先鋒自然資源 (PXD) 2006 Q1 法說會逐字稿

Welcome to Pioneer Natural Resources first-quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim 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.PXD.com. Again, that Internet site to access the slides related to today's call is www.PXD.com. At the website, select investor, then select investor presentation.

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 the 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 Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for this morning's call. Scott Sheffield, our Chairman and CEO, will be the first speaker. He will provide the financial and operating highlights for the first quarter of 2006 plus provide an overview of the Company's progress towards achieving its production and growth goals for 2006 and beyond. You may recall that at our March analysts meeting, we committed to provide a quarterly update on how each of our assets is performing against its 2006 production and operating goals. Tim Dove, Pioneer's President and Chief Operating Officer, will provide this update after Scott concludes his remarks. Rich Dealy, our CFO, will then cover the financial highlights from the first quarter, which included the impact of two large asset sales and several unusual items. He will also provide earnings guidance for the second quarter. After that, we will open up the call for your questions. With that, I'll turn the call over to Scott.

Thank you, Frank, and good morning. On Slide No. 2, financial highlights, Pioneer reported net income of 543 million. That included an after-tax gain on the sale of our Deepwater Gulf of Mexico of 472 million. Reported first-quarter production of 95,000 barrels a day equivalent. Obviously we're becoming very confident that we'll meet or exceed our 2006 exit rate target of 95 to 100,000 barrels of oil equivalent per day.

We did complete our two divestitures. In first quarter, we completed our Deepwater Gulf of Mexico sale at $65 per BOE on proved. And then we completed in April our sale to Apache of all of our Argentine operations for 675 million.

We will begin later this week to complete our $1 billion stock repurchase. We have remaining about $359 million. And just recently, we issued 450 million senior notes due 2018 with investment-grade covenants to refinance senior notes maturing in January of 2008.

On Slide No. 3, operational highlights. Obviously, we're seeing a lot of success in our Spraberry and Raton accelerated development drilling programs. We are on track to meet or exceed our 2006 production targets that we laid out last March. In addition, we're continuing to have 100% success in the Edwards Trend resource play with another field discovery in addition to the one we have announced. This will be adding significant production above our five-year development plan that we laid out last March. That is a 10% compounded annual growth rate from development drilling only.

We had a very successful winter drilling program in Canada in both Horseshoe Canyon and Chinchaga. Production is ramping up, as Tim will talk about, beginning in April and going into the second and third quarter.

Our rig count, we've secured all of our rigs to execute our plan. We began the quarter with about 27 rigs and we'll be at 44 rigs by year-end.

Oooguruk and South Coast Gas projects are on schedule for delivering production in late '07 and early '08.

Slide No. 4, a slide that we laid out to see where the growth is coming from. Obviously, we are seeing much better rates coming out of the Spraberry and Raton, driving our blue development wedge of delivering a 10% production growth over the next several years; and combined we're seeing a lot of the magenta color coming out of the Edwards, obviously with a lot of production coming on over the next several months coming from our two field discoveries there. Obviously, we are very confident that this growth plan is going to work and probably work as well or better than shown here. Let me now turn it over to Tim Dove to go over each of our assets.

Thank you, Scott. As you mentioned and as has been the case in terms of our prior information in terms of the prior graph, North American production growth is really the driver for meeting the Company's overall growth targets.

If you look at Slide 5, we have started a positive trend in that regard. We reported North American production of about 87,000 BOE per day in the first quarter. That is up 6% from the first quarter a year ago. So showing a positive trend, but the fact is we're really just ramping up growth. We really anticipate getting to an over 10% growth rate on North American assets as that production is ramped up from the drilling campaign.

We think it's clear, looking at our forecast, that we'll be able to meet or exceed our exit rate that was established during the March analyst presentation of 90 to 95,000 BOE per day for 2006. As Scott mentioned, this is reflective of success and growth from several of our key development assets, which I will talk more about in some subsequent slides. But important to that of course is the Spraberry and Raton production results.

