先鋒自然資源 (PXD) 2005 Q3 法說會逐字稿

Good day everyone and welcome to the Pioneer Natural Resources third quarter conference call. Joining us today is 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.pioneernrc.com. Again, the internet site to access the slides related to today's calls www.pioneernrc.com. At the website, select investor, then investor presentation.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provision of the Private Securities 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 formed 10-Q and 10-K made with the Securities and Exchange Commission.

At this time for opening remarks and introductions, I would like to turn the call over to Pioneer's chief executive officer, Mr. Scott Sheffield.

Good morning. We will start off on slide number 3, financial highlights. Like to report for the quarter third quarter net income of $124 million,. $0.88 per share.

When you look at the two items of East Cameron 322, abandonment charge of $21 million and the discontinued operations from Grand Bay T-bay divestiture may claim number for earnings is $0.89 per share. We reported third quarter production of 169,000 barrels a day equivalent. Excludes a couple items: 2000-barrels a day equivalent from Grand Bay T-Bay discontinued operations, and we had a loss of the quarter from the two hurricanes of 6000 barrels a day.

We did close as I mentioned the divestiture to non-core assets, Grand Bay and T-bay off of Louisiana. And we had an after tax gain on that of $17 million booked in the third quarter. In addition, as we announced previously, we have a signed agreement and closeout agreement with Canadian Natural. They've taken over operations of our Gabon block. We closed the sale for about $48 million with a after tax gain of $47 million which we booked in the fourth quarter.

As I mentioned earlier, we did recognize 33 million pre-tax in third quarter related to the increment abandoned obligation for East Cameron 322. As a result of hurricane Rita it was make being 600-barrels a day, obviously not economical to restore the platform. It had a PV value of about 6 to 7 million PV10 value about 6 to $7 million. As we receive insurance recoveries to offset the $33 million plus business interruption insurance in addition to the value of the platform, we will be booking to gain on that over the next several quarters.

Moving to hurricane impacts on slide 4, obviously our impacts were last year from hurricane Ivan. We had very limited Gulf of Mexico disruptions from the two hurricanes. Low or no damage to deepwater facilities at Falcon, Canyon Express and Devils Tower. It had the shut in production from all of these of about 6000-barrels a day representative of about 3% of worldwide production.

Falcon and Canyon Express came back on fully operational by October 1. Devils Tower will be restarted any day now. It was essentially delayed by Chevron's Empire Terminal which we expect to be back on in the next few days. We expect a return Devils Tower back up to 5000-barrels a day equivalent net to Pioneer followed by bringing on Triton and Goldfinger satellites which are ready to come in. And then followed up again by receiving business interruption insurance in excess of $5 million which will be reported over the next one to two quarters from Devils Tower.

Operational highlights on slide 5, we signed a MOU, memorandum of understanding with PetroSA and expect their Board approval shortly, obviously to develop a South African gas project. What's more important is that a rig will be drilling several seven gas development wells starting in December.

We also ended up with our exploration successful track record in deep water Gulf of Mexico, the very successful discovery on Clipper, where we operated 55% net and resource of our initial wells of 25 to 50 million barrels-of-oil equivalent and additional amplitudes that we hope will be proved up. With additional drilling it could expand this discovery on up to 90 million barrels of oil equivalent. This is in our deepwater Gulf of Mexico divestment package.

We did acquire and took over operations during the quarter from our Spraberry acquisition that we acquired from ExxonMobil/Oxy. We reported initial rate of 1400 barrels a day equivalent. There was about 75, 76 wells that we just restored to production. And picked up another 900-barrels a day.

We have not started our aggressive drilling activity on this. Expect to drill 20 wells later in the fourth quarter. And then ramping up we will talk more about ramping up of Spraberry. In the Raton CBM joint program, on schedule, we had a good couple months in regard to moving toward our target of drilling 300 wells. In addition, the CIG pipeline went in October 1. We did have a nice bump of about 4 to 5 million a day at that point in time.

We do expect production to be up 5-7%. We will be adding another 75 to 80 wells between now and end of the year on production so we continue to see that continuing to ramp up above the 147 level. We have drilled 90 wells of 180 wells CBM program drilled in the Horseshoe Canyon. 30 are on production producing about 3 million. We expect to be up to 10 million a day by the end of the year. In that program.

