先鋒自然資源 (PXD) 2005 Q2 法說會逐字稿

Good day, everyone, welcome to the Pioneer Natural Resources second quarter conference call. Joining us today will be Mr. Scott Sheffield, Chairman and Chief Executive Officer; Mr. Timothy Dove, President and Chief Operating Officer; Mr. Rich Dealy, Executive Vice President and Chief Financial Officer; and Mr. 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 the slides related to today's call is www.pioneernrc.com. At the website, select Investor, then Investor Presentation.

The Company's comments today will include forward-looking statements made from 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 two 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 conference over to Pioneer's Chief Executive Officer, Mr. Scott Sheffield. Please go ahead, sir.

Thank you, Amy. Good morning. For people that have the access to the website, we'll start on Slide Number 3, Financial Highlights. We reported, for the quarter, net income of 186 million; from continuing operations, about $104 million. Rich Dealy will explain the difference, but primarily, with the adjustments in the asset divestitures, the gain, and also the Gabon transaction. Reported second quarter production of 183,000 barrels a day equivalent; including our asset sales, 185,000 barrels a day equivalent.

Continuing to sell marginal assets. We did sell assets in Canada and East Texas for a little over $19 of BOE. Also we're announcing two properties for $80 million we'll be selling in the Gulf of Mexico shelf, non-core. That will be completed in the third quarter. For the year, we sold about 45 million BOEs, for a total of about $1.2 billion. We did close our third volumetric production payment of about 300 million during the quarter. We purchased about, a little over 2 million shares during the quarter, almost 6 million shares year-to-date. We have 63 million left, which will complete early the third quarter. We will be recommending an additional 300 million to the Board later this year.

We have reduced debt down to 1.4 billion from a high of about 2.7 billion, right after the close of the Evergreen transaction; for the year, year-to-date, about a billion dollars. We've driven our debt to book down, down to a number we feel very comfortable with, around 35%. In addition, we had insurance recoveries of approximately 95 to $100 million, related to, primarily, Hurricane Ivan and also the fire at the Fain plant. $44 million of that was recognized in the second quarter. We'll have additional recognition, which Rich will talk about, in the third quarter.

Slide Number 4, on Operation Highlights. Obviously, one of the things we are very excited about is acquiring 70 million BOEs in onshore Aquarius, primarily in the Spraberry trend area in West Texas and also in our backyard in South Texas for about 177 million. Tim Dove will talk about the aggressive development drilling campaign in both of those areas. Production was restored at Fain within about a 60-day time frame after we had the fire. It's back up to full capacity. We have -- are spending a lot of dollars, when we talk about the budget slide, on land, primarily 170,000 acres in several U.S. onshore areas, both along the Gulf Coast in two or three plays, acquiring additional acreage in West Texas, and also in the Raton Basin, and a couple other coalbed methane plays in the Rockies. We'll continue to -- that aggressive leasing campaign through this year.

The Horseshoe Canyon, one of the sleepers we found, obviously, in the Evergreen transaction, Tim will talk more about it. But we had -- we're ramping up development drilling already. We're already very excited about the results in Canada. In addition, we're continuing to look for discoveries by the majors that we feel like that, with our lower cost structure, that we can commercialize. We're very excited about the Cosmopolitan discovery that was made several years ago. It's in the Cook Inlet. We'll be shooting a 3D shortly. Obviously, very excited about that with, an option to pick up additional 40%, picking up 50% in operatorship.

Our newer discovery, which we announced the first quarter, is actually increased from 2,500 barrels a day, our original test, on up to about 6,000 barrels a day. So, obviously, we're seven for seven in Silurian discoveries in Tunisia, obviously, we're very excited about that. And we'll be ramping up that program going into '06. And, then, during the quarter, we awarded exploration rights on two deepwater blocks between -- in deepwater between Nigeria and Sao Tome, which we'll talk on a separate slide.

Slide Number 5, our Near-Term Production Outlook. Obviously, with Harrier and Raptor, one's fully-produced in early July, the other one is almost fully-produced, Raptor. We lost about 20 to 25,000 barrels a day equivalent, or roughly 120 to 150 million a day of gas. We are -- that's affected in regard to our range, 160 to 175,000 for the third and fourth quarter, going forward. The reasons why we're revising annual guidance, primarily due to asset sales and issues that we've had, interruptions, primarily in the deepwater Gulf of Mexico. Tim will give a full update, I know which people wanted first quarter. We'll give a full update on what's going on in Raton later on in the presentation.

Going to Slide Number 6, deepwater Gulf of Mexico Production Profile. We wanted to, again, show you -- we disclosed our deepwater profile back in October of 2004. Obviously, the deepwater has been a home run for Pioneer, adding over 1.4 billion of value, including all dry holes and seismic and land costs. But, obviously, one thing I have learned, being in the deepwater is that it's been hard to predict production. Our reserve recoveries have exceeded original estimates. I mean, you can see the dashed line on the curve shows you what we showed you last October, in 2004. The blue bars is existing production. As you can see, with the -- we did peak late last year at about 60,000 barrels a day equivalent. Here, you can see with the -- with the decline of Harrier and Raptor, being fully-produced, we're leveling out around a little over 30,000 barrels a day equivalent. That's primarily from Falcon and Devils Tower.

Tim will talk more about Canyon Express. We've had four sidetracks planned for the year. Total has not been able to find those rigs, and we have assumed, for the time being, that it will take us two years to find a deepwater rig in, roughly, 7,000 feet of water to get back and drill these four sidetracks. In addition, you can see the upside from our two recent discoveries, both Ozona Deep and Thunder Hawk, the impact production picking up in 2008. And this does exclude all upside from exploration drilling.

So Tim will talk about the drilling at Clipper. We'll follow with Paladin, and we have two other prospects we'll drill with the same rig early next year. So it does exclude any association with exploration drilling. But as you can see, the deepwater has been hard to predict from a production standpoint. But at least, we're at a point to where we have less wells producing, we have leveled out production by quarter. Obviously, things can change in regard to this profile that we have shown you.