Turning then to Slide 6, focusing now individually on assets as we go through the presentation. Spraberry is a foundation resource play for us; and it is the case that we're starting to see the impact from ramping up the activity, ramping up drilling, we're starting to see the production impact of that, which we anticipate continuing through the rest of this year. Production for the first quarter was about 22,000 BOE per day and that is up substantially, up 16% from a year ago.

It's the case in our drilling program at Spraberry, it's repeatable results, it's predictable results, so we can pretty much accurately estimate future performance.

And with the drilling campaign increasing from 190 wells last year to 350 wells in 2006, we anticipate that our production will be ramping up as we go into the future quarters. This increase in development drilling is in response to very high margins in this core business. We are on track essentially with our drilling campaign. We have drilled 76 wells through April. We're going to reach that target of 350 by ramping up the rig count. We will have 18 to 20 rigs by year-end. But we're currently only operating about 11.

We also are in the midst of an aggressive leasing campaign. We have added about 30,000 gross acres in the Permian Basin. This is periphery acreage as well as acreage which is internal to our existing operations.

Suffice it to say when you look the left-hand graph and you look at the red line, the red line represents, from our March analyst presentation, what we have forecasted Spraberry's annual production for 2006 to average. You can see that our first-quarter results are essentially at that average of about 22,000 barrels a day. And with the growth we anticipate for the subsequent quarters, we believe that we will be able to exceed the annual production forecast that we set in March for this asset.

Slide 7 is a similar slide for the Mid-Continent assets. You will recall here we have two producing fields, which are on slow declines. These are our Hugoton and West Panhandle fields. But with drilling and other activities in the field, we essentially have been able to keep production flat. As shown in the first quarter of 2006, we produced 131 MMCFPD, essentially flat from a year ago. And that is a result of the activities in the field operations.

In a similar vein here, you can see that our March forecast for production from these two fields for the entire year is about 117 MMCFPD on average. With the excellent first-quarter results and the anticipation that our exit rates will exceed that, we now believe our annual production will exceed that March forecast. We'll be doing that by drilling some wells. We'll be drilling about 40 wells combined in these two areas; and we're also pursuing some field rule changes to reduce spacing in the West Panhandle field that will hopefully unlock several other locations, maybe 100 drilling locations, and allow us to commence production on an additional 30 wells.

Slide 8 is a beginning discussion of our Edwards Trend area. This is rapidly developing as a significant growth vehicle for the Company. What you see on this slide is production essentially only from the Pawnee field area. You can see production for the first quarter was about 39 MMCFPD. That's about 2 MMCFPD over the first quarter of 2005, up about 5%. Again, just Pawnee field production.

You see that our average forecast for the area for the year in the March analyst presentation was about 40. We think we will blast by that based on the success we have had in some of our new drilling, which I will talk about on the next slide. The new drilling successes being tied in will allow us to easily exceed that forecast.

We have a 25-well development program we're working on. Several of the 25 will be applied to new development drilling from the new discoveries that I will talk about on Slide 9.

As Scott mentioned earlier, we have had some very exciting early success in the trend with 100% drilling successes. We control the trend in the sense of acreage. We have over 200,000 acres locked up. The first four wells in the Sinor area, we believe, have established a new field similar in size to Pawnee; Pawnee being roughly about 300 Bcf. We're right in the midst now of planning out the pending development of this area. The wells IP'ed at 2.5 to 3.2 MMCFPD each on an unstimulated basis, so those are very good wells. And we should have each of the four wells on production by the end of this quarter.

The second new field discovery is something we're just announcing today. It's a well that we drilled at the Stingray prospect. This is really the first well that we have drilled a substantial distance from Pawnee. In fact, this well is about 90 miles northeast of Pawnee. But the impressive thing about this well, it has similar pay to Pawnee type wells but substantially better porosity. And toward that end, we would call this really an exceptional well when it comes to Edwards Trend drilling. This well we'll have on production as well in the latter part of the second quarter. But because of this success, this will be a field will be in future development as well. We think it'll be a major contributor from the standpoint of future production.

In addition to this drilling, we're also going to keep marching down the trend. We have got three additional prospects downtrend that we will be drilling as the second quarter proceeds. These are new field targets, again, similar to what we drilled at Stingray.

