SilverBow Resources Inc (SBOW) 2005 Q2 法說會逐字稿

[ OPERATOR INSTRUCTIONS ] Good morning, ladies and gentlemen and welcome to the Swift Energy Company second quarter 2005 earnings conference call. At this time, all participants have been placed on a listen-only mode, and the floor will be open for questions following the presentation.

It is now my pleasure to turn the floor over to your host, Scott Espenshade, Director of Corporate Development and Investor Relations.

Thank you, Ian. Good morning everyone. I'm Scott Espenshade, Director of Corporate Development and Investor Relations. I'd like to welcome everyone to Swift Energy's second quarter 2005 earnings conference call. Terry Swift, our CEO, will provide an overview, then Alton Heckaman, Executive Vice President and CFO will review the financial results for the second quarter. Joseph D'Amico, Executive Vice President, COO, will cover our recent domestic activity. Then Bruce Vincent, President, will update our New Zealand operations. Terry Swift will then recap before we open it up for questions.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates and projections about us and our industry. These statements involve risks and uncertainties, detailed in our SEC reports. And our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes, and have allowed additional time for questions.

With that, I'd like to turn it over to Terry.

Thanks, Scott. And again, thank you for joining this morning's conference call.

The same themes that were highlighted in our first quarter earnings conference call can still hold true today and, in fact, they are becoming more and more visible. Obviously the commodity pricing environment has held strong and is expected to improve even more through the rest of the year. Our production, our corporate production, continues to grow. Our cash margins, that is our cash margins, continue to increase, as well. Yet we know that we've got to keep a watchful eye on our costs, we're watching how well costs increase. We're doing those things you would us expect to be vigilant as these cost increases come, and I believe they will continue to come.

For example, we do see higher costs manifesting themselves in our future development costs. We will talk more about that this morning. Higher commodity prices over the foreseeable future is, in fact, what the oil and gas markets are telling us. As is demonstrated in the forward strip for 2006, we see oil averaging -- $64.50 a barrel for crude oil and over $8.50 an Mcf for natural gas. The question remains for certain enthusiasts that want to know what the reversion to the mean is.

What is the new norm? What is the average? What should we expect? And what are those expectations as they relate to historical price levels? I can assure you that Swift Energy Company is well-positioned to capture value going forward. We're in a new era of energy demand. It's outpacing supply. Higher costs have clearly followed suit with these increases. We're in a tremendously exciting and challenging environment as an oil and gas company.

Swift Energy Company, I believe, has many important competitive advantages versus our peers. One of which is the quality and diversity of our proven and probable reserve basis. We continue to implement our plans, both in the way of development and exploitation of these assets. Our inventory of future drilling opportunities will become more fully understood, appreciated, and valued in the equity markets as we execute our plan.

I'm extremely proud of the accomplishments of our Company and especially our people. We have just completed both our best quarter ever and our best six-month period ever in the 25-year history of this Company. Of equal importance, our corporate strategies and our financial resources are in place for our engineering and Geo sciences teams to expand our organic growth opportunities over the next several years. The oil and gas professionals of Swift Energy Company have many accomplishments, which they can and should be proud of.

Let me go in and cover some of the highlights of this morning's second quarter earnings call here. For the 13th straight quarter, that's 13 straight quarters, Swift Energy Company has beat the consensus earnings estimates. Management believes that earnings are a primary metric for long-term shareholder value, and we're quite proud of this long earnings increase streak that we have. We had earnings of $0.96 [Company corrected following call] per diluted share for the second quarter of 2005, and cash flow per share of $2.40. This was delivered on record corporate production of 15.9 Bcf equivalent. I'd like to talk more about that now, but I will save some of those discussions for Alton, Joe and Bruce, and their presentation here this morning.

In fact, with higher commodity prices and the increased production, we are increasing our guidance. We should see even better reported financial numbers for the second half of 2005. Our 2005 plan for reserve growth is primarily oriented toward exploration and exploitation activity in Lake Washington, Bay de Chene, Cote Blanche Island, which are in south Louisiana, our South Texas activities and New Zealand, of course. This planned activity is very robust for the second half of the year. Based on our planned activity, based on these planned drilling activities, we estimate that our reserves will increase 5 to 10% this year. We also expect to deliver production growth in the 10 to 14% range for 2005. We continue to deliver value to our stakeholders, our shareholders, through our operating results.