Slide number 6, and seven really talk about our activity around North America and Africa, near term plans really over the next fourth quarter and the first quarter over the next six months. We still are waiting government approvals on Kapurik we will be studying with the Arctic Fox, another rig that we helped negotiate and bring up to the slope should start this program in late December, early January.

We will drill three north slope exploration wells. Conoco-Phillips will be our partner on those three wells. They are all closer tie-ins in regard to the Prudhoe Bay/Kapurik infrastructure. We are shooting Cosmopolitan 3-D and should be completed by the end of the year. Chinchaga will get ready to start in December. A 50 well program, During our winter drilling season up there.

Followed by another 180 wells we will start right into early '06 in the Horseshoe canyon. In addition, with some of the success by some operators on horizontal drilling on Mannville, we are getting ready to start a four-well horizontal Mannville CBM program. Rockies it looks pretty good. So far with the weather in regard to getting our 100 wells drilled October has been a great month for us.

Getting our 300 well program completed by the end of fourth quarter starting several CBM pilots, both horizontal and Castlegate followed by CBM and Columbine Springs and Piceance and Uinta, followed by some deep test in the Entrada. We recently added 37,000 net acres and another CBM pilot will be starting up in the Piceance.

Spraberry trend area, we started the year with about six rigs and are up to 10 now and will be going to 13 and running 13 consistently for several years. Drilling 350 to 400 wells per year in the Spraberry trend area. In addition, we had a very successful extension well and set up eight additional location in our pawnee field, adding two more rigs in south Texas. Early next year we will be up to four rigs and continue to add acreage in that successful trend area.

In Africa, over the next few months, Tunisia, we are drilling two wells back to back in the Adam concession. BNI and Pioneer have agreed to get more aggressive with a second rig which we expect to start by the end of the first quarter. We expect to drill six to eight wells in 2006. South Africa, as I mentioned already, we expect their board approval shortly. The rig is already south of Mosul Bay finishing up a project for PetroSA we will be moving over to the first development well in December.

In West Africa, we will be spudding with Devin. The second well on block 256 by the end of December. And we do have fourth quarter our 3D survey on block 320 which we expect to spud a well in 320 late 2006, early 2007.

An update on our strategic initiatives update on slide 8, obviously we have told everyone we would be aggressive in a share repurchase program. We completed $641 million of the 650 since September 1 by 12.4 million shares. Repurchased almost 20 million shares year to date. We will make a decision obviously on the first 350 after our asset divestitures are completed. We repurchased our bonds, eliminating high yield covenants eliminating over $2 million followed by a closing a new 1.5 billion senior credit facility with much improved terms on our past facility.

Divestment packages, going on track in both deepwater Gulf of Mexico and Terra del Fuego. We hired advisers for both sets of packages. Data rooms just opened. Bids are expected in December and we will report later on by the end of this year early next year on those results. 2000 capital program is being adjusted and reflected the allocation of deepwater Gulf of Mexico capital to primarily more increase North American onshore development in extension drilling. We did complete our hedges that we had announced using costless collars for '06-'07. We did announce a dividend increase of 20% to $0.12 per share.

Let me turn over to Rich Dealy to go over the financials of the third quarter.

Thanks, Scott. Starting on slide nine, earnings for the third quarter were $124 million or $0.88 per diluted share. Third quarter earnings did include $30 million on a pre-tax basis or $19 million on an after tax basis of income associated with our divestitures of Grand Bay and fields in the Gulf of Mexico shelf. Quarterly results on these fields are reported as discontinued operations in the financial statements.

If you look on slide 22 in the back of the supplemental schedules, you can see the detail component that make that discontinued operations not only for these sales but for our sales earlier in the year as well. Excluding discontinued operations for the quarter, income from continuing operations was $105 million or $0.74 per diluted share.

As Scott mentioned, income from continuing operations included the $33 million pre-tax charge or $21 million after tax charge related to the recognition of the incremental abandonment cost related to East Cameron 22 field which was lost during Hurricane Rita and is uneconomical to replace. While we expect insurance to cover the incremental plug in costs as well as the property value of the platform and lost revenues, the accounting literature required us to recognize the additional abandonment accrual in the third quarter with no offsetting insurance recovery. We expect the insurance the insurance recovery will be recognized in the coming quarters as the amount becoming better quantified and known.