We have four rigs working in the trend and we will be adding three more between now and the end of next year and perhaps even more as we have more successes here. With the success, we're going to be increasing the number of wells drilled in this trend to a total of 35 to 40 wells and about a third of those are targeting these new fields down the trend. That is increased from 20 to 30 wells that we had been talking about in March due to the success we have had in the trend. So we're very excited about how Edwards is moving ahead in its early stages.

Slide 10, a discussion of Raton. We are very encouraged by Raton's performance. Our drilling campaign is on schedule. We have drilled 94 wells through April with a target to hit 330 wells. You'll remember last year, we got a little bit behind because of weather and other matters. This year, we are right on the mark in terms of our drilling campaign. We have done a lot to improve wellhead compression; and compression in general is reducing pressures in the field, which is allowing us to begin to see the growth -- the type of growth in production that we have been expecting out of the field. So we produced 149 MMCFPD in the first quarter; that's up about 6% from last year's first quarter.

And toward that end, we're very close to, at that rate, what we estimated in March to be the year average for 2006 from this field. So again, we anticipate that we'll be able to exceed that annual target and be on this 5 to 7% annual growth rate that we have been talking about for Raton.

Slide 11 and 12 cover our new asset plays in the Rockies. There are three different resource type plays that we're working on in 2006 to determine their commerciality, and hopefully decisions can be made on each between now and the end of the year. Each has its own challenges. In fact, in each of these, we have three different water and gas treating facilities because water handling in these CBM plays becomes really a critical challenge.

At Castlegate, we have just now completed the horizontal pilot that is referred to at the top of Page 11 and we're going to be evaluating that as well as drill another high-density pilot. And we will be evaluating these wells in terms of their performance to decide whether a project can be sanctioned here by year end.

At Columbine Springs, we have an active program, where we have a seven well pilot that we're working on now. We have six of the wells already drilled; and we are targeting adding existing wells to production so as to evaluate the performance of this field again between now and the end of the year. We have successfully drilled a water disposal well in the field that will help again in this process of moving water off the coals.

In Main Canyon, we are drilling three conventional Entrada gas prospects that are based on 3-D, existing 3-D. The idea here is evaluating the potential for sands based on identifying porosity through seismic anomalies and seismic amplitudes.

On Slide 12 then, let's talk a little bit more about Lay Creek. We are very excited about our early returns at Lay Creek. Remember there, we're doing reworks on a couple of existing pilots and putting in some new pilots of our own.

In the case of the existing two pilots the prior operators had put in place, very exciting news that we have determined now from reworking these, the wells in question, that the coals are in fact permeable and can be put on production without excessive water. That was one of the keys to Lay Creek. And then we're also in the process of putting two disposal wells in place so as to take the water off the coals in volume. And we expect to basically complete the rest of the wells by the second half of this year and put gas on production for sales by year end with the idea of again evaluating these two pilots.

But it's also in combination with some new pilots we are putting in place from a fresh start. We have drilled a new five-well pilot towards the Southern end of the acreage, as shown on the map. And we're happy to say the coals are thicker than expected and continuous and we have been able to confirm gas content. All these are critical towards evaluating the future potential for Lay Creek.

We are putting in place two additional pilots. The first has already started to be put in place and then we'll continue that over the next couple of quarters.

Essentially at Lay Creek, just like Columbine Springs and Castlegate, we are evaluating the pilot results in these areas to determine the commerciality of these fields hopefully between now and the end of 2006. Substantial potential in the sense of Lay Creek though, with greater than 1 Tcf resource potential.

Slide 13 is a discussion of Canada. Canada is a solid contributor to growth in the Company. Scott mentioned that we're just now seeing the ramp-up that happens every year as a product of the winter drilling campaign. We produced 40 MMCFPD in the first quarter and that's up from the first quarter of 2005 marginally. Our current production is about 47 MMCFPD, ramping up as these winter access wells are brought on stream.