For the first half, production increased 10% organically. The 50% capacity increase of our facilities in Lake Washington is on schedule to be completed late this quarter, as was originally planned. This focus on production has allowed Swift Energy to capture value from these higher commodity prices. What a great time to be experiencing record production and record pricing.

Our 3D seismic data in south Louisiana has shown its first exploration success. The Newport prospect, which was drilled recently, together with our Piakau discovery in New Zealand, show us early results that are encouraging in both our domestic activity and our New Zealand activity. This diversified drilling portfolio positions Swift for some higher-impact types of exploration drilling in the second half of 2005. As well as some planned exploitation efforts.

Continued execution of our operating strategy in 2005, as planned, should bring us an excellent year. Our south Louisiana plans call for more wells that will be impactful, not only for production, but also for reserves, especially in Lake Washington. Swift Energy will continue to test very meaningful exploration potential in New Zealand, as well. Layering this commodity price environment with our improved production outlook, we believe we will deliver another year of record results, excellent returns, and increased long-term value to our shareholders.

With that, I'd like to turn the presentation over to Alton to present the quarter's financial results.

Thanks, Terry and good morning, everyone. I'm pleased to reiterate that Swift had its best quarterly and six-month results in the history of the Company. Revenues were $104 million, up 47%, production for 2Q '05 rose 12% to 15.9 Bcfe. Net income was $27.9 million, up 116%. Diluted EPS, more than doubled to $0.96, while net cash flow provided by operating activities increased 72% to $2.23.

Again, as Terry said, Swift's domestic production increase, along with commodity prices received, led the way for our stellar results. U.S. production rose 17% for the quarter, when compared to 2004, thanks primarily to continued success in our core Lake Washington area. 67% of Swift's domestic production for Q2 '05 was crude oil, which, in this current pricing environment, is obviously quite favorable.

With the current weighting of crude oil in the equation, Swift's average composite realized price for 2Q '05 increased 31% to $6.60 per Mcfe. Domestic composite prices actually averaged $7.53, which is up $1.67 from 2Q '04. And New Zealand composite prices rose 27% to $3.79 on average.

Oil and gas sales revenues were therefore 46% above the 2004 quarter. Amidst the current favorable pricing environment, we remain keenly focused on our per-unit cost and metrics, as Terry mentioned in his intro. For the second quarter 2005, G&A came in at $0.31 per unit, in line with guidance. DD&A per unit came in above guidance at $1.81, primarily as a result of increased estimates for future development costs in additional capital expenditures, as drilling and service sector costs increased. Given these increased costs and the expected reserve adds for 2005, we've adjusted our full year DD&A guidance upward to the $1.75 to $1.80 range.

Production costs came in below guidance, due to some efficiencies and some -- and less domestic workover activity incurred in 2Q '05, and production taxes increased, obviously in tandem with higher prices and the production mix that we have. While interest expense came in at the low end of guidance at $0.40. Swift thus realized net income of $27.9 million, which on a per-share basis equates to $0.98 basic and $0.96 diluted, beating consensus First Call estimates for 13th consecutive quarter, as Terry mentioned.

Cash flow before working capital changes for 2Q '05 came in at $69.5 million, or $2.39 per diluted share, while EBITDA was $77 million for the quarter. Both well over the 2004 comparable amounts. Swift's six-month numbers for 2005 were equally as impressive and record-setting. For virtually the same reasons as the second quarter. Detailed first half results are included in our press release. Swift's bank line remains untapped. We had no bank borrowings at June 30, providing plenty of available capital for plenty of value-adding opportunities that may avail themselves.

With respect to Swift's hedging activity, we continue to layer in protection in this very strong commodity market as we continue our diligent price strategy. For the details of our price risk positions, please see our website. CapEx for 2Q '05 was $57 million, and $102 million for the first half of the year, well within our cash flow, allowing us to increase our cash balances.

