先鋒自然資源 (PXD) 2005 Q1 法說會逐字稿

Good day, everyone and Welcome to today's Pioneer Conference Call to discuss this morning's news release. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Timothy Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.PioneerNRC.com. Again, the Internet site to access those slides related to today's call is www.PioneerNRC.com. At the web site, select Investor then select Investor Presentations.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer's news release on Page 2 of the slide presentation and in most recent public filings on Forms 10-Q or 10-K made with the Securities and Exchange Commission.

At this time for opening remarks and introductions, I would like to turn the call over to Pioneer's Chief Executive Officer, Scott Sheffield. Please go ahead, sir.

Thank you. Good morning and thanks for taking the time to spend with us this 30 minutes, I am talking about our first quarter for 2005. Pioneer reported this morning really another great quarter. We had net income of $85 million, or about $0.58 per share. A reported production first quarter at the high-end of our range about 187,000 barrels of oil equivalent. This does exclude 4,000 barrels a day equivalent from our first quarter, our volumetric production volumes that we are removing from our quarterly financials.

The quarter was highlighted by two volumetric production payments, almost 600 million in proceeds. With a run-up in the oil strip price, we ended up doing a third VPP in April with proceeds of about 300 million. We very actively purchased a little over half of our 300 million share repurchase program, about 3.7 million shares, a little over 5.4 million shares for the past two quarters. Now, with $148 million left, we'll continue to be aggressive in the marketplace, especially where the stock price is today.

Continuing to drive down the balance sheet in this price environment that we have, reduced debt $554 million during the quarter. That includes the April 3 Sprayberry VPP. In addition, we sold our Canadian assets or announced a sell, which will close by the end of May, roughly 9 million BOEs for $23 million of BOE in the ground. And that is -- we've got several questions that is in US dollars.

We established an exploration program, we've been working on for about a year and year and half in deepwater Nigeria. We awarded interest in Block 320, which we expect to drill a well in 2006. We hope to hear sometime in the next couple of weeks a potential award of Blocks two and three in the joint development zone between Sao Tome and deepwater Nigeria. And we are still awaiting government approval on Block 256.

Our track record during the quarter, for exploration wells, we had three dry holes, one in the Gulf of Mexico, Tunisia and Block 256 in Nigeria. Then we participated in four wells that, after further testing and evaluation over the next several months, we will discuss both in Alaska, Thunder Hawk and also our discovery in Tunisia.

On slide number four, a couple of -- we have got three new slides to discuss more. The comments that we received in the last three or four months about volumetric production payments, this summarizes the fact that we collected about $900 million for about 28 million BOEs. Obviously we are taking advantage of two things, the highest strip prices we've seen in our lifetime. And secondly, the lowest, coupled with the lowest discount rates.

We felt like it was the best mechanism that's out there in the marketplace to be able to lock in both of those prices and bring those, bring the cash in the door and improve the balance sheets significantly as we will look over the next three or four slides. Pioneer will continue to evaluate these type mechanisms, royalty trusts, MLB structures as funding alternatives, but, obviously, in the tough pricing environment as you will look on the continued improvement of our balance sheet, at this point in time, there is no need moving forward on any further VPPs.

The next couple of slides are new slides we created just to show the reliability predictable nature of our production, and also our operating expense. In each of the three transactions, Pioneer does retain the risk in regard to operational risks, which we'll talk about. In regard to the production risk, this is one of 4,500 wells that we sold in the Sprayberry. We sold essentially the oil production associated with these wells for roughly about a five-year period.

We did not sell the natural gas liquids or the gas coming out of these wells. So we just sold the oil for a period of five years, 2006 to 2010. This is an actual decline curve from one of the wells. You can see the very stable nature, which is one of the reasons that the banks that are buying these overrides are not really concerned in regard to reserve risk. If something does happen in regard to the reserves, the banks obviously are taking the risk. They cannot go after any other production or anything else that Pioneer has.

With regard to the operating expense, Pioneer does retain 100% of the operating expense. So we officially pulled out our track record with Sprayberry lease operating expenses, including taxes, over the last three years. And as you can see, for various reasons, as gas prices have doubled, oil prices have gone up roughly 50%, our base LOE has essentially remained flat. Workovers are up a little bit, not much. But the only thing that does move, obviously with commodity prices, you can see the increases with severance and ad valorem tax. The key point here is, the reason, we've only done about 10% of our production with VPPs is the fact that the remaining percent of Pioneer's production will obviously benefit from the higher commodity prices on the remaining, on that remaining production.