What's more important is the fact that all other areas are focused on growth. The deepwater is focused on growth, but we're not going to see it until 2008. But all other areas onshore -- U.S., Canada, Argentina, and Africa -- are growing. So all areas are focused on growth. Alaska, we have filed our permits. Obviously, we're excited with our Ooguruk discovery. We have filed our permits with the State, and moving forward on that project.

The Cosmopolitan, Tim will talk more about the detail of that project. We have an aggressive drilling campaign starting in first quarter, both in the Storms Lead area and other areas on the North Slope. In Canada, an aggressive drilling campaign, both in Raton in the Spraberry, Piceance and Uinta is picking up activity second half of '05, going into '06. We talked about the Horseshoe Canyon. Also, a couple of our -- a lot our acreage is in a couple CBM plays in the Rockies, and also in two onshore U.S. exploration plays that will be spudding wells over the next two or three quarters. Obviously, very excited about those plays. In the Gulf of Mexico, a very aggressive eight-well program in the shallow shelf.

And then going over to Argentina, our Ranquil Co. Norte project, gas project, will be increasing in production starting in the third quarter, with Argentina. Gas pricing continue to increase. We are selling some gas at between 2.00 and 2.50. In addition, some of our residue gas that we're selling at residential levels of about $0.50 to $0.60. We're signing contracts now, moving it up to about $1.50 to $1.70. Oil pricing is moving up from a $32 base, on up to about $38 to $39. So pricing continuing to increase in Argentina.

In Tunisia, we're at capacity. We're producing at full capacity at about 20,000 barrels a day. We have 25% of that. ENI is increasing capacity by the end of August on up to about 30,000 barrels a day. We have compromised with them into going into an aggressive drilling campaign with our seven-for-seven success in Tunisia going into next year. So we'll be doubling or tripling the amount of wells that we have drilled over the last two years. In addition, we have a lot of gas that we have found in the Adam Concession with ENI. We're moving forward for that pipeline expansion project. In addition, Anadarko and Pioneer are drilling an exploration well in Anaguid, followed by fracture stimulating two other discoveries that we made. So a very exciting program for the third quarter.

West Africa, we've been awarded seven more blocks. We're in negotiations with the JDA that governs the deepwater blocks in Nigeria and Sao Tome. And in South Africa, we have a drilling rig already in Cape Town harbour. We'll start development drilling on South Coast gas the fourth quarter of this year, and we're finalizing our contracts now. Obviously, we're very excited about that project. With oil prices where they are, we are -- it looks like we'll be moving forward over the next two years on some additional satellites that are within about a 10 to 15-mile radius of the Sable project. So, obviously, in this price realm, there's a lot other potential that we're looking at to bringing on in projects sometime in '07, '08.

Turning to Slide Number 8. In West Africa, we have now picked up -- been awarded two more blocks, Blocks 2 and 3. Pioneer has been designated operator in Block 2. Anadarko has been designated operator in Block 3. We hope to sign those in the next 90 days. Block 256 is where we are with Devon. Pioneer operates in Block 320. What's important is the fact that Shell has announced two discoveries. In Block 256, they've had a major discovery. They just announced 1 kilometer, just off our Block in 256. We'll be spudding our second well with Devon and with Spinnaker later this year. And a third well is planned for next year.

Block 320, Shell has announced another significant discovery about 1 kilometer away from our Block 320. We'll be shooting 3D in the third and the fourth quarter. We already have rig contracts lined up for Block 320, and additional slots to drill wells in Blocks 2. We already have rig contracts with Devon, to complete the three-well program in Block 256. So, obviously, we're getting a lot more excited about the potential, in regard to having success in Nigeria over the next 18 months in Sao Tome.

Our capital budget, we're revising, primarily due to additional land costs in -- both in West Africa, also U.S. Gulf Coast and the Rockies and Canada, acquiring over 1.5 million acres added in 2005. That's probably about half of the increase in the capital budget. The other component is primarily the ramp up with our recent acquisition from Oxy and Exxon in the Spraberry. And, also, in the Pawnee area, we're ramping up development drilling, both in the Spraberry, Pawnee area in South Texas. We're ramping up development drilling with our early success in the Horseshoe Canyon, followed by five additional high-chance-of-success wells in the Gulf of Mexico shelf. This does exclude recent acquisitions in the Spraberry, Pawnee area that we have already announced of about 177 million.

We do expect, at this point in time -- obviously, it won't be submitted until late this year -- but for information purposes, we expect to be excluding the acquisition that we made this year, expect our capital budget in 2006 to be about the same number in 2005. Obviously we'll see land and seismic decrease, most -- and, then, we'll be adding up our Ooguruk and our South Coast gas projects to make up the difference. Our after-tax net asset value -- obviously, these numbers are as of the strip in June -- the strip, obviously, has moved up considerably. This is our proved reserves and also the probables. The probables are risked at 50%. We're showing a net asset value per share of $55 to $60 per share. Obviously, it's probably much higher than that, based on the current strip. Obviously, it's a big discount from current share price, which is one of the reasons that the goal is to acquire, over about a 18-month time period, roughly about 10 to 12% of our stock back over that time frame, from late '04 through the first half of 2006.

Let me now turn it over to Tim to talk more in detail about some of our operational highlights.

Thank you, Scott. Yes, I will discuss a few of our operational areas and our progress in these areas. First of all, on Slide 11, let's discuss the Spraberry and Pawnee acquisitions in a little bit more detail. The purchase price was about 177 million. Obviously, we're very excited about this project, this acquisition, as I said, because of the fact it adds assets into two of our existing core areas. So it's a tremendous transaction for us. About 70 million BOEs, those are substantially undeveloped barrels. So this means this -- these assets have tremendous drilling upside. And you can see that we'll be dedicating significant capital to the transaction. It's about 400 million over the next five years to drill, some, 800 locations.