Our previously-announced increase full-year 2005 CapEx budget of 220 to $240 million should remain well within our '05 cash flow projections, thus continuing to strengthen our balance sheet. As always, we've included additional financial and operational information in our press release, including guidance for the third quarter and full year 2005. With record results and what we see on the horizon, it's hard to contain our enthusiasm about 2005, both financially and operationally.

And with that, I will turn it over to Joseph D'Amico for an overview of our domestic operations.

Thanks, Alton. Good morning, everyone.

I am delighted to report that for the second quarter, total production was a record 15.9 Bcf equivalent, which increased 12% from the 14.3 Bcf equivalent produced in the same quarter 2004, and increased 2% when compared to production in the immediately proceeding quarter of 2005. Second quarter 2005 domestic production increased to approximately 12 Bcf equivalent, an increase of 17% from the 10.2 Bcf equivalent produced in the same quarter in 2004. Primarily due to increased productions in the Lake Washington area. And 7% higher than production in the first quarter of 2005 for the same reasons.

The facility upgrades in Lake Washington are on schedule to be completed in the third quarter as planned. These expansions will take facility-rated capacity to approximately 30,000 barrels per day of oil processing capacity. The principal activities under way are the doubling of the current process and capacity of the CM3 production platform, which handles sour crude, and will soon have a capacity of 10,000 barrels a day.

The CM3 production barges in the sea are awaiting tie-ins to the existing infrastructure. The field also has a high-pressure gas backbone installed which waylaid the efficiency of our gas lift system, and we're also installing additional compressors at the 6700 platform, as well as CM3, which will add to our gas lift capacity. We believe this upgraded system would give a significant boost to production, particularly as we enter the fourth quarter. Additionally, Swift Energy currently has three wells waiting to be completed in the Lake Washington area, which includes the Newport well.

It is important to note that the 3D generated Newport exploration prospect was our first exploration prospect developed using our originally acquired 3D data, set over Lake Washington, and the well tested over 1,000 barrels a day in the production test, but very good pressures for a crude oil well. We have also identified and are permitting two new locations to further delineate this discovery, as well as target some deeper potential.

Swift Energy's Cote Blanche Island, acquired at year-end 2004, has production restored in the second quarter. Production from Cote Blanche Island and Bay de Chene was negligible in the first half, but production increase from quarter one to quarter two as Cote Blanche Island production was placed back onstream. The Company does expect to double daily production from the field by year-end to approximately 1500 barrels per day combined.

We expect Swift's activity for these fields to be similar to our early activity in Lake Washington. That is improving the production facilities, searching for workover opportunities and beginning the drilling program. As for our domestic drilling results, the Company completed 13 of 17 wells in the second quarter of 2005. Domestically, the Company completed 12 of 15 development wells for a success rate of 80% for the quarter, and was 1 for 1 in exploration with the successful Newport prospect.

Swift successfully completed 5 of 8 development wells in the Lake Washington area in Plaquemines Parish, Louisiana and successfully completed 6 development wells in the AWP Olmos area in McMullen County, Texas. Swift Energy also participated in a successful non-operated well in the Brookeland field in Newton County, Texas. Swift Energy has three wells waiting to be completed in the Lake Washington area. The Company currently has two drilling rigs operating Lake Washington, and has recently contracted for a third barge rig that will operate in Lake Washington, Bay de Chene and Cote Blanche Island areas through the rest of the year.

The Company has also contracted for a fourth barge rig to work in these areas that will be available for approximately two to three months during the second half of the year. An additional workover rig is also scheduled to begin working in Bay de Chene and Cote Blanche Island in the second half of 2005, to begin recompletion efforts in both areas. Additionally, the Company has plans to move a rig to the Garcia Ranch area in South Texas later in the third quarter of 2005.

Now I'll turn you over to Bruce to talk about our New Zealand operation.

Thanks, Joe and good morning, everybody. I'd like to cover several things in New Zealand this morning, including our second quarter production, the results of our successful exploratory well, the Piakau well, along with the remainder of our 2005 exploration program, update you on the frac program in the Kauri sand in the Rimu Kauri area. And then close it by talking about the current pricing department.