We have an annual target for Canada of roughly about 55 MMCFPD feet per day on average for the year. The reason this is relatively higher is, number one, we're bringing in the Northern access wells as well as tying in a substantial number of Horseshoe Canyon wells, both from this year and last year. We are ramping up drilling in Horseshoe Canyon to 200 wells in 2006, in addition to which we will be tying in 100 wells that were drilled last year but not yet put on production. In fact, there are 10 to 20 wells that are ready to be put on production as we speak that are behind one compressor that we should have on shortly. We did drill some wells earlier this year, about 18. We have the rigs in place to drill the balance of the locations as we get into this year. We're right now limited because of road bans as the frost is coming out of the ground in Canada.

We will be drilling two horizontal Mannvilles -- Mannville CBM tests, coalbed methane tests, in the Bashaw area during the second quarter as well. The early drilling from what we think will be a 6 to 8-well campaign in the Mannville. Overall, we anticipate Canada to meet its production goals that were laid out in the March forecast.

Slide 14 is the South Coast Gas update. Essentially this project is moving ahead smartly on -- it's on budget and on time at this point. We've drilled two wells, waiting for those to be completed. We've got several more wells to drill this year as we continue with the development of the project, with first production anticipated in the second half of 2007, on schedule.

Going to Slide 15, Tunisia, we still believe Tunisia has core area potential. We need to ramp up the drilling in our areas and we're doing just that in 2006. We have drilled another success in the Adam concession. We're now 9 for 9 in drilling the Adam 4 well successfully. We are also acquiring 3-D over both Adam and into Jenein Nord, the new area we've acquired the balance of the interest in, and we're going to be drilling several wells in this area.

As I mentioned, Jenein Nord is adjacent to Adam. It has similar prospectivity to Adam. So we're now up to having 100% working interest in the block and we're rigging up to drill three wells here in the latter part of this year. Testing very similar prospectivity as what has been the successful wells drilled in Adam.

We also have another well to drill in the Borj El Khadra block which is also adjacent to the same areas of Adam. And we're going to be drilling one well there here shortly in the second quarter.

Slide 16, Africa. We have two areas of production of course, Sable being offshore South Africa and the Adam concession I mentioned a moment ago. Both of these areas are exceeding goals or exceeding expectations. In fact, overall, Africa production was about 8,000 BOE per day in the first quarter; that's of course down as both of these fields are on declines from the first quarter of 2005. But they are exceeding our internal forecast. You can see our average forecast for 2006, as outlined in the March analyst meeting, was about 6,000 barrels a day. We now anticipate that will be about our exit rate, so we anticipate that the Africa production areas will exceed their plan for 2006 overall production.

The Tunisia production deserves note here. We had about 3,000 barrels a day of net production in Tunisia in the first quarter of 2005. That would be up slightly in the first quarter of 2006 other than for the fact that our equity has been reduced from 24% down to 20% by contract in Tunisia.

So essentially, these areas are important from the standpoint of current production. But more importantly, the South Coast Gas project can add significant production as we look ahead to next year and then hopefully our Tunisia drilling will provide success in these areas that I mentioned, Adam, Jenein Nord and BEK.

Slide 17, this is the Oooguruk update. We are extremely pleased with our accomplishments this winter on the project. The gravel island that you see in the photo below is now completed. We moved 420,000 cubic yards of gravel out to build this island. As you see there, it's about 31 feet high. That is actually sitting on the seabed. With that completed, now this summer we can contour and armor the gravel and we're right now in the process of fabricating all of the modules that will be used on this drill site and they will be put in place in the next winter. At the same time, we are modifying a drilling rig that will also be installed in 2007 and the hope is we'll even be able to begin development drilling in the latter part of next year for first production in 2008. So this is quite an accomplishment for our Company and for our Alaska division.

So in conclusion, looking at Slide 18, we feel very good about meeting our 2006 production targets. Overall for the first quarter, our production was about 95,000 BOE per day. We now believe that we will be able to meet or exceed our March forecasted exit rate of 95 to 100,000 BOE per day by virtue of all the areas that I mentioned that are in effect exceeding their own targets.

