先鋒自然資源 (PXD) 2004 Q3 法說會逐字稿

Good day everyone and welcome to the Pioneer Natural Resources third quarter earnings conference call. Just a reminder that today's call is being recorded. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer. Tim Dove, Executive Vice President, and Chief Financial Officer. Rich Dealy, Vice President and Chief Accounting Officer and Susan Spratlen, Vice President, Investor Relations and Communications.

Pioneer has prepared power point slides to supplement their comments today. These slides can be accessed over the internet at www.pioneernrc.com. Again, the internet site to access slides related to today's call is www.pioneernrc.com. At the web site, 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 different 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 call over to pioneer's Chief Financial Officer, Tim Dove. Please go ahead, sir.

Thank you, Tim, I appreciate it, and thank you all for joining Pioneer's third quarter conference call. I plan to make this call short and sweet. Mostly as a courtesy to our Boston shareholders, who I am sure were up all night, last night, and have few activities they need to participate in, this morning.

As many of you know, last week Scott Sheffield, our CEO rolled out a detailed plan of the next several years, 2005 to 2008. And I encourage you to visit our website to view that presentation, because it's got a lot of details on that plan. I have attached actually the last slide from that presentation as slide three for today. It outlines the key takeaways from that presentation.

First of all, you can see in the graph to the bottom right, -- in the blue, is our base plan. This plan includes continuing expenditures for exploration, but assumes no future exploration successes, and also does not include any projects that have not already been commercialized or sanctioned. The plan in the blue shows a growth in production in 2005, about 6% to 7%. And then an annuity-like flat production profile for several years through 2008.

In the red you see the risk-success plan. In this plan we assume a risk portfolio of exploration successes and the commercializing of several projects for which we already made discoveries, such as South African Gas, Ozona Deep, Thunder Hawk and other projects, such as those in the deep water gulf of Mexico. And that plan shows, that we could achieve growth in the range of 8% to 9%.

In the box up to the top left of slide three, you can see at the same time, in either one of these models, we generate a substantial amount of excess cash flow, it's above normal capital requirements. It's about $2.6 billion or so through the period 2005 to 2008 if we continue to have these high strip prices and it’s about $1 billion or so in the event, that we were to reduce prices down to a 30 and 5 world.

The excess cash flow, obviously, gives us a lot of flexibility and optionality. It gives us the ability to fund new exploration successes, increment our share repurchase programs, do some core area acquisitions, similar to what we've done in the past, finish our debt repayment schedule, and obviously, continue to look at our dividend policies. We are obviously excited about this plan and looking forward to the next several years.

But actually the objective today is really not that, because that was covered last week. What I am going to do today is to briefly cover the third quarter results, and then go over the fourth quarter outlook with the effects of the Evergreen merger.

So go on to page four. The merger did close on September 28. We're obviously extremely excited about that. Our balance sheet for this quarter reflects the impact of the merger for September 30th, and then as of October, we'll begin reflecting production in earnings from the Evergreen assets. And I've got some more slides in here to discuss that.

For the third quarter we had a very solid 81 million of net income or about $0.67 per diluted share. That was after taking the after-tax impairment charge, related to Gabon as we discussed last week. It was principally related to the fact that steel costs, had made the economics in that development, very, very difficult. As a result we have a $10 million after-tax charge for the quarter, or $0.08 per diluted share, without that we would have reported about $0.75, per diluted share on a recurring basis.

Obviously in this commodity-price market and with a strong production profile we've shown over the last quarters, we're a significant cash flow generator, about 1.3 billion run rate in terms of EBIT backs.

Turning to slide five, on oil and gas revenue. Revenue was up slightly for the quarter, as higher prices for both oil and NGL'S were offset by our slightly lower production due to the hurricane effects, principally I will cover that here on slide 7 and 8. But first, let me just talk about in slide six, the Raton production history, we get this a question a lot. How has Raton assets been performing?

And here we are giving you some minutiae as to what happened this year. And that is to say by month 2004, January to September. You can see that as expected, the Evergreen Raton assets have performed very well, about a 10% annual growth rate is what we have seen over the last 8 months, which is as expected. We have completed the drilling of about 153 wells so far in the Raton, with a target as we said earlier in the year of about 200 for the year. Our internal models show that we can grow this asset about 14% per year based on the fact that we are going to increase the number of wells drilled next year to 300.