Overall acquisition economics, if you also add in the capital needed to drill and complete and tie in all these wells is very attractive, at 8.25 per BOE, in terms of lifecycle cost. Current production is relatively nominal from these assets, as I said, most of the production -- most of the reserves are undeveloped. But we believe because of the drilling campaign we'll be putting forth, that they have five-year potential to increase by a factor of 5 in terms of production, over 10,000 barrels -- BOE per day. This is a very-low-risk transaction for us, in the sense that we already had interest in most of the wells prior to the transaction, and, obviously, these are our core areas. We have a lot of expertise, in terms of applying new technology, in terms of leveraging our scale, and, hopefully, being able to control costs as a result of all that.

The bottom box we show the drilling activity that's anticipated, for both this year and next year, ramping up in relation to the two transactions. We have already secured three additional rigs for 2005 in the Spraberry trend area, giving us a total of nine. We'll be increasing the total well count from, some, 170 to 175, up to about 200, in other words, a 30-well increase, which will lead to about a 20 million capital increase, or 120 million total. If you look at 2006, this is the year we really be hitting all cylinders, when it comes to the drilling. We'll have a total of 12 rigs in the Spraberry operating, as opposed to nine today. We'll ramp up the drilling to 350 wells, and that will lead to a capital increase of a little over 100 million, compared to the earlier plans. So this is a significant ramp up of activity, and we believe it will lead to substantial growth in production from these assets. So it's really a tremendous bolt-on set of transactions for us.

Turning to Slide 12. Yesterday we announced that we acquired an interest in a discovered resource in the Cook Inlet, which is just off the Kenai Peninsula in Alaska. It's a 25,000-acre unit in the Cook Inlet, and we have acquired a 10% working interest. And with that, we are shooting a new 3D seismic program to assess the existing discovery that was made in combination of wells drilled in 19 -- in 19 -- in the 1960s -- I guess, it was 1970s, late-1970s, and then in 2001, 2002. And the idea here is to further refine the previous discovery and assess what are going to be the next steps as to potential development. But we also have the right, assuming the seismic proves up what we think it will, to increase our working interest and assume operatorship in the Block. So, it's another addition to what is a burgeoning portfolio of Alaska assets. Obviously, we have a substantial position, as shown in the left map in the North Slope, where we're the third largest acreage holder of undeveloped acreage. And we're now adding interest in the Cook Inlet, and we're very excited about that.

Turning, now, to Slide 13. This is a -- the halfway point in the year, and we thought we'd give you an update on how all of the Evergreen assets are performing, and we do so in these next two slides. First of all, on the first page, a recap as to Raton. As we publicized for a long time, we have a plan, or a budget, this year to drill 300 wells. That budget is backloaded, because it's hard to get into the field in terms of getting new wells spudded in the winter, the first quarter, particularly. We have drilled 135 wells so far through July, with a current drilling rate of about 30 to 40 wells per month. We have four rigs out there. This is the first time all year we've had four rigs in the field. So, you can see we've ramped up activity considerably. We've also added staffings, so as to be at, basically, fully-staffed levels now, having added a net 50 people in our Raton operations.

Overall production, we're now estimating to be 5 to 7% up this year from last year. That is less than what we had put out publicly in the past, and it's owing to a couple things. First of all, we anticipated the first quarter production growth would be relatively limited, mostly because, as I said, drilling programs are backloaded in the field because of weather. We did anticipate growth to commence in April, but we then were faced with unexpected pipeline limitations. We knew that we -- the El Paso pipeline system was going to be limited. We thought it would be later in the year.

But we began to see our production growth curtail, even as early as April, due to limitations on the CIG pipeline system. As we have publicized, there is a CIG pipeline expansion, which is underway and on schedule for October. There will be increase in capacity on the system, about 35%, and we believe that will be the point at which we'll see the Raton growth continue, where we will have our capacity increase to 195 million cubic feet per day. As Scott mentioned, but it's the case that, even in Raton, we're adding new acreage. We are adding new drilling locations. And we're continually working on new opportunities to add, further, to our acreage position, and to our drilling inventory.

In the case of Piceance and Uinta, we announced when we did the Evergreen transaction that we were going to do some study of Piceance and Uinta. And the second half of this year is really first time during the history of our ownership, we're going to be ramping up activity. We have over 250,000 gross acres, a lot of undeveloped lands, and two specific areas we're working on, a CBM -- early CBM projects, specifically in Columbine, which is in the Western Colorado, essentially on the Utah line. We'll be drilling three wells and, potentially, completing 12 existing wells, with the idea of, basically, proving up a new CBM play. So we're real excited to see the results of that extra effort.

In addition, the Castlegate area, we have one horizontal re-entry we'll be drilling and, then, one grassroots horizontal well, probably will not get drilled until next year. The -- those plays are both CBM plays and they're both in the early stages, but if they're successful, have considerable running room. In the case of some other areas, we have about three other areas we're working in Piceance and Uinta, and have somewhere in the neighborhood of 8 to 10 well activities, including well deepenings or completing existing wells in those other three areas.

Suffice it to say, if you look at the bar graph on the right, that the Evergreen transaction has played out well for us. Obviously, we've been the beneficiary of commodity price increases through time. In fact, this is based on the June strip prices, the second quarter 2005 bar. It doesn't reflect the high -- even higher current gas strips. But, also, Horseshoe Canyon has, in fact, been a diamond in the rough. We'll talk more about it in the next slide. But, now, we're at the point where we think the Evergreen asset's yield value, almost 4.5 billion, compared to the acquisition cost, about 2, 2.5 billion. So we're very excited about the fact that these assets continue to bode well, in terms of value accretion for Pioneer.

Then on Evergreen -- I mean, on Evergreen -- the last two Evergreen assets, being in the Horseshoe Canyon, Canada. Slide 14 gives you a snapshot as to the early returns on this project, and they look excellent. We have about 67,000 acres, about 600 locations to drill. We are potentially adding to that, with new acreage transactions from time to time. We have already completed 30 wells -- actually, we've drilled 30 wells, I should say. We have tested six of those wells, and have had excellent stabilized flow rates -- about 200 Mcf per day. That was about twice what we'd budgeted, in terms of proving the wells. And, so, you see substantial potential in the early days of this program. We have an 80- to 100-well program planned for this year, and it's the case, based on these early returns, it's likely we'll increase that to add additional 100 wells. We'd have to add a couple more rigs out in the field, but rig availability is really no problem in this play.