The key takeaways from this discussion of operations are as follows. Our North American production is up 6%, heading towards a 10% plus growth rate, as we ramp up Spraberry, Raton and other areas. We have rigs in place to effect this production increase and we will be ramping up our drilling campaign in these critical areas.

The two new Edwards fields are substantial and will be adding to future production. And that's not the only places we're getting benefits. We have additional upside from several of our resource plays that I mentioned in the Rockies, our Tunisia drilling campaign and some of our other Gulf Coast onshore areas that will be also seeing drilling in this year. And of course Oooguruk and South Coast Gas being on schedule provide us confidence in our plan as well.

And overall, as Scott mentioned this as well on his slide on production, we remain very confident in delivering the double-digit compounded annual growth that we'll be seeing over the period of 2006 through 2010.

And with that, I'll turn it over to Rich for a discussion of the first-quarter results.

Thanks, Tim. Net income for the first quarter, as Scott mentioned, was $543 million or $4.28 per diluted share. It did include a gain on our disposition of the deepwater Gulf of Mexico assets that we sold to Marubeni of $472 million for the quarter or $3.72 per diluted share.

The first quarter also included an increase in our abandonment charge related to the East Cameron 322 facility that we lost as part of Hurricane Rita on the shelf. We increased our accrual on a pretax basis, up from $44 million to $86 million during the quarter or a $42 million pretax charge, which is equivalent to the $27 million on an after-tax or $0.21 per diluted share.

We had two gains during the quarter related to business interruption where we finalized a couple of those claims. The first was on our Fain Gas Plant that we had a fire last year; we recognized $3.6 million during the quarter as the final settlement of that business interruption. As well as we had a policy for $4 million on our East Cameron 322 facility that we have recognized as well. So just under $8 million on a pretax basis, $5 million after-tax was included in the quarter or $0.04 per diluted share.

In addition, as we mentioned earlier in our press release in April, we did drill a dry hole on our Pina well on Block 256 during the quarter and the dry hole costs plus the acreage costs totaled $33 million. Because of our situation in Nigeria, where we haven't yet generated income, we're not able to recognize the income tax benefit of having that write off. And so during the first quarter, we wrote off the valuation allowance or wrote off the tax benefit that we would have normally achieved in most other jurisdictions; and so earnings were reduced by that $17 million benefit that we can't recognize yet.

Also included in the first quarter, the deepwater Gulf of Mexico and Argentina, their results of operations; in total that was $72 million on an after-tax basis, that we recognized in the quarter as discontinued operations, along with the gain on the deepwater sale. So in total, those are all reflected in the income statement or will be reflected as discontinued operations.

Operating cash flow for the quarter was $303 million, consistent with first quarter of 2005.

Turning to Slide 20, the real price realizations here, all these reflect continuing operations so they do not reflect any deepwater Gulf of Mexico or Argentina activity. And so I think to start with on oil, as you may recall in 2005, we entered into two oil VPPs that basically began delivering volumes beginning January 1, 2006. So for the first quarter, it is the first time we have VPP deferred revenue amortization hitting our first-quarter realizations. So the 9,000 barrels a day that we started delivering January 1 had the impact of amortizing into oil and gas revenue or oil revenue in this case $12.91 per BOE. Adjusting out the oil deferred revenue, oil price realizations were up 17% compared to the fourth quarter at $47.10.

Looking at NGL prices, NGL prices declined 8% during the quarter to $34.20, primarily due to the decline in demand for ethane and propane.

Gas prices declined also during the quarter, down 17% to $6.72, primarily due to the mild winter that we have encountered.

Moving to Slide 21, production costs, and looking at the first quarter, you can see that we are at the low end of our guidance that we put out in early March of the $11 to $12 range per BOE. This is an increase as we mentioned in March over the fourth quarter, primarily due to the incremental oil VPP volumes that we incur costs on but record no production.