Overall, Evergreen's production, the assets we are acquiring would have equated to about 25.9 thousand BOE per day in the third quarter on the Evergreen method of accounting. And as we’ll talk about the change in accounting practices, if the Pioneer method were used for the third quarter it would have been 27.2.

What you should realize is that in conforming with Pioneer's accounting practices, the Evergreen production shown on this graph would be an average of about 9% to 10% higher than the numbers shown, due to the fact in Pioneer's accounting practices we account for field fuel as production as well as operating cost. So what you see here in the blue is how these assets are recorded with the Evergreen accounting practices. The numbers would have been, as I said, somewhere in the neighborhood of 9% to 10% higher using the Pioneer practices.

On slide seven, production volumes. Obviously we were affected in the third quarter the well publicized effect from hurricanes, principally two major hurricanes affecting production at Canyon Express from time to time, but more importantly at, Devils Tower. The production overall did come in slightly above guidance. We obliviously also were affected by the Harrier reservoir having been depleted a little bit earlier than anticipated, which led to the drilling of the successful side track, which we also covered earlier this week.

Overall production of gas in the United States was 499 million cubic feet per day, that's down about 11%. Again precisely related to the reasons I mentioned a minute ago. Canada production was about 39 million cubic feet a day, for a North American total of 538 out of the total of 676 million cubic feet a day, the balance having been 138 million Argentina where production was up about 12% on gas. Again our gas production results in Argentina are clearly being positively affected by demand and also in the future, gas price increases in Argentina.

As we look to the fourth quarter, as I mentioned, the fourth quarter results will include the assumption of the Evergreen production. In this range, we are assuming that we will not have any Harrier production until January 1. As mentioned earlier last week, the decision has been made to postpone tying in Harrier to make sure we are maximizing reserves on both Raptor and Tomahawk and a couple of other of the satellite wells.

We will see as is usual in Argentina, a slight decrease in gas production as we enter their summer. I think if you look at the history in Argentina, though, you will see that the peaks have been higher and the valleys have been higher, just owing to the increases in demand. So we really shouldn't have as negative an effect in terms of production, reductions in Argentina this winter -- as we had last winter or prior winters.

The timing of shipments of crude oil in a couple of projects, principally South Africa and Tunisia affect this range. And obviously we're awaiting the tie-in of the Devils Tower project. The news we have is that it should be shortly when we'll be tying in the existing four wells, but this production range reflects a range of outcomes in terms of, exactly when that will get on production and how these wells will perform when they are put back on production.

On slide eight, similar data, but shown in a geographical split. Couple of things you can see here, is that our African production was down slightly, that's only because of the timing of shipments. Production actually in Tunisia and South Africa have been extremely strong and we expect them to continue strong into the fourth quarter. And you can see the effect as the increase in Argentina from gas is shown in the blue up to 34,000 B.O.E. per day for the third quarter.

On slide nine in terms of prices, you can see that our overall oil price realization has been affected by a couple of things. One is overall prices, obviously, are extremely strong. But we have been affected, of course, by a relatively large hedge position. As we mentioned in prior calls also, we have had imposed pricing restrictions on domestic sales in Argentina, which limited oil prices, realized in Argentina to about $32 a barrel. So both of those have put a lid on our oil price realization. We do not hedge any NGL's. And you can see the strong results on N.G.O. pricing.

Gas prices were down, on a NYMEX basis, just slightly during the third quarter. You realize how strong the second quarter was on that basis. Overall, North American gas prices were over $5 for the third quarter.

On page 10, this shows historical production costs as well as the third quarter results. We came in essentially in the middle of our range at $5.63 per B.O.E. The range we had for the quarter was $5.40 to $5.90. Devils Tower's production, what we did achieve during the third quarter is at a relatively higher production cost, and you can see a slight bump in the base L.O.E. related to that.