Second quarter 2005 New Zealand sales included production of nearly 4 billion cubic feet equivalent. This was a decrease of nearly 2% from production in the same quarter in 2004, and also a decrease of 13% from levels in the previous quarter. The decline from the most recent quarter in 2005 was primarily the result of downtime at the Rimu production station due to annual maintenance work. As well as having only two of three scheduled crude oil tanker liftings in the second quarter, as well as some inherent production decline.

In our core areas, production in the Rimu Kauri area averaged just over 22 million cubic feet equivalent per day in the second quarter. This was an increase of 58% from the second quarter of 2004, mainly from the success of our activity in the Kauri sand. Expansion plans also occurred during the annual maintenance work in the second quarter at the Rimu production station, to handle additional Kauri gas in the future. The gas handling capabilities of the plant were increased about 10% to approximately 23 million cubic feet equivalent per day.

At the TAWN fields, production averaged over 23 million cubic feet equivalent per day in the second quarter, which was down 58% from the second quarter in '04 and down 2% from the first quarter of '05. These fields are expected to continue their inherent decline through 2005, although production in the TAWN area could see increased production if the Piakau well is successfully completed, and tests as we expect it will.

Regard to our drilling activity in the second quarter, it began with the Kauri-E10 well which was plugged and abandoned during the quarter. We did encounter the Kauri sand, but found it too tight to be commercial at that particular well site. We also were able to drill an unannounced exploration well, the Piakau well up in the TAWN area. We have just finished logging the Piakau well for an apparent success, and we're pretty excited about it, but I would caution everyone that we need to wait until we complete the well, and have long-term production tests, before we can fully evaluate its potential.

Because of the well's proximity to the TAWN area pipeline and processing infrastructure, connections are being made to test the well through these facilities and begin immediate production. The Piakau well was a 2006 planned activity in the TAWN area, but we were able to bring it forward, due to increases in available cash flow in our Swift Energy and New Zealand budget. We are currently looking at one or more follow-up wells in the area and expect to be drilling the first offsets of this new discovery within the next week or two.

We're also excited about our 2005 Tarata Thrust exploration joint venture with Mighty River Power. This join venture allows Swift Energy to spread our capital further, since Mighty River Power will be providing the drilling capital on three impactful exploration wells in the program. After pretty much a two-year hiatus of significant exploration activity in New Zealand, Swift is currently drilling the Tawa well, and expects to drill two additional exploration wells in the Taranaki Basin under this program. The Goss Prospect in our Waihapa field area at TAWN should immediately follow the Tawa well in the third quarter. And it will be followed by the Trapper Prospect in the [Erola] field area late in the fourth quarter. Both of these sales are part of the TAWN area.

In other onshore Taranaki areas, we are also looking to secure an additional rig to accelerate the timing of other exploration drilling. This drilling will target both previously-identified prospects, as well as new prospects identified from our recently-completed transition zone seismic program. In the second quarter, Swift Energy New Zealand performed 4 fracture stimulations on Kauri sand wells. Three of the four wells, the Kauri-E7, the E9 and the Kauri-A4 saw improved flow rates ranging from twice the pre-frac rates, to as much as 5 times the pre-frac rate. There was no response from one of the wells, the Kauri-E1 well.

In terms of pricing in New Zealand, the sales price of our [Marquis] blend crude oil averaged $50.82. A 36% increase over prices for the same period last year. As we talked about at our analyst meeting earlier in the year, Swift Energy expects to continue to see a strengthening of our natural gas realization, due to the supply and demand fundamentals in New Zealand and these continue to tighten in the country.

This has allowed Swift Energy to traunch into natural gas prospects over time at the increasing market level. The fact that our TAWN production is declining, under an older contract, and the Kauri gas is an increasing portion of the gas stream, which is under a newer contract, it allows Swift Energy to typically realize a higher aggregate New Zealand dollar price each quarter.