Given that all these quarters presented here have varying degrees of impact from VPPs, at the bottom of this slide, we have adjusted our total production cost to reflect the VPP volumes as if we had those volumes as production, to show what the true underlying costs are doing. As you can see at the bottom here, from the Q1 '05 to Q1 '06, costs have increased about 15%, which is in line with what we would expect the industry has experienced. For Pioneer specifically, these increases are primarily due to increases in production and ad valorem taxes, which are a function of commodity prices. And then as it relates to base LOE, the main increase there is driven by utility costs and in our case principally electricity in the field.

Switching gears to second-quarter guidance. We are anticipating production of 93,000 to 98,000 BOEs per day during the second quarter. This reflects the continued ramp-up of our Spraberry and Raton drilling as well as the winter drilling program in Canada. It also has some variability built into it for timing of shipments in Tunisia and South Africa.

Production costs are expected to be same range as the first quarter of $11 to $12 per BOE.

Looking at exploration abandonments and specifically on drilling, the range is 4 million to 30 million. This includes carryover costs related to our Alaska program in the first quarter, where we have got 3 to 4 million associated with our Antigua well that was unsuccessful that were costs incurred in the second quarter that we will write off in the second quarter, as well as the Cronus well, which is still under evaluation.

Most of our dollars during the second quarter, as Tim mentioned, are focused on resource plays and so we have a range of 0 to $20 million there.

Seismic, we're looking at 21 to $25 million of expense during the second quarter. This is primarily related to shooting seismic or acquiring seismic over our resource plays.

DD&A per BOE is expected to range between $9.25 and $10.25, consistent with where we were at in the first quarter at $9.61. G&A is expected to range 31 to 34 million, similar to the 32 million that we had in the first quarter.

Interest expense is down from the first quarter and is expected to be 24 to 27 million, reflecting the fact that we got proceeds on the deepwater Gulf of Mexico sale and Argentine sales, and we were able to pay off our credit facility; offset by the fact that we issued the additional -- the new bond issuance of $450 million for 12-year money; offset by the fact that we plan on and have a tender currently open to buy back our January 2008 350 million of bonds.

Interest income is expected to range between 3 and $4 million, really just investing the cash that we have sitting on the balance sheet today.

Cash taxes should range between 5 and $15 million, primarily paying cash taxes in Tunisia and to a lesser extent, alternative minimum tax in the U.S. during the second quarter. Overall, our effective tax rate should be 35 to 45% during the second quarter.

Turning to Slide 23, a couple other items to make note of. We do expect to record a nominal gain related to our Argentine divestiture in the second quarter and that will be reflected as discontinued operations. On the insurance side, there are two insurance claims yet outstanding. The first is on our Devils Tower that we had downtime related to Hurricane Katrina last year. We still have about $20 million that we will recognize related to business interruption on that issue and we expect that to happen in either the second quarter or the third quarter.

As I mentioned earlier, we also have an $86 million accrual built in to abandon the East Cameron facility. That is mostly covered by insurance so we expect to start recovering that over the next 12 to 18 months. We should recover most of that as well.

On the capital side of the business, we are heavily weighted towards development drilling in resource plays over the remainder of 2006. But we do have a few high-end type exploration wells planned for later this year but nothing during the second quarter.

Turning to Slide 24, as our normal practice is, we have included at the back of the PowerPoint presentation a number of supplemental slides that you can see on Slide 24 for your information and so we hope you find those useful.

At that point, that concludes my comments and we would like to open the call up for questions.

(OPERATOR INSTRUCTIONS). Brian Singer, Goldman Sachs.

Good morning, thank you. Could you talk a little more about the Edwards Trend, what you're seeing in terms of well costs? And in particular, how you've reached your level of confidence at the Sinor area that that now holds the recoverable 300 Bcf?

Yes Brian, in March at the analyst meeting, I think we gave out well costs there. We have not seen any change in those well costs. They're still running about 3.5 to $4 million per well. Reserves are staying about the same that we have announced.

I have done a detailed evaluation of every log analysis in the Edwards Trend, also in regard to history matching, in regard to taking early production and matching decline wells. So we have evaluated 250 miles of the entire trend over the last two years. So, based on the log analysis, the samples and the initial test rates in Sinor Ranch, that's why we are very optimistic about that.