Consequently if you adjust for the unusual items, we had very strong earnings from continuing operations of $126 million or $0.89 per diluted share. Discretionary cash flow for the quarter increased to $352 million, up 18% from the prior quarter. This increase reflects the significantly higher commodity prices that we received during the third quarter offset partially by cost increases that I will discuss later.

Turning to slide ten, I first like to point out that the third quarter in the prior periods presented in the following slides have been adjusted to exclude discontinuing operations associated with our year to date asset sales. So as we look at forward you will see those were removed. As it relates specifically to this slide, gas revenues were up $558 million for the quarter, at 4% increase from the second quarter.

The increase is primarily attributable to significantly higher commodity prices that we received offset by lower production that you can see on slide 11. Production on that slide is represents 169,000 BOEs per day for the third quarter as compared to 180,000 BOEs per day for the second quarter. As noted, the bottom of slide 11 the third quarter excludes 2000 BOEs per day associated with discontinued operations.

Specifically, gas production declined 11% as compared to the second quarter results of Harrier field being fully produced in mid-July partially offset by the fact that we were able to resume production from our west Panhandle field once the damage called by the plant fire was repaired in July. Similarly the increase in NGL production is also due to the west Panhandle field resuming operations.

Oil production for the quarter was down due to Devils Tower production being shut in for the month of September as result of the damage caused to Chevron's Empire Terminal from Hurricane Katrina. As we look at the fourth quarter, our production range is 160,000 to 175,000 BOEs per day.

This range reflects anticipated the timing of resuming production at Devils Tower that Scott mentioned. Our increased production Raton after the CIG platform expansion in our early October expected increase production in Canada from our newly drilled Horseshoe Canyon wells and the timing of oil cargo shipments in Argentina, South Africa and Tunisia.

Turning to slide 12, where we show production on geographical basis, you can see that African and Canadian production is flat with the second quarter, Argentina was successful in boosting production in the third quarter as a result of adding compression to a couple of our gas field down there and it helped and as I mentioned earlier production was down primarily due to the Harrier field being fully produced, Devils Tower down for the month of September ,offset by the resumption of our production at the west Panhandle field.

Turning to slide 13, the company benefited from increased commodity prices in the third quarter with oil prices increasing 13%. NGL prices increasing 19% and gas prices, excluding the effects of the VPPs increasing 6%. In particular, North American gas prices increased to $6.62 per MCF, or roughly 10% over the second quarter. Focusing on Argentina, we are seeing increases in demand for oil down there and are signing new contracts for oil sales in the 38 to $40 range up from the previous limits which were tied to export parity of roughly $32 per barrel. Argentine gas prices for the quarter were flat.

Turning to slide 14, third quarter production costs per BOE were $7.61, an increase of 19% from the second quarter. The increase in the quarter is primarily attributable to commodity prices which resulted in hire production taxes as it relates to base LOE, that's primarily attributable to two items: first, we had a decline in deepwater Gulf of Mexico production that have lower per BOE operating costs; and two, we had general price increases and services and supplies given the higher commodity price environment that we are in.

For the quarter, if you look at the decline in lower cost production, accounts for half the increase in base LOE with the other half being attributable to price increases. As we look forward to the fourth quarter, we expect production costs to be similar to the third quarter, and we are estimating the range to be $7.25 to $7.75 per BOE.

Turning to other costs on slide 15, third quarter G&A costs were $33 million, and include certain one-time severance-related charges. Therefore we expect the fourth quarter G&A to be between $31 million and $33 million. Interest costs for the third quarter were $29 million. And during the fourth quarter, we expect interest expense to range from $31 million to $34 million as a result of the increased borrowings associated with the $641 million of stock repurchase we've accomplished since announcing our strategic initiatives on September 1 and slightly rising interest rates. As we outlined previously, long-term debt will be reduced from proceeds from our announced asset divestitures resulting in overall interest costs coming down post divestiture.

Talking about a couple other items DD&A cost for third quarter were $8.76 per BOE. Fourth quarter DD&A per BOE is expected to be 8.75 to 9.25 per BOE. Cash income taxes for the quarter were $12 million, principally accrual of cash taxes in Tunisia, we expect fourth quarter tax cash income taxes to be $10 million to $20 million. The Company's overall effective tax rate for the third quarter was 29%. And we expect the fourth quarter to be approximately 34% to 37%, each of which reflect the tax benefit associated with the sale of our Gabunese subsidiary for $48 million in the fourth quarter that brought those rates down.