However, as currency rates weakened slightly in the second quarter, when compared to the first quarter of 2005, but we're up over the second quarter 2004. Which brought the average natural gas price to $3.05 per Mcf for the second quarter of this year. A 43% increase from the second quarter of last year, and a 4% decline over the $3.17 per Mcf received in the first quarter of '05. Additionally, our contracts for natural gas liquids yielded an average price of $19.30 per barrel for the second quarter of '05. New Zealand natural gas and NGL price contracts are both denominated in New Zealand dollars.

In summary, let me tell you that we continue to be excited about our position in New Zealand. We continue to see the impact of the tightening natural gas market there. And we believe that we are very well positioned to take advantage of it with a significant onshore position of exploration acreage. We have several exciting exploration prospects that we will be drilling, in order to evaluate this potential over the next two years. We believe that our acreage position and our experience at having drilled more wells than any other operator in the last two years, along with our significant position and infrastructure assets, will allow us to exploit the opportunities of this market in this basin.

I appreciate your attention and I will turn it back to Terry to recap.

Thanks, Bruce. To conclude before we open it up for questions, I'd like to remind you of a few other things. Point 1, we are in an exceptional commodity price environment with strong fundamentals. And we now have the best internally-generated opportunities set in the Company's history in our 25-year history, in fact. We've begun the year with impressive financial results and we intend to continue delivering on our 2005 operational plan.

We have a high impact exploration program, both domestically and in New Zealand and it has the opportunity to deliver significant results to our Company, both in the way of reserve growth, as well as shareholder value. We're encouraged by our progress in our core areas, particularly in Lake Washington and New Zealand. As well as our new areas that are in south Louisiana, Cote Blanche Island, and Bay de Chene.

We have a strong and flexible financial position that allows us to take advantage of future opportunities, whether those opportunities are organic growth opportunities through drilling, or strategic growth opportunities through acquisitions.

Before I turn it over to questions and answers, though, I'd like to also emphasize that this is such an exceptional quarter. I want to take the time to thank, personally, the Board of Swift Energy Company, the management team of Swift Energy Company, and our shareholders, for the support and confident they have had in our strategies and our plans. But most of all, we want to thank the hardworking people of Swift Energy Company for their dedicated efforts and the exceptional results that they are delivering.

At this time, I would like to turn it over to the question and answer portion of our presentation.

Thank you. The floor is now open for questions. [ OPERATOR INSTRUCTIONS ] Our first question comes from Frank Bracken with Jefferies.

I've actually got a couple of questions. First, could you expand upon your comments as it relates to Newport? Could you give us a little insight as to just how well the 3D is working, in terms of how well it calibrated to your predrill estimates? Really I'm just kind of looking for some sense of the precision that it's providing you. You also haven't talked much about depth or size of this potential structure. So, if you kind of familiarize us a little more with Newport, I'd appreciate it.

And then secondly, as it relates to the Piakau well, I was hoping you could give us some handle as to analogous production elsewhere, and give us a little handle from an historical perspective as to how impactful this could be if, in fact, the tests support your initial enthusiasm.

This is Terry. Thank you, Frank, for both those questions. We will attempt to answer what we can of those. First, on the Newport prospect, it is one of several 3D prospects that began development late last year, as you will recall. We had shopped the 3D last year, began the processing of it and we are still developing prospects from it. It's a great question in terms of how accurate was our initial drill prognosis against the 3D. I can give this information at this time, we are extremely pleased with the level of precision that we have with the 3D in terms of picking, you know, what we believe were formation tops and targets.

So, from a depth precision standpoint, we felt very comfortable with that. We do have a very nice, productive zone here. We do have some imaging issues, we still need to work out in terms of the salt itself. This is not one of the traditional development zones in the field. I want to stress that. This is a new zone. It is somewhat deeper. It is still in the Miocene section.

We do believe that we need more production testing to determine the boundaries of this reservoir. We do have a delineation well planned this year. Our appraisal well, I should say, that will help us better quantify some of the aerial aspects of this well. We still have additional structural gain, we're not at the top of the structure in this well. I will go ahead and say that to our knowledge we don't have any water yet.