So, moving forward, we are susceptible to higher taxes. We don't think it's worthwhile to lock those taxes in. It's just a question whether or not you are going to believe prices are going to be greater, much greater than $50 a barrel. If prices are going to be $100 a barrel, we'll collect on the rest of our production. But the red bar essentially will double if we see that type of scenario. So we don't mind that at all. You can see the tremendous improvement in financial flexibility.

We fully expect to be driving our debt per BOE and debt-to-book down to less than 30%. Debt per BOE on $1.25 and right now on about $900 million capital budget projected in our base case for 2006, we expect to get debt-to-book down to less than 10% and debt per BOE less than 40 cents per BOE. Obviously, we think it's important to drive down the balance sheet in this higher-cost environment, higher-price environment, primarily to fund a lot of our projects that we'll be approving this year. Discovered resources, in addition to expecting continued further exploration success followed by share repurchases, as indicated on slide number seven.

Let me turn it over to Rich Dealy, our Chief Financial Officer to talk in more detail about the quarter.

Thanks Scott. We are very pleased, as Scott mentioned about, our strong first quarter results. Earnings came in at $85 million or $0.58 per diluted share, representing a 16% increase over 2004 first quarter earnings per share. Similarly, as you see on slide eight, operating cash flow was up 32% over the prior quarter, totaling $335 million.

This increase reflects the higher production volumes during the first quarter and significantly higher commodity prices that we received during the first quarter as compared to the first quarter of 2004. Also on that slide you can see discretionary cash flows came in about 347 million. On an annualized basis it's about 1.4 billion and obviously with a 900 to $1 billion capital budget, shows the excess cash flow we have in 2005.

Turning to slide number nine, oil and gas revenues were $520 million during the first quarter and were consistent with those revenues recognized in the fourth quarter 2004 of $519 million. During the first quarter, the company also recognized another income when you look at our financial statements, 25 million associated with business interruption insurance for down time and delays that we experienced during the quarter at Canyon Express and Devils Tower, the carry-over impacts of hurricane Ivan back in 2004.

Moving to slide 10, production was 189,000 BOEs per day during the first quarter. If you look at the bar, oil and gas sales were essentially flat with the fourth quarter while NGL production was down about 9%. NGL production was down primarily due to mechanical problems that were temporary at a processing plant in the Permian basin, which reduced NGL processing capacity for about 10 days during January.

If you look at the gas bars and if you adjust for the impact of the Hugoton VPP volumes that are excluded from these bars or the first quarter bar, and we have denoted the volume that are excluded at the bottom side in yellow. You can see the gas production was actually higher for the first quarter, principally due to one-full quarter production from the Harrier sidetrack, which we put on back in December, and also the increased gas sales in Canada as a result of our successful winter drilling program up there.

Moving towards the second quarter guidance range, the range reflects our expectations full quarter production from Canyon Express during the second quarter, as we mentioned increasing production at Devils Tower, we completed the remaining wells out there, increased production from our Canadian drilling that will come on here in March and April, that's come on. Also as we move into the winter season for Argentina we'll see increased production coming out of Argentina in the range from 185,000 to 205,000 BOEs per day also reflects the variability of cargo shipments in South Africa and Tunisia during the quarter. The second quarter guidance excludes, as noted in the bottom, 7,000 BOEs per day related to the sold VPP volumes as well.

Moving to slide 11, where we show production on a geographical basis. You can see that Africa sales volumes were down 13% from the fourth quarter. This primarily reflects, as I mentioned, the variability of oil cargo shipments. Looking at Argentina, production was up slightly from the first - in the first quarter from the fourth quarter, primarily reflecting the continued strong gas demand during their summertime period and increased oil sales during the first quarter.

As I mentioned earlier, without the Hugoton VPP volumes, US production increased during the first quarter, as a result of the Harrier sidetrack offset by the downtime in Canyon Express and Permian Basin, so net - excluding the VPP volumes, we're up about 2,000 barrels per day and then down when you backup the VPP volumes.

Turning to slide 12; price realizations for oil declined 7% to $33.27 per barrel, mainly as a result of NYMEX trading month prices being approximately $3.50 per barrel lower in the first quarter as compared to the fourth quarter. And keeping mind that the Company sells approximately 50% of its US production under trading month contracts. Also contributing to the decline in the fourth quarter is the timing of oil and cargo shipments in South Africa and Tunisia, which received lower prices in the first quarter than those received in the fourth quarter.