On page 11. We want to spend a little time on this slide, because the accounting conventions that I mentioned in relation to Evergreen will affect the production cost estimates as we go ahead. As I mentioned earlier we do burden our lease operating expense with the field fuel we use for compressors in field operations. We also include that volume as production.

If you take a look at what we would otherwise anticipate for the fourth quarter, we were projecting just as to the Pioneer assets a range of 5.85 to 6.25, remember we did about 5.63 for the third quarter. The reason it's slightly higher, is because, we do have, as we await on Falcon Corridor production, principally Harrier to come back on stream, we're losing very low operating cost production there.

The Falcon system year-to-date, has had operating costs of about $2.50 per B.O.E. So when you lose the production from that, at least somewhat and it's at such a low cost, it moves, otherwise your numbers up slightly. And obviously to the extent we account for field fuel production taxes, and ad valorem taxes as we do, these are affected directly by high commodity prices. And that's why you see a little bit of creep in our forecast for the fourth quarter.

As I mentioned in the case of Evergreen, the change in accounting conventions for their production will lead to an increase on the incremental amount of production that those assets will add. Evergreen if you follow their story through time is averaged say 6 to 6.50 per B.O.E, about a dollar, a little over a dollar, per Mcfe (inaudible) basis on production cost through time. That was done without the inclusion of field fuel.

If we include field fuel it’s utilized in the Raton basin, and in other areas of Evergreen's prior operations the equivalent value per B.O.E would be about $9.75 to $10.50 as shown. And then when we put in the increment of the Evergreen production, it raises the Pioneer combined forecast, as shown to $6.40 to $7. Obviously the result that we have in the fourth quarter will be very dependent upon commodity prices, as you can see at the bottom of slide 11, this assumes the continuing high commodity prices, over $50 oil and almost $8 in gas.

Page 12. Other costs. G&A was up as expected. Obviously we have some more G&A that comes out of the continuation of the new Pioneer Denver office. We are very excited about the business development opportunities and growth, that those assets will provide and that office will be a linchpin for that growth. And we also have stock amortization's that become a part of the increase somewhat related to Evergreen's stock, as well.

In the sense of interest costs, we have added, obviously acquisition financing of a large amount. Our incremental acquisition financing in terms of credit facility is 2.5% interest roughly. And we also have assumed the Evergreen notes and converts. And that leads to an increase in interest costs as shown about $31 million to $34 million for the fourth quarter estimated. DD&A for the third quarter came in at about $8.45 per B.O.E., that's about the same as the second quarter. We had expected DD&A to increase due to the higher cost basis properties such as Harrier.

In the fourth quarter, we were expecting a similar range that we expected really for the third $8.50 to $9.25 per B.O.E. This reflects the increases that come from the Evergreen purchase accounting effects but it was essentially the same range we had in place for the second quarter.

Cash taxes for the third quarter were $7.5 million. Those are principally taxes we pay in Argentina and Tunisia, we are a very limited U.S. taxpayer obviously with our significant NOL position. Our overall tax provision was 22%. That was reflecting the Gabon tax benefit associated with the impairment there. Without that, our tax provision would have been about 34%. In the fourth quarter, we anticipate that the cash taxes will be somewhere in the neighborhood of $5 to $10 with a provisional rate somewhere between 36% and 39%.

Slide 13 exploration and abandonments. The significant expenditures in this category continue to be in both new seismic acquisition, investment in our future exploration program and G&G, G&A. G&G, G&A was just under 7 million for the quarter. Seismic acquisitions for the third quarter, principally in the deep water Gulf of Mexico and West Africa where we have got a new exploration push going. So the total being about 33 million.

We are putting a range in place for the fourth quarter of about 40 million to 60 million. A substantial amount of that again will be seismic where we continue to build our seismic portfolio and inventory with purchases in places such as West Africa and Alaska, which are going to be a couple of the key focus areas for future explorations. So about 30 million it seems for the fourth quarter will come from a combination of seismic acquisitions as well as G&G G&A, so these are in my view, investments in the future of our exploration program.

Slide 14, F&D costs shown on this slide. We are down a little bit, $136 million for the third quarter. The acquisitions you see were related to some Gulf of Mexico leases in the last lease sale, as well as the acquisition of some Canadian coal bed methane leases and land. It probably will give us approximately 400 new CBM locations in the Horseshoe Canyon area of Canada CBM drilling. And we'll probably be drilling several wells there upwards of 80 wells next summer.