We don't know where the water contact is. We will have to drill even deeper, or I should say outboard and downdip to find the water contact. We're just now putting this well on production in the very near-term. It's not hooked up to production just yet. Still a lot of unanswered questions, but a lot of excitement.

We're reluctant to give an actual volume of reserves on this yet. There is nothing substantial at this point in the way of reserve additions from this. But that's the work for the rest of the year, to prove that out. In terms of acreage that we have, we believe we -- we totally have all the acreage necessary to develop the potential that this reservoir might have.

But I would add that we have options in this area, seismic options that come forward later in the year, and so there are some competitive elements that require us to get all of our information as quickly as we can, and secure all of the acreage that we think is appropriate before we release a whole lot more detail.

Frank, this is Bruce. Both of your questions are very good questions. You clearly targeted two pretty important pieces of information in the press release, and two important activities that we have under way. With regard to the Piakau well, though, the answer is pretty much the same as Terry gave you for Newport, I appreciate everybody's desire to know what it's going to produce, to know what the potential reserves are, but we really just drilled the well, and just logged it. We just set pipe.

We have not completed the well yet. We're going to be in the process of doing that shortly. Then we're going to be moving the rigs, getting it actually off to the side, and we do have sufficient confidence in where to drill an initial delineation or appraisal well, and we're going to begin that really probably in about 10 days. It will probably take us about two weeks to actually get this completed and hooked up to the TAWN facilities and infrastructure.

That's obviously a real positive because we can test it immediately into the infrastructure and begin sales right away. And instead of just testing for a short period of time, we can put it on long-term production test. We are real excited about this. We believe that it could be significant to Swift Energy New Zealand, both in terms of production, obviously both the remainder of this year, as well as in the next, as well as reserve potential.

But quite frankly, we really do need to test the well. We need to drill a delineation well and, then we will be in a much better position to quantify the potential size of the discovery.

Great, thank you very much.

Thank you, Frank.

Our next question comes from Adam Leight with Credit Suisse First Boston.

Morning, guys.

Good morning, Adam.

A couple of different questions here. The drilling success rate -- development drilling success in Lake Washington, can you remind me whether the success rate you had this last quarter is kind of in-line with what you've been doing? And does the new seismic give you an anticipation of seeing somewhat higher levels -- ?

Adam, that's a good question. I'll address it very briefly here and then let Joe give you a little more detail on it. We intend to begin to drill some higher-risk types of wells within the inventory of activity in Lake Washington, both in the way of pure exploration wells like the Newport test. But additionally we've taken wells that are more of an exploitation nature to test different aspects of the seismic information that we have, both in anomalies as well as some fault blocks looking for additional traps. So, we kind of went away from some of what I'd call the very low-hanging fruit, and started moving to more of the higher impact, higher risk types of wells, and we did that on purpose. Joe, you have the actual numbers.

Our success rate has been historically around 75% and we're still around 75%, even though, as Terry said, we're drilling wells that are slightly more in the probable impossible exploitation category, than pure, proved undeveloped locations.

So, we've been really pleased. That's because of the 3D is allowing us to better image our targets and so that's why the success rate has stayed the same.

Okay. Maybe premature to get this answer, but with your projection for reserve increases, do you see with what you're drilling, potentially any shift in the developed/undeveloped mix?

I'm not sure I understand the question. I will say we do believe a significant amount of the growth in reserves this year will come from the Lake Washington activity, if that was the question.

I think he's referring... [ Inaudible ]

Oh, okay. Adam, with regard -- I think you're asking the question about the split between proved developed, and proved undeveloped reserves. And, you know, it's really hard to gauge exactly what that's going to be at this point in time.

You know, we're obviously trying to get a lot of this on production, you know, if we have an opportunity to drill certainly one, but even two delineation wells on some of these discoveries, and clearly you're going to add some PUD reserves, as well as improved developed resources, but to the extent that we can get a number of things on production, that will increase the proved developed side, as well.

