer the second part in terms of the new or different markets. There are of couple of key gas buyers, Genesis Power and Contact and they both happen to be major customers of ours. Contact takes the gas out of TAWN, for the most part, and Genesis takes it out of the Rimu area. Both are major power generators, both have combined cycle generating plants, so it’s the principal use of the gas is to turn it into electricity. Both were having problems in terms of gas availability, both in the short-run and in the long-run. Genesis, as an example, wants to build a new combined cycle generating plant, but needs a more assured gas supply in order to do that. So they’re looking for larger reserves of gas that can assure them that longer term availability. Contact was one of the principal buyers of gas from the Maui field and they had taken more than their share in earlier years. And with the re-determination, they’re kind of left out in the cold with very little if any gas remaining to be allocated to them. So they’re finding themselves on the short end of gas supply right now.

One of the things that you’re seeing in their price, it’s a little hard for us to quantify for you but, up at TAWN, where the significant increase in deliverability is, there is a contract that calls for minimum takes and that contract has an associated price with it. Those reserves, as we have said before, have higher deliverability than the contract -- the minimum types of the contract and what that field was producing at the time that we acquired it. As an acquisition, I know we’ve mentioned this before, but that was a superb acquisition in hindsight for a number of reasons. But one of the reasons was we evaluated it based upon the contract to demounting the throughput, it was going through with the time and as well as the pricing at the time which I think we used the $1.10 for the gas price and $20 for the oil price and prices have dramatically improved since then. And more importantly, the deliverability has improved and we’ve been a part of that. Part of it’s the market related to Hydro, part of it’s the market related to the reduction in Maui reserves. A part of it’s an aggressive effort on the part of our people in New Zealand to further develop the market and work on the facilities so that they could increase the deliverability and assure the customer base, meaning Contact and/or Genesis if they can sustain those higher rates of deliverability, so they can factor that into their planning.

But what they’ve been able to negotiate is essentially a premium for that non-contracted gas, kind of the tail-end gas that you produce. In other words let me try to -- let’s say there is 100% remaining gas reserves. All of those are under the contract – it's a reserve based contract. There’s a portion of those reserves that could bruise out in the future that aren’t contracted and by producing them today instead of a couple of years from now, we’re able to sell them into the market, but at a premium above the contract price. And the gas market in New Zealand is contracted, but all those contracts and the prices are confidential. Because it’s the commercial terms that are competitive with one another, so we really can’t disclose what those prices are. But, some of what you’re seeing in that higher gas price is a result of the higher deliverability that are produced into the market and we’re receiving a higher rate than the contracted price. Some of that also is obviously related to the exchange rate. Trying to actually quantify what’s coming -- what probably we have to do a little bit more work.

I can grab you after the call Bruce.

Yes.

So, in short of a higher than expected gas price environment has caused you to try to take gas that would have historically -- that would have ordinarily been produced at the back end of the reserve life, accelerate the present value, is that a fair assessment?

Higher than expected is a relative term. We have always known that the gas market in New Zealand was going to come to some shortage types of issues, and we have been very positive that gas prices would in fact increase. I think in terms of the exchange rate that was somewhat of a surprise that it would move that quickly. But it’s on a historical basis, again, we felt the exchange rates would go back into a more normal trading range. So, I think we were anticipating these things. We weren’t anticipating them to happen as fast as they have happened.

Right, so this has probably got some -- it would kind of have a negative implication for -- if you’re, I mean if you’re accelerating your production now, you’re going to have almost by definition a shorter RP ratio. What are the things you can do to add new R to the equation, and could you discuss the timing on those specifically?

Sure. Let me, let me come back to the previous questions first. With regard to the exchange rate, when we actually bought the TAWN facilities, I think, the exchange rate was 42 cents to the dollar or something like that. It probably averaged last year more like 45-50 cents on the dollar, and today it is 56 cents on the dollar. So you have 10-20% increase in the value attributable to the exchange rate. You are right, obviously producing reserve short of the same amount. Reserves you are going to get a lower reserve reduction ratio but significantly improved value for the assets.

In terms of the reserves, there are several things we are doing. In TAWN itself, there are several exploitation projects in terms of -- some of it’s minor stuff like gas lift, increasing productivity, lengthening reserves, there might be some re-completions that we are looking at, there might be some additional drilling activity in some of those sands. We are doing some work in terms of further mapping and step up the existing productive sand, but also there is a deep structure that is very evident on seismic. Fletcher Challenge had drilled the well and tested Kapuni Sand over 3m a day. So we know there is productive sand when hydrocarbon is down there, that's a mappable event on seismic. Plans are to drill a well, but probably not this year, probably next year. The other part of the reserve equation, we are pretty excited about, but I think it is premature to quantify in any way is the Kauri sand, certainly in terms of gas and the Manutahi Sands and in terms of oil. The Kauri sand, one of the reasons that we like that particular sand is that it's a mappable event. It was drilled on a seismic anomaly. It is clearly a direct hydrocarbon indicator. That anomaly covers an area of 4,000 acres. So it's fairly large aerial extent. What we don't know, is that anomaly productive over that internal aerial extent. We know it is productive it with the Kauri A-4 well and those are the only reserves we’ve booked to date. We do have plans this year to drill two delineation wells and we should be able to get them also hooked into the Rimu production station fairly quickly. And you know, we think that those wells will add significant amount in terms of reserves and production but if that seismic anomaly is productive over a, you know, good portion of it, it would add significant reserve potential not only to our company but the kind of thing that the country is looking for.

Gentlemen, it appears there are no further questions coming from the phone lines at this point. If you have any question or comment, please press the number "1" followed by "4" on your telephone keypad. Thank you. Our next question is from Jeff Robertson with Lehman Brothers. Your line is live.

Good morning Bruce.

Hi Jeff, how are you doing?

Fine. I stepped away for a minute, so I'm not sure if you answered this question or not, but Joe talked about drilling a couple more wells at AWP Olmos and the one at Brooklyn and just two questions. One, could you step that up with where gas prices are over the rest of the year in terms of activity? And at the Brooklyn Field, Joe, is that the Wilcox Test or the Vicksburg (ph.) Test you are talking about drilling or is that a Chalk well?

That's an Austin Chalk well at Brooklyn. And yes, we are moving it up in our schedule. Likewise, at AWP. We had originally planned to drill three wells in the first quarter at AWP, but unfortunately, they had extensive flooding down there, so we couldn't get a rig in and so now since it stopped raining for a brief period of time, we got a rig in and we are drilling three wells right now and we plan to drill at least seven more and may step it up and drill even more.

Okay, I noticed that people have been drilling I think the Wilcox and Newton county, which I think you said is where your Brooklyn Field test is?

Yes, we have.

Is that something you are all looking at as well?

Yes we are.

Okay.

Yes, we are actually -- one of the wells we have there is Wilcox producer, I don't know if you heard Joe say that.

Okay. Alright, thank you.

Thank you. Once again, ladies and gentlemen if you do have a question or comment at this time, please press the numbers "1" followed by "4" on your telephone keypad. Gentlemen, at this time I am showing no further questions on the phone lines. I forward back it to you for any closing comments.

We just like to thank you once again for joining us on our First Quarter 2003 conference call and we look forward to getting back with you with more operating results. So, thank you again.

Yes thanks everybody.

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