Slide 15, in terms of the long-term debt balance. Obviously, we do have incremental debt that came from the Evergreen transaction as it was a 50-50 stock-cash transaction. We are making substantial progress in terms of meeting our debt reduction targets. As we've stated before, we have a target to reduce debt about 600 million door-to-door between the end of last year and the end of 2005. So far we reduced debt about 280 million towards that target with about 320 remaining. We still anticipate no problem in achieving that by our stated target at the end of 2005.

Incidentally, we did mention in our discussions last week that we have slated three non-core fields in Canada for divestiture. We anticipate being able to close by the end of the first quarter next year. I am estimating that we can generate proceeds on those sales that are in excess of 100 million. Those would go towards this debt reduction target.

Slide 16. This is just really for clarification. We get this question from time-to-time, just trying to be clear as to what the new run rate is as to diluted shares outstanding. The existing Pioneer shares were about 120 million. That includes all the Pioneer restricted stock as well as options. New shares granted in the Evergreen transaction about 25. Then we will be counting on the conversion of 2.3 million shares related to the Evergreen converts and then future option exercises. The total we'll be showing as we get into the fourth quarter and we reflect back on fourth quarter results will be 150 million or so of fully diluted shares outstanding. We have repurchased about 1.4 million shares this year. That includes about 300,000 in the last four trading days.

Our hedge position is shown on page 17 has not changed very much. We have added if you go back and carefully look at this versus the second quarter, we've added some hedges in 2005 and 2006. Mostly in crude oil we have added 2,000 barrels a day in 2005. 1,000 of that was a swap at 42 and 1,000 of it was a collar as shown between 35 and 51. We added some more in 2006 in terms of crude oil, a total of 9,000 barrels a day, 4,500 of that about $37.50, another 4,500 at the collar shown 35 to about 42.

So, with my promise to be short and sweet on this presentation, I am going to conclude there. Obviously, we have our typical supplemental slides in the back, including non-financial measures of GAAP. In terminated commodities, interest rate swaps and our oil and gas differentials. With that I will stop and Scott and I and others here can take any questions you may have. Thanks.

[Operator Instructions]

Our first question of the day will come from Brian Singer of Goldman Sachs.

Good morning, Tim.

Hi Brian

Just a quick clarification with regards to the Evergreen production accounting change. The production of Pioneer will report will be lower by about 9% to 10% than the production that Evergreen had reported?

No, it will be higher.

It will be higher

Will be in, remember the chart that I showed with the blue bars, that showed the Raton as an example, those bars would all be 9% to 10% higher as Pioneer reports the volume because we will be using a convention that includes fuel field, which is utilized in the field as part of production, which Evergreen did not do.

And has that already been baked into the production guidance for 2005, this was for the fourth quarter, that higher number?

Yes, sir.

OK and I just to also, I think you mentioned, just wanted to make sure I got the number right, you bought 300,000 shares in the last four trading days?

That's correct.

OK Thank you.

Next, we'll hear from Rehan Rashid of FBR.

Good morning guys. On the field fuel, any way to lower the loss or this is something that you just have to run with (ph)?

The operation of the compressors out there are obviously are an integral part of both Evergreen’s fuel operations in gas as well as Pioneer’s. As you know we have substantial compression in both the West Panhandle Field at Yucatan (ph). These compressors are needed basically needed to produce and deliver the gas and that's the case in Evergreen's, as well. So, I think what you see is continuing increases in fuel field just related to the fact that we charge ourselves for the cost of that field fuel and as gas prices go up, so does that component.

Thanks. As far as growth is concerned within the Evergreen assets, infrastructure wise any kind of limitations 1,2,3 years out that you have to address in the interim to be able to deliver that 13%, 12%, 14% growth rather?

Yes I think would be in the case of Raton, obviously we have the infrastructure pretty much in place with regard to all the drilling and completion facilities in place. We have an excellent plan to continue the ramping up of the drilling of the wells, up to about 300. I don't see any issues there at all.