In addition to the Stingray prospect that Tim mentioned, one key ingredient is that we do have 3-D in that area, so obviously it's made us a lot more optimistic with the discovery there. We are shooting 3-D in the Sinor Ranch to determine the exact direction we will drill our horizontal wells. So, obviously, we're very confident in the early results and we will be drilling several more exploration prospects over the next sixty days.

What spacing assumption are you using in thinking about the 300 Bcf potential?

Pawnee is developed on 80 acre spacing, so we will be able to hopefully develop –- it depends on how productive -- the tighter it is, we'll be able to definitely go to 80. The more productive if we hit some areas where it's very productive, it could be developed on larger spacing.

But the 300 is assuming 80 or is assuming larger?

We think Sinor Ranch is more like Pawnee, so that's developed on 80 so we'll probably go down to 80's there.

And just considering some of the additional drilling and you may have mentioned this, but could you just talk about capital spending and any changes in or thoughts about changes in allocation?

Right now, we see no changes in capital allocation at this point in time. We have increased some -- I think we increased the Edwards exploration play with development drilling another 15 wells up from March but that's about it at this point in time.

And where does that come out of?

It is re-allocation of capital within the budget.

Great, thank you.

Robert Morris, Banc of America.

Thanks. The first question I had was just really what Brian just asked on the capital budget. So the total for the year is what?

Right now there's no change at $1.3 billion that we announced in March.

So it stays the same. You noted a lot of areas where you expect to exceed the production guidance. I'm just curious why not go ahead and raise the guidance at this point or what might preclude you from actually beating the production guidance you gave for the full year?

I think we will wait another quarter and make sure that we are 110% confident that we are going to meet or beat the estimates at that point in time, Bob. We will raise the guidance at that time.

(OPERATOR INSTRUCTIONS). Robert Christensen, Buckingham Research.

Can you give us an update on your Clipper? I think it was a sidetrack that you were going to do?

Yes, Bob, we had the rig coming to us in July and we'll keep it for the rest of the year, so that's why we did not report on that. So it will be a second and third quarter series of wells, appraisal wells and exploration wells. So we probably won't have a report on that until late third quarter, maybe fourth quarter on that.

Sven Del Pozzo, J.S. Herold.

Good afternoon. I would like to know whether the costs per well at Edwards, did those include anything for stimulation? Or could you just talk about whether it's going to make more sense to stimulate these wells if you have any pilot projects going on right now, just give me an idea?

The total cost includes a stimulation. We have not stimulated these wells yet because we are hooking them up. So obviously, stimulation, we expect to potentially get higher rates. So we will stimulate these right before we connect them sometime during the second quarter. So the costs that I gave out and the costs that we gave out last March includes stimulation in those costs.

Okay, I'm looking at the slide right here, it says 2.8 million per well for development and then I guess inclusive of exploration costs, so finding and development costs it goes to 3.5 million. And those include stimulation?

Yes, those include stimulation. And obviously the Pawnee wells, once you get into a full development phase, the cost drops significantly. Obviously, on exploration wells, we take a lot more analysis, a lot more extensive logging program; that's why our initial wells are generally higher than our development wells.

Okay. Now if you are able to hit the higher end of your guidance in the second quarter, so 98,000 Boe per day -- does that have any implications for your full-year forecast of the exit rate of -- full year exit rate of 100,000 Boe per day? I mean could you go through it in other words? Would the projects that enabled you to get up to the 98 in the second quarter also be producing for the balance of the year, allowing you therefore to go to exceed your targeted exit rate for '06 of 100?

Yes. You know, I mentioned this earlier in a previous question. But we have four months of data. Obviously, we're getting excited about our growth rates in all of our key areas. We will make a decision after announcing second-quarter production going into third quarter in regard to what's going to happen at the end of the year.

Okay. And Spraberry, are we still looking at cost per well to drill and complete those wells, the same as what you had in the March analyst presentation?

Yes, there's been really no change.

Okay. Then if later on, if I could get some -- I would like to know what the net after-tax proceeds were from your sales in Argentina and the Gulf of Mexico. If you could break out the transaction costs too, that would be helpful.