Looking at exploration abandonments on slide 16, total expiration abandonments was $64 million during the quarter, with G and G expenditures being $17 million, And as I mentioned earlier, exploration abandonment included $33 million related to east cam 322 platform and that's the half of the charge for the quarter. As we look forward to the fourth quarter, exploration abandonment costs are expected to range between 30 and $70 million and includes plants drill wells in Alaska, the Gulf of Mexico shelf, Argentina, Nigeria and Tunisia along with some purchases of additional seismic.

Moving to slide 17, costs incurred since third quarter were $406 million. And includes our previously announced acquisitions in the Permian basin in south Texas. Exploration development drilling in our core areas was consistent from quarter to quarter and expect similar stuff in the fourth quarter.

As our normal practice, we have included in the back of this presentation supplemental schedules that show the detail related to discontinued operations. I mentioned earlier, we also show quarterly oil and gas volumes and deferred revenue amortization associated with the VPP transactions we completed earlier this year. Our current commodity hedge position is also back there. Plus historical oil and gas price differentials by geographic area and a detail of income taxes. Hopefully those will find those helpful and that concludes my comments.

At this time we would like to open the call up for questions.

Thank you, sir. [OPERATOR INSTRUCTIONS]. Our first question will come from Brian Singer with Goldman Sachs.

Good morning. In the Horseshoe Canyon, what are you seeing in initial production rates and reserves per well and how many locations do you believe you may have beyond the 180 you plan to drill for 2006?

Yeah, Brian. I think we have gone on the past that we had about 600 locations. So currently that's on -- drilling on 80 acres. There is some movement toward drilling on 40-acre spacing which could allow for more drilling.

We are assuming 85 MCF a day per well, initially we're getting, and that's gross. We typically own 80% working interest and we are getting much better production rates than we expect in our model. Averaging about 125 to 150.

Is it your view that 40-acre space could work in your acreage or have you --

We have not -- we were only watching offset operators in Canada, Quicksilver and so on. We have not even attempted 40-acre spacing yet.

Switching to the Raton is it 15% growth rate the right level to think about over the next few years considering there should be a bump up in production in the fourth quarter, could next year be above that?

No. We stated that we are -- our goal was to get 14% early this year. Up on this slide, we were showing a 5-7%. You -- of course, the five to seven obviously is based on the fact that the first nine months were flat production because of pipeline constraints. So the year -- we were up probably about 8 to 9% from 12 months ago for the year we will be somewhere between five and seven. We will have a better feel.

We probably need another two to three months of bringing on the other 75 to 80 wells and watching what happens to the pressures of the CID system. And we will have a very good handle probably sometime in January or February. Make it an ongoing rate.

Great. Thanks.

Our next question will come from Bob Morris from Banc of America.

Good morning, Scott.

Hi, Bob, how are you doing?

Good. You are looking at the reallocation of the offshore Gulf of Mexico spending to onshore areas. Where are you seeing the better opportunities to wrap up spending, is it in Raton, Spraberry or where do you have the better opportunities to ramp up?

There are lower risk opportunities obviously high margins and the Spraberry obviously is a place where we were doubling our capital from the time that we made the Exxon/Oxy acquisition where we are adding a lot more acreage from the Spraberry trend area. We're drilling deeper wells adding the wolf camp to already three zones. So major expansion in the Spraberry trend area.

Raton was already on track to build 300 wells and we will continue that going into next year. We were wrapping up the Piceance Uinta after having it for about 12 months now, and that will be starting fourth quarter going into 2006. Canada was another place we increased our budget and we started off only at 90 wells this year.

We've increased it to 180 wells and will continue that going to 2006. In addition, South Texas in the Edwards trend and a couple other trends we are now just drilling test wells and will be drilling test wells all the way along the Gulf Coast. We will be allocating a lot more capital based on success in those place. That's pretty much the areas.

And you mentioned in one slide that on the quarter to higher service in oil field and service costs, what are you now expecting for service cost and inflation this year and have you increased your budget any now for the full year?

I don't know if rich or Tim, I can't tell you exactly what percent is due to increased cost versus our deepwater production. Rich, do you have a better feel, or Tim?

The feeling, internally talking to the divisional folks that we have a 15% cost creep this year on our onshore property base which is a significantly large number of wells underpinning the Company's production.

Primarily units, electricity, things like that.

And so have you bumped up your budget here or what is your full year budget now.