I would add to that. Strategically, in terms of our base assets and by that, I mean the assets that are already either producing, or where you have PUDs identified, we pay very close attention to the turnover rate, and how quickly we're going through that inventory and strategically we do want to lower the PUD rate, increase the proven producing portion of that existing base. But when we do have these -- exploration projects and the kind of things we're doing, if we're adding undeveloped in that area, that's going to be a good problem to have.

Okay. And then in New Zealand, can you give us a sense -- a) of how the tanker lifting will impact third quarter projection, and then b) on your guidance for royalty and operating costs over there.

Adam, this is Alton. We've actually built that into our guidance that we have out there for the third and fourth quarter, you know, depending on when the tanker makes a lifting, it might overlap a particular quarter. Hasn't been real significant in the past. We've always had that -- that out there, but it is -- it hit a little bit in the second quarter, but we haven't impacted or reflected in our guidance we show.

Yes, oftentimes some of these tanker liftings, like in this particular case, was scheduled for late in the second quarter, but for various reasons, whether it was weather or whatever, the tanker just didn't get into port in time to make the lifting. That particular lifting actually happened on July 1st or 2nd. You know, those things happen but it really doesn't affect you in the long-term sense.

I was just trying to get a sense of in that 4 to 4.5 Bcfe projection, how much of that is attributable to the additional tanker, whether you're netting something out on the back end or what?

I'd have to go back and look -- you know, we have -- we have essentially a carryover inventory every quarter, and just really a function of how many days --

It's a function of how big that inventory is in relationship to when the last crude oil lifting was. I don't have in front of me what our anticipated third quarter inventory is. You know, I would tell you that certainly the difference is probably not much more than 0.1 Bcf.

Cost increases, royalty and operating costs over there? What's that attributable to?

Increased operating costs, was that the question?

In New Zealand?

In New Zealand? You had the Rimu production station that was down in the second quarter. And then on a per-unit basis, because of the reduced production levels, it brought it up on a per-unit basis.

Yes, that's a good question. And this is Terry. I will answer that further. You know, in the first quarter and second quarter this year, both domestically and in New Zealand, we really haven't conducted a lot of workover activity. We noted that in our press release. We do have plans to do some of that, both domestically, and in New Zealand, during the second half of the year.

All right.

That will increase those costs somewhat.

Great. Thanks.

Thank you, Adam.

Sure.

[ OPERATOR INSTRUCTIONS ] Our next question comes from Sam [Kiston] with BlackRock.

Yeah, hi, guys, just two quick questions. I missed a couple of minutes at the beginning. Can you just update me on the CapEx budget for the remainder of the year?

Yeah, this is Bruce. Our CapEx budget is estimated to be between 220 and $240 million. Adjusted that upward last quarter, and haven't made an adjust at this point in time.

Okay. And at that level of CapEx, do you guys foresee having any excess cash flow this year?

Yes, we do.

And what will the uses of the cash flow be?

Well, obviously we're looking at opportunities for acquiring properties that fit within our strategic core areas, that make sense for us to add to our long-term inventory. That would be the most likely use of that capital if we're successful in making an acquisition. But we don't feel compelled to do one, so we're not going to go and push one, just to do one. I think we're happy to consider that cash into 2006, and give ourselves more financial flexibility, both with our drilling capital expenditures, as well as looking for other acquisition opportunities.

Yes, I would add to Bruce's comment that we design our budget every year with a discretionary wedge and when we make that designation, we work with the Board of Directors to determine just how much more activity we could conduct, both practically as well as cash flow-wise, and we've really now, for three or four years in the running, basically said that when the cash is in the bank is when we will make those decisions on how to utilize it, and not necessarily utilize it prospectively. But clearly we are accumulating now, cash in the bank. The questions that you're asking are exactly the kind of discussions we're having with the Board, about how to get into that discretionary wedge of additional opportunities.

Thank you very much.

Sure.

Thank you.

At this time, it appears we have no further questions. I'd like to turn it back to Mr. Terry Swift for any closing remarks.

Well, again, we'd like to thank you for joining us today. We've had an excellent quarter. And at this time, we will get back to the work that we have forward, and we look forward to the next conference call. Thank you.

Thank you. This does conclude this morning's teleconference. Please disconnect your lines at this time, and have a great day.