NGL prices were similarly were down 15% in the first quarter compared to the fourth quarter. This is principally due to the decline in demand for propane and ethane, which caused prices for those products to be reduced during the first quarter.

Looking at gas prices; although, NYMEX gas prices were down 8% in the first quarter as compared to the fourth quarter. Pioneer's realizations increased as a result of a couple of items; one, the narrowing of mid-continent and Permian Basin basis differentials relative to NYMEX prices and substantially less gas volumes hedged in the first quarters compared to the fourth quarter.

And those hedges that we had in place in the first quarter were substantially better prices than the fourth quarter ones. Specifically North American gas prices increased to $5.76 per Mcf, excluding the impact of the VPP, representing a 10% increase over the fourth quarter. In Argentina, our gas price realizations continue to improve as the government price increases take effect, and as a result of increased demand which has led to spot market gas sales in excess of $2 per Mcf.

On slide 13 related production costs. First quarter production costs per BOE were $6.72. As I discussed on our fourth quarter call, going into the quarter, we expected first quarter costs to rise as a result of higher expected ad valorem taxes, more workovers being scheduled during Canada's winter access season and the retention of the operating costs associated with our VPPs unsold in January. However, first quarter actual costs came in slightly higher than anticipated, due to the higher than originally expected ad valorem tax estimate that we gotten the renditions in. We're seeing that we need to increase those estimates slightly, and also, we've had extra Canadian work-over activities during the first quarter.

Specifically as it relates to basis BOE, first quarter includes a large fixed cost component related to Devils Tower that will decline on a per BOE basis, as we ramp up production in the second quarter related to Devils Tower. In addition, we are seeing cost increases in field operating costs, just in conjunction with the sustained higher commodity price environment that we are in.

As we look forward to the second quarter, we do expect production costs to decline in average between $6.25 per BOE and $6.75 per BOE. The decline that we expect is really as a result of greater percentage of our second quarter production coming from lower operating costs properties in the Gulf of Mexico. And in addition, we expect that workovers to return to more normalized levels in the second quarter, as well.

Turning to slide 14; G&A costs were higher than expected in the first quarter due to annual incentive based compensation being paid during the quarter. Additional staffing that we've been hiring, as well as the award of our restricted stock that we did during the quarter as retention to our key employees. We also, as we look forward to the second quarter, we do expect costs to come down slightly to 27 to $29 million in the second quarter.

Looking at interest costs, they were $33 million or down 7% as compared to the fourth quarter. This decreases for the quarter reflects the interest savings associated with the 554 million of debt reduction that we achieved during the quarter, principally related, as Scott mentioned, to the VPP proceeds back in January. Also given the additional 300 million of proceeds received in April for the VPPs sold then, plus the 207 million of anticipated proceeds related to our Canadian divestures that we should receive in late May, plus the excess cash flow we have during 2005, we do anticipate pretty substantial interest costs reduction over the remainder of the years to reduced debt, and as Scott mentioned, we are targeting net debt to book capitalization ratio of less than 30% by year-end.

Moving to a couple of other cost components. DD&A costs for the first quarter were $9.20 per BOE. In the second quarter, we expect DD&A per BOE to range between $9.10 and $9.60 per BOE, reflecting that a higher percentage of our production in the second quarter will come from higher cost basis assets.

Switching to cash income taxes, cash income taxes for the quarter were 9 million and were primarily associated with taxes paid in Tunisia and Argentina. Deferred income taxes for the quarter were 43 million. The Company expects second quarter cash taxes to range between 5 and 10 million, consistent with the first quarter, and the Company's overall effective tax rate in second quarter is expected to be 36% to 39%.

Moving to slide 15; exploration and abandonment costs during the first quarter were $67 million. Approximately 40% of the first quarter expenditure is related to seismic purchases in Alaska and Nigeria which obviously represent investments for the future in these areas. As Scott mentioned, the first quarter exploration program was front-end loaded with seven key wells being drilled. Of the seven, three were unsuccessful and are included in our exploration expense for the quarter.

As we move forward to the second quarter and look forward to that period, exploration and abandonment costs are expected to range between 50 million and 70 million. This range includes carryover costs associated with two unsuccessful wells that were in progress at the end of the first quarter, as well as plans to drill two deepwater Gulf of Mexico wells and plans to acquire additional seismic and support our future drilling activities.