We also have substantial potential in the Manville. It's in its early days in terms of CBM potential. There have been a couple of recent successful wells in the area, which has piqued interest in it -- in the Manville CBM play. We have a significant acreage position -- 63,000 acres. And we have a couple of wells we're going to plan that would be considered pilot wells, in terms of testing the Manville in our areas of acreage holding.

Finally, then, on Slide 15, a recap of what's going on in the Gulf of Mexico. Scott mentioned that we do have an eight-well shelf program, and we have already drilled one of the eight. It was a successful well in Eugene Island 208. We've got two more wells planned there. And, then, five additional shelf wells that we recently added to that program, relatively low risk, production adders in the short -- in the short to intermediate time frame. We also, as Scott mentioned, have announced today the sale of some non-core shelf assets for about 80 million.

Devils Tower, we did, obviously, get affected by earlier hurricanes. But we've actually been affected by Hurricane Dennis as well, to the extent that the operator under the abundance of caution has decided to move the completion rig off location prior to the hurricane coming through, and -- but prior to some more top-side construction. It will be back in place in September. But one of the results is we've moved out completion of wells for a month or two. In addition, we have had to delay production ramp ups because what we're being forced to do by dictate -- dictates of the MMS is to produce lowest-interval hydrocarbons to a much longer extent because of these high commodity prices, and, therefore, we're not able to get to higher, more productive zones as quickly as the plan would have shown. We are on schedule to tie in Triton and Goldfinger in the fourth quarter of this year.

In Canyon Express, the plan shows that the original completions, both in the Aconcagua and Camden Hills fields will be produced out by the early part 2006. The four sidetracks that were mentioned earlier have been postponed until we are able to have a rig available for the drilling of those. It's unclear when that will be. In the earlier plan Scott showed, we were scheduling it for the end of '07.

In terms of Falcon, Scott mentioned that Harrier field produced until mid-July. The results of that field were really outstanding. Its results, in terms of EUR exceeded our pre-drill expectations. The sidetrack in Harrier, itself, added about 130 million of NPV, based on calculating a 10% discount rate and 25 Bcf for the sidetrack, a rate of return of about 100%. So an outstanding results on the Harrier field total. We believe that Falcon wells are showing excellent reservoir performance and will lead to an increase of, some, 30 Bcf over our earlier plans, as to the final EUR for those wells.

In terms of current drilling, we have a -- the Clipper well that is back to drilling now. We had to pull off Clipper, due to the hurricanes coming through, or the storms. In addition, with -- the Gulf of Mexico's been subject to substantial loop currents, and this well has also been affected by that. But we are back to drilling and anticipate results in the next few weeks. We'll follow Clipper by going to the Paladin well, as shown on Slide 15. We have a couple of other wells that are planned, in terms of appraisal wells, on existing discoveries, as shown -- the Thunder Hawk appraisal well planned for the second half of this year and, potentially, a sanction of that project as we get closer to the end of the year.

And, then, Ozona Deep, the appraisal well there is now planned, it looks like, for 2006. We also have slots for additional exploratory prospects as we get into later this year and into early 2006.

And with that, I'll pass the microphone to Rich for some comments on the financials.

Great. Thanks, Tim. If I can direct you to Slide 16, we'll go over our second quarter results. I think, as Scott mentioned, we're very pleased with our second quarter earnings, coming in at $186 million for the quarter, or $1.28 per diluted share. This net income number does include $82 million associated with our second quarter divestitures of three non-core fields in Canada, which will be reported as discontinued operations. That's something new for Pioneer. We haven't had that in the past. And so, as a result, we have added on Slide 28, back in our Supplemental Schedules, a detailed results of operations, the gain on the disposition, and the related tax effects associated with discontinued operations. If you exclude discontinued operations, income from continuing operations was $104 million, or $0.72 per diluted share, representing a 61% increase over income from continuing operations for the second quarter of 2004.

Included in income from continuing operations are two unusual items that, for the most part, offset, but I wanted to give a little more details on. First, other income includes 44 million of business interruption insurance, or 28 million on an after-tax basis, associated with our final settlement of losses that we sustained at Devils Tower and Canyon Express related to Hurricane Ivan. It also includes about $9 million, in that same 44, related to the plant fire at our West Panhandle field. Now, as it relates to the West Panhandle field, as Scott mentioned, we do expect to recognize an additional 9 to $10 million during the third quarter of business interruption, related to the down time that we had at the plant prior to its returning to production in mid-July.

Also, as we announced in June, the second quarter income tax expense reflects the reversal of $27 million related to a tax benefit that we, principally, recognized in 2004 and are in conjunction with our decision to exit Gabon. Having recently signed, in June, our agreement to sell our subsidiary that holds our interest in Gabon, we've had to reverse that deferred tax benefit, and will, obviously, recognize a gain in the third quarter or fourth quarter when that sale closes, to the tune of the 49 million of proceeds that we announced in June. Looking at the operating cash flow on this line, you can see that was up to $333 million for the quarter, a 26% increase over the prior-year quarter, obviously, reflecting the higher production volumes and significantly higher commodity prices that were received in the quarter, as compared to last year, offset partially by increases in costs.

Turning to Slide 17. I would like to point out that you'll see the note on the remaining of the slides at the bottom, there, that we've adjusted, not only the second quarter, but the prior periods presented, to exclude discontinued operations associated with the Canadian divestiture. And so, you'll see that throughout these slides. In particular, as it relates to this slide, oil and gas revenues were 545 million for the quarter, representing a 7% increase. And as you can imagine, this is primarily attributable to higher commodity prices.