That's operating expenses. You said service costs so we don't budget in regard to the service cost side. So we are obviously will be increasing our service operating costs going into 2006 when it comes to trying to predict the exact amount of cash flow we have post divestiture for 2006. Obviously we will be bumping the service cost up at that point in time.

Okay. All right, thank you.

And our next question will come from Ellen Hannan from Bear Stearns.

Couple follow-ups, one on the Horseshoe Canyon, you mentioned that your model is looking for IP rates of 85. Can you tell us what your modeling for your reserves per well and also cost per well.

Go ahead, Tim. I will let Tim answer.

The wells in the Horseshoe Canyon right now are running approximately $300,000 U.S. But that is a little high today because we were in the early stages of building infrastructure as this place is blossoming we need to lay pipe and put new compression out there to handle the new well count. Early days the well costs are higher than they will be next year on a per unit basis.

In terms of reserves, the current thought even though we are in the early days of production from these wells because it's in the early days in the field, we don't have a lots of long-term well history. But the early indications would show two to 300 or .2 to 3BCF per well 2-300 million cubic feet per well.

And can you also elaborate on what you expect your Mannville CBM pilot to cost?

These wells in general up there that -- we were drilling horizontal wells in the neighborhood of 800,000 to $1 million each.

One last question on another play, can you elaborate on your Entrada gas testout and new intubation, what your acreage position is and your objective is?

We are utilizing new 3-D out in the area. There is a bunch of 3-D seismic shoots. One thing we are testing is the ability to image the Entrada with 3D so we are deepening the existing well bother to test our theories. If it were to work we have extensive acreage position on our main canyon area that we can expand the play. These are the early days and this well is an important well for us.

And that's it for me. Thank you.

We will take our next question from [Phil Cohen] from Buckingham Research.

Good morning. Could you just remind me in you guys are active in this west Texas Barnett play?

West Texas Barnett play, yeah, the Barnett shell does move all the way over to the Permian basin. At this current time we are continuing to evaluate CBM opportunities in the Permian basin and we have not -- we were not active at this point in time.

Also, all this Permian bases on acquisition activity, is there a higher inflation on the rates that you see out there?

I don't think it's Permian basin has never been ake active as a lot of other areas such as south Texas or the Rockies. We have seen less pressure in west Texas. To remind everyone we own some of our own rigs. Help keeping costs down in the Permian basin.

Thank you.

Thank you. We will take our next question from David Heikkinen from Hibernia --

Just a question. I think Ellen asked or maybe I didn't hear the answer, the Entrada gas test in the Uinta, how much acreage did you have around that?

I don't have the exact acreage position on that particular play, but we have substantial acreage in Piceance and Uinta the total being over 250,000 acres. Not all that is -- for Entrada We have substantial acreage that would be for Entrada if this well were to be successful.

And then the expected timing on the deepwater divestitures and the remaining divestitures. Are those all by year end or probably the first quarter. What are you thinking?

Bids are due essentially in December. They are due in December. Obviously you will have negotiations going on. I would anticipate announcements late December to early 2006.

Okay. That was it. Thanks, guys.

Okay.

We will take our next question from [Ted Szot] from Bear Stearns.

Good morning, everybody. My first question is on your reserve numbers for the end of the year. Do you have an early census as to what your replacement number will be like?

Yeah, the initial range of finding cost reserve replacements will be somewhere between 9 and $13 on finding costs and 175 to 225 on reserve replacement.

Okay. Great, and then in terms of the percentage of production that you will replace, do you have any guidance on that?

That's the 175 to 225% reserve replacement.

Guidance, I know you only give it for the fourth quarter here, but do you have a sense for next year as probably going to be basically flat or down a little or up a little.

In regard to --

Your production levels.

Well, production levels will be -- we anticipate them to be down, primarily due to the successful divestitures of Terra del Fuego and also deepwater. We reported deepwater next year was going to make about 30,000-barrels a day and Terra del Fuego was 9000 barrels a day.

Okay. Thank you.

I think I said nine, it's 12,000-barrels a day.

Okay. Thank you.

[OPERATOR INSTRUCTIONS].

Okay, again, we would like to thank everyone for listening to our call. Look forward to talking to you all again early next year. And I think Frank and Chris did send out a notice on our buy side, sale side analyst conference, it will be February 21 and 22 here in Las Colinas. Look forward to seeing everyone next year.

That does conclude today's conference. We thank you for your participation.