Moving to slide 16; costs incurred for the first quarter were 286 million. We're primarily focused on development drilling in our core areas, and then basically spent 102 million related to exploration activities being the seven key wells, plus the seismic in our focus exploration areas. As it's our normal practice, we've included in the back of the package, Supplemental Schedules that show the scheduled quarterly oil and gas volumes associated with the three VPP transactions we have completed. We also have included a schedule for your modeling purposes of the quarterly amortization associated with our VPP proceeds and how that proceeds will be amortized to oil and gas revenues. Also, the Company includes back there, current commodity from hedge position, our historical price differentials for oil and gas by area, and the detail of first quarter income taxes. So hopefully that will help you out in your modeling efforts.

With that, I will turn it back over to Scott for closing comments.

Thanks. On slide 17, our final wrap-up slide, a slide that we've been using in the last couple of quarters. Just to update you of activities going forward around the globe. Starting with the North Slope; as we have mentioned before, the third and fourth quarter will be our go-forward decision on the Oooguruk Discovery that we made two years ago. We are continuing to evaluate our seismic both 2D and 3D on NPR-A and the storms lead area, and really anticipate a very active drilling program next winter. Five to seven wells probably with two rigs, a lot more active than the first quarter.

On the Rockies/Onshore US; on the Raton, we are still on schedule with drilling and permitting in regard to completing our 300-well program in the Raton Basin. Piceance and Uinta are now fully staffed with G&G and engineering, buying our Denver office. We're seeing lot of opportunities. We are getting ready to start drilling in those two areas, but really won't see ramp-up activity in 2006 and 2007.

Our Canadian group continues to focus on our Conchagua assets and getting ready to start a very aggressive program in the Horseshoe Canyon CBM starting this month in Canada. We're developing a couple unconventional and tight gas plays in the US at this point in time and acquiring significant amount of acreage, and we'll be updating the market over the next several quarters with that activity.

In the Gulf of Mexico, continuing to move forward on several undeveloped discoveries that'll be bringing on drilling sidetracks in some of our existing assets. Also, we'll be drilling a key sub salt well, starting late second quarter, early third quarter. We're starting a very active shallow shelf program in the next three to four months, drilling five to six prospects, and essentially Pioneer will own 100% of these high chances success type prospects that we'll start with that program, as I mentioned, in three to four months.

Argentina continues to still grow in production. Gas prices are continuing to still move up. We've recently have sold some gas in the second quarter at $2.40, so record prices we are receiving for our revenue in gas in Argentina. South Africa, we are very close, obviously, with boards meeting here in the next couple of weeks, on a go-forward decision on South Africa's South Coast Gas, when that is made we'll be making more detailed information about that project, timing, cost of capital and so on.

In West Africa, essentially we've already updated the market in regard to activity. We really see 2006 as really the year that we'll be testing all of our prospects. We'll probably drill, as we had drilled one-draw hole already in first quarter with Devon in Block 256, we may drill or spread light this year on the second well on that block, followed by wells on the remaining blocks in West Africa in 2006.

Tunisia, another discovery we made with E&I, also bringing on - adding three well will be spreading another four to five wells in Tunisia, continuing to ramp-up production there. Followed by late second quarter we'll be picking up a rig with Anadarko and testing Ordovician Gas Play and fracture stimulating a couple of our wells discoveries that we have made.

In regard to -- we have a very attractive growth portfolio. We really see Pioneer allocating a lot of capital to these projects in 2006, 2007, 2008, which is one of the primary reasons we are driving down the balance sheet over the next 12 to 24 months.

Let me stop there, and we'll open up for questions.

Thank you.

[Operator Instructions]

We'll go first to Jeff Hayden with Pickering Resources.

Hi, guys. How are you?

Fine Jeff, how you are doing?

Scott, just a couple of questions, one, could you give us any more color on what you guys saw in the 256 well, and then could you give us a little more color on the two deepwater Gulf of Mexico wells you're planning this quarter?

Yes, Jeff. As I've learned in the past, until I'm 90% sure of the answer, we're not going to give out any details. So no more color. I apologize.

Okay. And the Gulf of Mexico stuff?

No. I'm not going to give out any more details of what we are studying.

Okay. Thanks a lot, Scott.

Sure.

We will go next to Brian Singer with Goldman Sachs.

Good morning.

Hi, Brian.