Turning to Slide 18. Production was 183,000 BOEs per day during the second quarter, and as I mentioned earlier, this excludes approximately 2,100 BOEs per day associated with discontinued operations. Specifically, gas production increased 3% as compared to the first quarter, primarily a result of a full quarter production of Canyon Express system, since it was down in January during the first quarter; increased production in both -- gas production, in both Canada and Argentina; offset by the shut in of our West Panhandle field for the last 45 days of the second quarter, as a result of the plant fire. The decrease in oil and NGL production is primarily due to the West Panhandle field, as it relates to NGL and part of the oil, and then the delays and, just, timing of oil cargo shipments in South Africa and Argentina. The third quarter production range of 160,000 BOEs per day to 175,000 BOEs per day is lower than the second quarter, and reflects the fact that the Harrier field has been fully produced, we are on decline at production at the Raptor field, as Scott mentioned. It does take into account that we've resumed the production at the West Panhandle field during the -- July, and the timing associated with oil cargo shipments in Argentina, South Africa, and Tunisia.

Flipping to Slide 19, where we show production on a geographical basis, you can see that Africa production is down 12% from the first quarter, primarily, as I mentioned, the South -- due to South African oil cargos. Canadian production is up as a result of our successful winter drilling campaign. Argentina production is basically flat during the second quarter, but we did see a small increase in gas production, and should see a bigger increase in the third quarter, as we add compression in a couple of our fields in the Neuquen Basin. As we discussed earlier, down time at the West Panhandle field was the principal cause for U.S. production being down in the second quarter.

Turning to Slide 20. The Company benefited from the increase in commodity prices during the second quarter. Oil prices increased 7%; NGL priced increased 9%; and gas prices increased 5%, excluding the effects of the VPPs for the second quarter as compared to the first quarter. In particular, North American realized gas prices increased to $6.00 per Mcf, or 5% over the first quarter. In Argentina, you'll see in the Supplemental Slides, that our quarter gas price realizations were consistent with the first quarter, but these should improve during the third quarter, as the government's last regulated price increase became effective July 1st and as the Company continues to benefit from spot sales above $2.00 an Mcf on gas.

Turning to Slide 21. Second quarter production costs per BOE were $6.47, down 3% from the first quarter. And as I discussed in our first quarter call, we expected second quarter production costs to decline, since a greater percentage of our second quarter production was attributable to deepwater Gulf of Mexico, which have lower per unit operating costs. However, as we look forward to the third quarter, we do expect production costs per BOE to increase to $6.75 to $7.25 per BOE, principally as a result of deepwater production dropping off with the Harrier and Raptor properties and an increase in overall commodity prices affecting production taxes as we looked at the second -- or the third quarter. Also, to a lesser extent, affecting the range is -- during the third quarter, we'll retain a full quarter of operating costs associated with the third VPP that we completed in April.

Turning to Slide 22. Second quarter G&A costs were $29 million. We expect, in the third quarter, G&A costs to be between 28 and 30 million, a similar range. Interest costs for the second quarter were $30 million, down 9% from the first quarter. The decrease for the quarter reflects the interest savings associated with our debt reduction that we achieved during the quarter of $437 million. That brings our quarter-end debt to book capitalization ratio down to 35%, from 46% at the end of 2004, so a substantial improvement. During the third quarter, we do expect interest expense to range from 26 million to 29 million, as a result of the Company's lower debt balance.

A couple items that aren't on the slide, but, just, are noteworthy. Our DD&A costs for the second quarter were $8.82 per BOE. And for the third quarter, we do expect a similar range of $8.75 to $9.25 per BOE. Cash income taxes for the quarter were $16 million, 3 million of which relates to the Company implementing our repatriation plan under the American Jobs Creation Act. We expect the third quarter cash income taxes to be about 10 to $20 million. From -- on an overall effective tax basis, for the second quarter, if you exclude the tax benefits that was reversed associated with the pending Gabon sale, our effective overall rate would have been 36%. As we look to the third quarter, we expect it to be about 36 to 39%. However, depending on which quarter we close the Gabonese sale, it could change that. It will be at the lower end of range or slightly below the range, potentially, if we close the sale in the third quarter.

Moving to Slide 23. Exploration and abandonments during the second quarter were $52 million, G&G expenditures were 28 million of the total, and the 18 million of dry holes is primarily carry-over cost from the first quarter. As we look to the third quarter, exploration and abandonment costs are expected to range between 40 and $70 million. This range includes accounting for drilling our Clipper and Paladin prospects in the deepwater Gulf of Mexico that Tim talked about, one exploration well in our Anaguid Block in Tunisia, and several wells in Argentina, as well as the acquisition of some of additional seismic.

On Slide 24. Costs incurred for the second quarter were $266 million, and were primarily focused on completing our ramped up development drilling program, as well as adding the new acreage position that Scott mentioned. As is our normal practice, we have included in the back of this presentation, Supplemental Schedules that show, as I talked earlier about, the components of discontinued operations, our quarterly oil and gas volumes, and deferred revenue amortization associated with our three VPP transactions that we've completed this year, the Company's current commodity hedge position, historical oil and gas price differentials by geographic area, and a detail of year-to-date income taxes. So, hopefully, you'll find those Schedules helpful in your analysis.

And that really concludes our prepared remarks. And at this time, I'd like to open it up for questions.

Thank you. [OPERATOR INSTRUCTIONS.] We'll take our first question from Brian Singer with Goldman Sachs.

To regards to the Gulf of Mexico issues at some of the different fields, do any of those issues have the potential to necessitate any revisions to reserves? And secondly, just looking on into 2006, Scott, are you happy with the existing projects that you have now, or would you consider doing some kind of acquisition until some of the longer-term projects come on in 2007, 2008?