Yes, we will get Frank to call you back on those.

(OPERATOR INSTRUCTIONS). Ross Payne, Wachovia.

How are you doing, guys? A quick question, it looks like things are moving up fairly nicely here. The only one I wanted to get a little more discussion on from your part is Canada. It looks like it was up about 5% sequentially. You're looking for about a 44% increase from '05 levels. So is that something that is going to pick up notably in the second and third quarters? Or what's going to bring it up to the expected average for the year?

Yes, Ross, as I mentioned when I covered Slide 13, we are just now seeing the ramp-up that always comes as a result of our winter drilling campaign. We drilled 44 wells with 90% success and we're just in the process of hooking those up, cleaning them up, getting them on production. And production is moving up smartly from that.

I think one of the key contributors though will be Horseshoe Canyon, where we have 100 wells to put on from last year, as I mentioned, and we're going to be drilling a 200-well campaign this year.

So that in and of itself can move the numbers up substantially; and then we will just be occurring through the rest of the year as we drill those wells.

Ken Carroll, Johnson Rice.

Hey guys, how are you doing? Good. Could you talk about Alaska real briefly? It sounds like the Antigua did not work for you as well. What does your future look like in terms of exploration up there in Alaska for you?

Yes, we'll make the decision on Cronus over the next several weeks to months and we are already discussing our winter drilling program. Next winter, it will most likely be in NPRA. But at this point in time, we don't have plans. We'll be obviously with partners, ConocoPhillips and Anadarko. So we won't make a decision until later this summer.

Robert Christensen, Buckingham Research.

A couple of small points. You mentioned at the analyst day that you have invested in I guess a sand quarry with a construction company for frac sands for your own use and that of third parties. I know it's a minor part of your business, but could you articulate how that is going and what the market is for the product?

Yes, we have invested in sand primarily due to the fact that we're drilling and completing and fracturing roughly about 1,000 wells per year. We have seen shortages in primarily all basins in the U.S. So we would like to be able to control our destiny, Bob, and that's the reason we made a minor investment to control when we can get the sand and not have to rely on the service companies.

And how would you stimulate your Edwards Reef, with acidized or what's the type of stimulation?

It is primarily with acid.

What were those reserves per well, the EURs? I don't have my (multiple speakers)

About 3.5 to 4 Bcf per well.

What's the world of compression like? Is your Company dependent on compression -- natural gas compression?

Our general philosophy is own our own compression. We generally own in all areas. We order leadtimes way ahead of time. In addition, we are ordering aiming units in our Edwards play way ahead of time, so we have done a lot of planning in regard to building inventory for all of our key areas.

Sven Del Pozzo, J.S. Herold.

My questions have been answered. That's fine. Thank you.

Marshall Carver, Pickering Energy.

Yes, I had a question on the Spraberry drilling. Would you characterize that as mostly PUD drilling or mostly wells targeting new reserves?

It's a combination of both. We are drilling a lot of PUDs. At the same time, Tim mentioned our aggressive leasing program. So we have -- we'll be booking a substantial amount of new reserves in Spraberry this year in addition to accelerating and drilling up our PUDs. So a combination of both.

Okay, and the -- I think you had spoken about long-term F&D costs in the 15 to $20 a barrel range. Would you think based off the drilling results to date that '06 would be in that range? Or do you think it could trend towards the lower end or is it too early to say?

Yes, we have made two announcements. One for 2006; finding costs are targeted between 15 and 20. In regard to all of our capital spending over the next five years, our target is 10 to $15 over the next several years with all of our resource potential plays as listed on the slides that we had shown earlier.

But at this point, the '06 would still be 15 to 20?

Yes, we have not made any changes. Even though we are seeing a lot of success in the Edwards, we will not make any changes until later this year.

At this time, there are no further questions. I would like to turn the conference back over to Mr. Scott Sheffield.

Again, thank you very much for participating. We look forward to seeing everyone in the second-quarter call later this year. Again, thank you very much.

That does conclude today's conference call. We thank you all very much for your participation and hope you have a terrific day.