In the announcement of your latest VPP combined with the sale of Canada there wasn't as explicit a use of free cash flow as there was during the initial couple of VPPs that were accompanied by an increase in stock buybacks. Can you talk about your thoughts on, what you plan to do with that cash flow, and the potential for future acquisitions, the right level of leverage on the balance sheet?

Yes, Brian. As I mentioned already, we're driving down the balance sheet because I anticipate spending about $1.5 billion per year starting of capital in starting '07, '08. $1.5 billion per year based on several existing projects, we're going to improve this year, and several potential discoveries that we had in first quarter, and also expect success the rest of this year and next year.

So we're driving down the balance sheet primary for that reason, second reason is to complete our stock repurchase program, pretty aggressively, and go back to the board and obviously, we'll be recommending, depending on where the stock is, and additional stock repurchase program. Those are the primary two. Last place would be core area acquisitions.

We would like to do in our backyard, but it's a very competitive market and very expensive. So far, we obviously, are not winning any bids. And I think the chances are probably low. That doesn't mean we won't, but based on this price environment, the prices that people are paying do not anticipate spending much money on core area acquisitions. Obviously, the drivers drive down the balance sheet to fund our capital needs in later years.

Great. Okay. That's one more on

Yes.

On the Rockies. Could you break out the production in the US and Canada from the oiled Evergreen properties, and is there any update on the Mannville coals in Canada?

No. There is no update on Canada. And we have not - we'll probably, not break out production on the Evergreen properties. But everything is fine, so moving forward with our 300-well drilling program.

Great. Thanks.

We'll now hear from Scott Burk with Bear Stearns.

Hi. Good morning.

Hi. Scott.

I wanted to ask a few questions about the Horseshoe Canyon. Can you give a little bit of detail on the number of well locations that you have to drill, kind of your acre -- acreage position and also your working interest in that area?

Yes. I think, we've given that in the past, and we have and somewhere between 600, 800 location. And we are permitting about a 120 this year I don't know how many the wells we can get drilled. We own 100% of most of them. So obviously we'll try to drill most of those up in about a four to five-year time frame.

And in terms of reserves per well, do you have any idea what you're expecting there for just your base reserve for beginning it for?

Yes, we've done the same work that everybody else has. We've taken averages based on were in the middle we're surrounded by several wells. We are just assuming the average, hopefully our Canadian none of reserves are booked and hopefully our Canadian program will after the recent divestiture will have a fairly aggressive growth targets over the next four to five years.

Okay. And then, one other final question on the Canadian prices. The prices were little bit higher than what I expected. I'm just wondering is there are you seeing lower differentials overall or are there some things that just happened for your company during the first quarter?

I just think it's a very competitive marketplace. And the market is the realty trust up there. We had some tremendous bids from --

He doesn't understand the question.

Yes. Who doesn't understand the questions?

Differentials in Canada.

The differentials in Canada. No I don't think it had anything to do with the differentials.

To tell you the truth. I think, one of the reasons that had a high value is very long life reserves and they are hard to find in Canada.

Okay. Thanks Rich.

Thank you.

We'll go now to Rehan Rashid with Friedman, Billings, Ramsey.

Good morning Scott.

Yes.

You mentioned in slide 17 on-book discovered resource of 350 to 400 million barrels. Any color on this one?

Yes, since all the discoveries that we've made that we talked about moving forward this year and next year, including deepwater Gulf, Northslope, Tunisia, Southcoast gas, includes Argentina 2-p.

Okay.

And includes our 2-p in Raton.

Okay.

So those are the primary areas.

All right. Thanks.

We'll hear next from Joe Magner with Petrie Parkman.

Good morning. I was wondering if you could talk about some of the estimates involved -- you mentioned or you have a slide in there that has $750 million free cash flow for 2006. What sort of estimates or assumptions were made to get there in terms of production, pricing or CAPEX program?

Yes, I mentioned on the call that we are estimated 900 million as price capital. Chances are capital will be higher than that because we'll be approving several projects this year. Our base does not include any discoveries that we will approve this year or any exploration successes. So at the base of about $900 million, that's about 200 to 250 for exploration and about 650-element drilling. The strip price was used in regard to the commodity price deck.

Okay

And that includes our base price, our base case that we released last October.

So no change to that?

No.

Okay. And you talk about being on track for the Raton development program. Any more details in terms of how many wells have been drilled out of 300 plans for '05?