Yes, Brian, on the reserve question, I already mentioned, in total, which we evaluate -- to calculate our net asset value, all of our fields combined produced at about a P25 to about a P30. So we generally start at a P90, and we've actually increased reserves almost all of the projects over time. So the issues that we mentioned do not affect -- reflect any reserve adjustments, or not going to have any. In regard to the other opportunities, we do have a -- we have five -- five slots, including the Clipper slot in the deepwater Gulf of Mexico. We'll -- we have four prospects, including Clipper and Paladin, two other prospects we will drill. At this point in time, Pioneer has been reluctant to sign some of these 400,000 to 450,000-barrel-a-day rate contracts. So we are not going to sign any of those. A lot of our peers have contacted us, we have decided not to sign those.

So we are going to take a very, very cautious approach to the deepwater Gulf of Mexico. It is -- the production is flattening out, as you can see with that graph. A slight decline in about five quarters, but starts picking up when Thunder Hawk goes on a deep. We hope we will, obviously, have success from the four prospects. Longer term, our primary focus, we think that a lot of the activity will be more focused on West Africa and also the North Slope. So we will not be making an acquisition in the Gulf of Mexico.

With regards to Argentina, any changes to your thoughts there either positively or negatively in terms of the business environment?

Yes, in meeting with DeVito recently, the number two guy in the government, obviously, we're a lot more -- I feel a lot better about Argentina. They are allowing gas prices to move up fairly significantly. I do see gas prices in '07, '08 getting up to about dollars $3.00. And I do see the export tax staying on for at least two or three more years after the election. I see the export tax being phased down, because Argentina will become an importer in 2008. So I do feel a lot better about Argentina going forward.

Thank you.

We'll take our next question from Jeff Hayden with Pickering.

Hey, guys, a couple quick questions. First off, just wondering if you could give us a little color on what your expectations are for production in '06? And, then, if you could give us any -- a little more information on the Cosmopolitan acquisition, how meaningful could this be? I don't really think there is much production in the area. Would you have to build a pipeline? And in terms of picking up the other 40%, you said either you pay disproportionate or a cash payment, just a little detail -- a little more details on, kind of, what you'd have to do to pick up that additional 40%?

Yes, Jeff on the first question, I'll let Tim follow up on the second question on Cosmopolitan. Obviously, our production has flattened out. All other areas are growing. And we will give out our '06 estimates by the end of this year, once the Board approves our capital budget. Tim, do you want to answer Cosmopolitan?

Sure, just a little bit more color, and this is all information that's public, obviously, we are limited as to what we want to say, in terms for competitive reasons and within our partnership. But the well that is established, that -- really, the production potential here was the well that was drilled in 2001 or '02 that was then sidetracked by ConocoPhillips. This well tested at a stabilized rate of 600 to 800 barrels a day over different intervals that lasted for three to four months. And, so, there's a certain amount of certainty that comes from that, as to the production potential.

As to the potential for tying any further development in and what you have to do with it, this -- this resource is only somewhere in the neighborhood of 2 to 4 miles offshore the Kenai Peninsula. It would require a pipeline to deliver oil to a refinery about 65 miles away. So you have a ready market, and you have a readily commercial opportunity to move -- to move the production if we can accomplish that. Finally on the -- on the terms, we have a right to increase by taking an additional 40%. The terms under which we would take that are not going to be disclosed but it would allow us to move up to 50% and assume operatorship.

Okay. Thanks a lot, guys.

I would say, just to note, we wouldn't be in this if we didn't think it was a sizable resource.

We'll take our next question from Sven Del Pozzo with John S. Herold.

Hi, good morning.

Good morning.

Could you give me an idea -- would you remind me of the gravity, the API gravity at Spraberry and the sulfur content as well?

Yes, it's very, very low sulfur, and about 40-degree gravity. So it's basically your West Texas intermediate sweet crude.

Okay. And as far as Canyon Express is concerned, now, there's a -- you mentioned Aconcagua and Camden Hills, and there's a Kings Peak in there as well, is there not?

Yes. We do not have -- that's a -- we do not have an interest in Kings Peak, so we cannot say anything about that property.

Okay. So your net production volumes from Canyon Express don't factor in anything from Kings Peak?

That's right.

Okay. All right. That's about it.

Okay. Thank you.

Thank you.

Thank you. We'll take our next question come from David Tameron with Jefferies & Company.

Good morning. In Evergreen, what's your absolute production level at the moment?

Let me see, it's running around 140 -- Evergreen, about 145 million.

Okay.

That excludes Canada.

Okay. So that -- is that -- that includes -- what about just the Raton itself? Is that -- ?

I think Raton's probably 143.

Okay. And in Horseshoe Canyon, what's the -- remind us what's the infrastructure like as far as what's your ability to get these wells online, et cetera?

Tim?

Yes, the infrastructure in the area is very, very good, in the sense this is only an area, say, 50 to 100 miles just slightly north -- northeast of Calgary. So, excellent capacity from the standpoint of export pipelines and internal pipelines within the Province. We will also -- we have two gas plants in the area, so we have plenty of capability of processing gas. I'll remind you, in this case, what we produce here is essentially 100% methane. So it needs very little in the way of processing. The wells are very cheap to drill, very fast to drill, and very easy to tie in. So, it's very uncomplicated from the standpoint of gas operations.

Okay. The -- and for -- as far as production impact, you're probably looking at '06?

Yes, [indiscernible].

Okay.

By the time all these wells are drilled and tied in and have full effect, they will probably be the latter part of this year and, then, clearly, into '06.

All right. And, then, last question, in the Raton, do you expect to get back to that 10%, kind of, production target in '06, once CIG expansion is completed?

Yes, we do.

Okay. Thank you, very much.

Thank you.

[OPERATOR INSTRUCTIONS.] We'll now move onto our next question from Gil Yang with Smith Barney.

Good morning. Could you talk about the Raton acreage that you purchased? How contiguous is it to existing acreage there? How the quality of those -- of those acres, compares? And what price you paid?