No. As we mentioned earlier, we are permeating more and drilling faster, especially as we get into the summer months. But we don't see any issues of completing, drilling and completing 300 wells.

Okay. Great. Thanks.

And Sven Del Pozzo with John S. Herold has our next question.

Hello. Would you be able to give a little more information on the Nor-1 well in Tunisia just would like to know about where it is in relation to the Adam wells?

Yes. It's in a large block there, but we won't give out any more information until we have fully analyzed the logs and production tested the well and then we'll release that information. So it will be some time in the next three or four months. But it's in the same block, which is a fairly large block where we had our Adam discovery.

Okay. And who is the operator?

CFNI (ph) operates the block.

Okay. And then I was wondering you might have this one of your production costs in first quarter '05, how much of those might be attributed to the VPP transactions?

I don't have the exact number in front of us. Somewhere between six cents and $0.10.

Okay. Per BOE.

Per BOE. That's correct.

All right. Thank you.

Moving onto Brian Dierghy (ph) with Allstate.

Good morning. I'm looking at some of your credit metrics and adding back some of the VPPs like the rating agencies do. Still seems like you have a lot more, as far as debt reduction is concerned, and I was wondering just from your perspective, when you are analyzing your free cash flow uses, how much more you do you think have you to do as far as debt reduction is concerned to get those outlooks a little bit more or to the stable region or maybe even an upgrade?

Yes. First of all, we don't treat - as debt.

The agencies do, right?

Right. The agencies have done no due diligence at all in regard to our production in decline curves, our risk. So they just have taken some very basic information that's public, to make their decisions. Obviously they are very conservative, but they are doing it with everybody that's done VPPs because of what happened with WorldCom and Enron.

We don't treat it as debt. It sold barrels. Our deferred revenues do go away. For some reason somebody acquires Pioneer or there is a merger, the total deferred revenue totally goes away. So there is a total discrepancy in the accounting convention of how they attract. So our primary goal is to drive down the balance sheet to be able to find our exploration development going onto '07, '08.

Okay. So you don't -- you do have like a specific number you are looking at?

We currently feel like that we have met investment grade statistics. Middle of '06 we probably have triple-b plus if the rating agency leave us at triple-b minus, it's their choice.

Okay. So you are running at how you feel, not necessarily to maintain those investment grade ratings how the rating agencies look at it?

That's right.

Okay.

We'll hear now from Mark Pibl with Barclays.

Good morning. I was just wondering, if you could update us on the bank facility, what the status is of that, and any plans for amendments?

We currently have 364-day facility and we have a five-year facility. And we are in the stage of just evaluating what the next steps are seeing what the bank market is in terms of its being pretty high where we can get some decent terms that we are in the process of evaluating whether, we want to renew those facilities at this time.

Would the amount of the facilities be increased?

We haven't made that decision yet.

Great. Thank you.

And we'll now hear from David Heikkinen with Hibernia.

Good morning, guys.

Good day David.

Had a quick question. Thinking about the increase in costs quarter-over-quarter, and then continuing to forecast operating expenses trending up, an industry-wide problem or issues. Even though margins are doing very well with commodity prices. When you think about your capital budget for the year and some potential increases on success versus increases for services costs, you do have a feel for where your budget could actually range for 2005?

2005 is not going to change a lot, David. It's probably 2006 or 2007 or bigger years, as we ramp up our capital budgets. That's why we basically have to run sensitivity prices at strip and a low base price and try to get a minimum return on a risk basis on all of our projects. If we have a price correction to make sure we get an adequate return, then we look at these strip prices, and then we make decisions on projects in regard to fraternal capital employ. So obviously, to offset rising G&A and operating costs, we're driving down the interest side, interest per BOE side of the equation. So right now, in diction automating a lot of our fields, using our own rigs and -- and saying immensely no on uncertain projects.

Okay.

So, their best way to, I mean, rest driving cost.

And you mentioned '07, '08 CAPEX in the $1.5 billion range, '06 is probably, somewhere between where '05 was and '07 range was going to --

It could easily move up.

Okay. Thanks a lot.

And that is all the time we have for questions at this time. Mr. Sheffield, I'll turn it back to you for any closing comments.

Okay. Thanks. And I know a lot of questions were asked about several of our projects. And as we approve those and get more data we'll be releasing that to the public market and we look forward to seeing everybody there on the road, conferences or one-on-ones and look forward to the next quarter call. Thank you.

Thank you. That does conclude today's conference. Thanks everyone for joining.