Yes, Gil, it's -- this is acreage that Mark and Dennis have been trying to get for several years, and they just took, basically, a lot more schmoozing with these two primary land owners that are really outside of the -- they reside outside the Rockies. The acreage value is, relatively, very inexpensive. The leases are long-term leases. We expect the coal quality -- coal quality to be very economical. So, I think we've already mentioned this, probably, at least -- there's over 100 locations in the acreage. And we're going to continually to acquire acreage on the fringes as we drill our extension wells, and they're very positive. We will continue to pick up acreage on the fringes over the next several years.

Does that mean that it's not exactly contiguous to your existing properties?

No, it is contiguous. Everything we're buying now is contiguous.

All right. And then you mentioned Blocks -- the discoveries on nearby Blocks 256 and 322. Could you talk about, A what those discoveries showed you, or how much you know about those discoveries that gives you increased confidence? And given that things can change from kilometer to kilometer, what did you see in those that really makes you much more confident about your prospects in those areas?

Obviously one kilometer is only 0.6 of a mile, so, obviously, we're very excited about that discovery. We are shooting 3D seismic on 320. So, at this point in time, we cannot disclose anything that we know about the extent that it is on us. So we only have 2D. Shell, obviously, has 3D. On 256, we have known about this discovery for a while, and we could not announce it until Shell announced. So, all it does is -- and it's fairly close to, it just sets up the opportune -- opportunity in regard to a prospect in adjacent to that -- to that well.

So I think -- the other thing did I not mention, we're excited about Chevron already getting a rig and spudding Block 1. Obviously, it's right in between Blocks 2 and 3. So there's two other wells that are going to be offsetting our Blocks. So we picked up deepwater blocks that are further -- if you look at that map that we showed you, most the discoveries have been closer to shore -- over 250 million barrels. The positive thing is, is that the majors are starting to move toward our Blocks and around our Blocks, and that's what we're very excited about. So --

Thank you.

We'll take our next question from Dan Fernandez with Lehman Brothers.

Good morning. It's actually Paul Tice. Just three quick ones. The third quarter guidance you have of 160 to 175 Bs, does that factor in anything for hurricane down time in the current quarter?

Very little.

Very little. Okay. And then on the share repurchase front, basically, the current program is already wrapped up. You said you wrapped that up early in the third quarter, so, since it's August 2nd, I'm assuming that that's done at this point?

We can not legally buy during the month of July up until --

Okay.

We can -- we start buying 48 hours after -- after this call.

Okay. And then you're going back to the Board? Is that September timing for a new authorization?

It's later this year. I can't tell you exactly when.

Okay. And, then, lastly, on the first quarter call, you mentioned that you were looking at recutting your bank deal. And I was wondering if you can give us some color about where that stands? And, then, specifically, if in that revision there was any changes that were contemplated for the covenant around your VPP activity?

At this point, we have not redone our bank agreement. It's still something we're considering, but we have -- it ended up not moving forward on that at that point in time. And so, it's still under evaluation.

Okay. And what was the -- ?

We also have 0 bank debt currently so --

Right. And was the -- the issue about upsizing that, or just terming it out, in terms of the revision? Or both?

Well, it would have been upsizing and, just, adding a couple years onto the end of it, was the -- really, the issue. And, so, it's still something we're considering doing. And we'll look at that, here, as we go over the rest of the year.

It's really just opportunistic, taking advantage of the strong bank markets that are currently in place.

Okay. And, I guess, lastly, any update on your recent conversation with the rating agencies?

No. There's been no discussion with them.

Okay.

Since their press releases.

Okay. Great. Thanks.

Moving on to Joe Magner with Petrie Parkman.

Good morning, I'm just curious if you could remind us, the Ooguruk and South African gas projects have not yet been sanctioned. What, sort of, is left in that process for those to be fully sanctioned by the end of this year?

Yes, Joe, South Coast gas, we basically are -- all the contracts are drafted, we're just in the process of finalizing them. There's a team meeting in London next week. So they should be final fairly quickly. PetroSA's Board has already approved the project. So, we've already -- the rig contract has already been signed. And on Ooguruk, we just filed our permits, so that project is very close also. I don't think we'd be filing permits if we weren't serious about the project.

Okay. Sounds good. On the Raton, it's currently producing 143 million a day. At the time of the closing, I recall it being around 180 million a day. I know there's some differential for field fuel. Can you sort of help with the reconciliation on what that field fuel impact would have been, to sort of -- ?

Yes, they averaged 135 last year. So if you do it from our accounting, they averaged 135. So we backed out field fuel, so they were around 135 at that time.

Okay. In terms of the NPR-A wells that were drilled this past winter, I know results haven't been disclosed by Conoco. And Anadarko mentioned that they had factored it into their plans for the upcoming winter program. When will we start to hear some more information on that program? The results to date, and what the plan might be going forward up there?

I think every year we're going to drill three to four wells in that area. And so there are certain -- I have found out, being up there -- there were certain wells that we can't disclose that have been drilled, and they've reached the -- are trading data for several millions of dollars. So there's lots of value to not disclosing what well results are. And, so, we have an agreement with all parties not to disclose anything. So, it could easily be 12 months. It could be three years, Joe. So, it's hard to tell. Obviously, if -- if you end up having a -- a major discovery, obviously, it will -- the quicker it will come out -- so -- the information.

Okay. And, then, on the divestiture between Canada, East Texas, and Gulf of Mexico shelf, is there any way you could break that out a little bit more between those three areas?

Yes, if you can get back with Frank or Chris, they can give you more details on that.

Okay. And, then, last October, you had -- you published, sort of, a long-term production per share growth outlook through 2008, I believe. Should we expect to see an update to that? It seems like quite a few of the components of that have changed and shifted around this year, and have probably impacted that outlook.

Yes, I think the major impact is that we've sold -- including the -- we sold 6 million -- 6 million barrels of VPPs in '06, and we sold another 3 million. So you basically got a -- from '06 on, you got to take about 8 to 9 BOEs off that. And that's, primarily, the VPPs, the Canadian, East Texas, and shallow water plays. So, at some point in time, at the end of this year, we will update that.

Okay. That's all I've got. Thanks.

Thank you. We'll take our next question from Shannon Nome with JPMorgan.

Thanks. Good morning. Just quick, did you say, or can you say, what your current net production is at Canyon Express?

It's probably in the -- I'm going to guess around 30 to 40 million a day, net.

MMcf a day net.

Yes.

And fair to assume that ceases what, mid-'06 or for argument's sake?

Yes, it basically -- if you look at the -- as it's declining, Devils Tower is increasing, and that's why it's flat production over the next five to six quarters.

And on that note, on that Slide 6, you showed a slight uptick in deepwater production in Q4 versus Q3, and I'm assuming that's Triton and Goldfinger tie-ins?

Exactly.

Okay. What are your -- if you're willing to say -- your pre-drill estimates on Clipper and Paladin?

Clipper we have told, and it's in a 50-million-barrel range. And Paladin is in the 150- to 200-million-barrel range.

Those are gross. What were your net interests, again?

We haven't -- we're in the process of negotiating agreements with people right now --

Okay.

-- Shannon, in regard to our interest. Right now, it's two-thirds, Pioneer; one-third, Devon.

Okay.

At Paladin.

At Paladin. Okay. And another detail, did you state your average working interest in those gross acres numbers up in Canada?

It's probably -- I think it's about 80, 82%.

82%. Okay. One more. And, then, -- was there something else?

Well, you're asking in the CBM play.

Yes.

Yes, Horseshoe Canyon and Manville?

Yes, Horseshoe Canyon our working interest is about six -- about 80%, that's about right.

And same with Manville?

Approximately, yes.

Approximately. And, then, finally, willing to quantify the probables, or the risk probable number that you used in the NAV in terms of total reserves?

Quantify by -- ?

In other words, instead of in dollars, value, NPV, what the actual quantities of reserves were?

We are going to give out a lot more detail on our probables by the end of the year.

Okay.

So let's wait until at that point in time.

Okay.

But it is risk 50%.

Yes.

And most of it's going to be in -- in North Slope, Ooguruk, South Coast gas, Tunisia, Argentina, Raton, South Texas, that's where the primary areas, some in the deepwater Gulf of Mexico.

Okay. And 8%'s a good enough assumption for your long-term weighted average cost of capital, presumably?

Yes, with interest -- long-term interest rates where they are, we think a PV 8 is a -- is a good number for long-life assets.

Thanks, Scott.

Okay.

We'll take our next question from Andrew O'Connor with Wells Capital.

Good morning, guys. I wanted to know, can you quickly review your philosophy regarding share repurchases? At what point would you cut back or throttle back share repurchases in favor of spending more discretionary cash flow on your business, development, exploration, or acquisitions? Thanks.

Yes, I see a point with a potential -- all of our development drilling areas have been ramped up, and, obviously, we're -- we're hopeful for success either in deepwater West Africa or the North Slope. Once we have some major discoveries, that's where you'll see, obviously, less exploration dollars and more on development appraisal drilling. As long as our stock is cheap like it is, we'll continue to focus on share repurchases. Our basic model shows this still 4 to 500 million of excess cash flow next year, and also going into the following year.

So, Scott, thanks for that. I mean, is there a point at which, or discount to NAV, at which point you'd throttle back share repurchases?

Obviously, obviously, as the -- if the stock gets up to where it's closer -- much closer to net asset value, that's obvious, I think.

Okay. But in terms of quantifying that --

I can't -- I can't tell you because the net asset value keeps changing. As I mentioned, it's two months old. And depending on this -- probable reserves continuing to pick up, and, secondly, depending on where the oil strip continues to move up like it is, there is a difference. That difference changes.

All right, sir. Thanks, very much.

And we have time for one last question. We'll take the last question from Ray Deacon with Harris Nesbitt.

Yes, hi, Scott. Could you talk about Adam and Anaguid and how the latest wells are performing?

Yes, it's -- it's -- we're at capacity of 20,000 barrels a day. We have 25% ENI operates.

Right.

And capacity is going up to 30,000. So we do anticipate increases in production from all the wells. Going into next year, instead of drilling four to five wells a year, we've been successful in discussing with ENI to go to about a ten-well development program. There's probably another 300 Bcf of gas discovered. We're looking at expanding existing pipeline and tying that gas in. We are selling some gas now. There's probably another 2Tcf of gas in the Devonian -- I mean, the Ordovician with Anadarko that we're -- which is adjacent to Anaguid that we're very excited about also. So, even though we don't anticipate a lot of gas sales until '07, '08 in Tunisia.

Okay. And all the oil is coming out of the -- is it the Silurian, or the -- ?

Yes, the Silurian.

Okay. And, just, a couple of quick ones. Is -- with more proved developed reserves, does that allow you to do more VPPs without having any negative impact on your rating? Or are you pretty much done with VPPs?

We have -- the purpose of the VPPs, to remind everyone, was, really, we got up to 2.7 billion of debt, it was a unique way to reduce our debt quickly and sell reserves at a high price. And that was the primary reason that we did the VPPs. So with our debt to book at 35, it's going below 30% next year, primarily with just earnings, that there's no reason to do any more VPPs. It's just another mechanism if we need capital, it is cheap capital to add resources.

Right. Okay. Yes, one other issue that I'd heard recently was ALTRA had sold some long-lived assets for what looked like a very attractive price to a California utility. I mean, have you seen similar interest in any of your long-lived gas? And would you consider that if the price was in excess of what you thought the net asset value was?

Yes, I think Pioneer, in regard to an upcoming Board meeting, strategic Board meeting, we have to continue to find a way to recognize the value of our long-life assets. So, as we see deals happen out there, we will continue to evaluate those types of opportunities.

Okay. All right. Thanks, Scott.

That does conclude today's question-and-answer session. Mr. Sheffield, I'd like to turn the conference back over to you for any additional or closing remarks.

Okay, again, thanks. We appreciate everybody listening in. Please give Investors Relations or Tim or myself or Rich a call. We look forward to seeing you next quarter.

Thank you. That does conclude today's presentation. Thank you for your participation, and have a great day. You may now disconnect.