In Piceance and Uintah you have a little bit of a different story because the permitting requirements are more onerous and it takes more time to get wells permitted and online. So if we have issues in terms of the Evergreen assets and their timing, it would be in Piceance and Uintah not in Raton but we've already factored that into our planning and in the numbers.

OK. Last just a modeling question. The NOL's impact on lowering the cash taxes, how much longer will this last? Any thoughts when that should begin to reverse and you guys should start paying some cash taxes?

It looks like based on modeling that we just completed, in 2007, probably the second half of 2007 is the time if we continue to have these high commodity prices when we would become a substantial U.S. cash taxpayer like most of our E&P brethren -- obviously if commodity prices were to come down from where they were we would be able to extend that out better.

Good, thank you.

And moving on we'll now hear from Shawn Reynolds of Petrie Parkman.

Good morning, guys.

Hi Shawn.

I know last week you talked a fair amount about West Africa, but I am just wondering how much of this fourth quarter exploration expense is related to West Africa's seismic as you mentioned? Is there any -- is there a big well involved in that number or any particular exploration prospects we should be looking at or any of those in West Africa?

Hi Shawn this is Scott. Most of the charge is more seismic in both all three of our key areas, North Slope, Deep Water and West Africa. We are in the middle of looking and evaluating several transactions. We can't comment on any at this point of time but we are, as I mentioned last week, we are giving out our policy going forward is to give out higher ranges in regard to our exploration. Our exposure to make sure that we don't miss. So the ranges we're giving essentially assumes any wells that we do spud, that it's a dry hole.

Are there are any particularly high impact prospects being drilled in the fourth quarter?

At this point in time, because we have several transactions in the midst, we can't comment at this point in time I don't really think so, in the fourth quarter. There could be some -- obviously there will be some in the first quarter of 2005.

OK. I am sure you're going to say, you know, just watch and see on this one, but that's a pretty aggressive repurchase program over the last four days. Is that something you are going to continue on that rate until you use up your authorization?

As I mentioned last week in our presentation, with the amount of firepower that we will have in completing our debt reduction targets that in the excess cash flow that we do have, we stated that, obviously, it's a lot better buying our reserves at current prices than it is drilling for it, so that will continue to be a focus over the next several weeks and months.

OK. because I think you kind of, at least once last week, said something about. Well you know, that might take us through to the middle of next year in terms of share repurchases. But if you continue at this rate, it would be sooner than that, I would expect.

I think it's better to, you know to act and talk about it afterwards.

OK. Fair enough. Thanks a lot.

OK, thanks Shaun.

Next we'll hear from Robert Christensen, of Buckingham Research.

Yes, Two questions. How much are you saving per quarter in cash taxes with your loss-carry forward position? That's question one. Question two. How much production is off in the Gulf of Mexico as we speak? Thank you.

I'll answer the first question on cash taxes. We save about 16 million so far. We saved about 16 million in the third quarter, Scott, do you want to address the (inaudible) --.

16 million per quarter roughly. Depends on the prices. In the production as we’d stated last week, Bob, that Harrier is in the process of testing. So in the ranges that we gave you, Harrier is not on for the fourth quarter. That does not mean that we may start it up at some point but right now our modeling Harrier starts up January the 1st,. And then hopefully we'll be getting out some news on Devils Tower in the next few days. So it assumes minimal production from Devils Tower. And then full production from Canyon Express.

So you're saying that Devils Tower is still down as we speak? And how much volume is that, roughly?

If you recall, we were up to gross 20,000 to 25,000 barrels a day. We have 25% of that. So as our last few press releases, the goal is to start up those four wells, actually three wells plus a fourth well, that we feel like we can complete with the existing derrick that remained on top of the spar. And so four wells we hope to be on in the next few days, and press releases will go out we they start up.

And can you just clarify, for me one more time, Harrier, you know you did the side track well, it's a successful well, when do you think you would bring that well on? I understand not wanting to co-mingle it with the other two fields there. I missed it though what you said at the start. Thanks.

OK. We have -- if you look at the graph we put out last week, we basically right now our modeling shows depleting Tomahawk and the first producing zone of Raptor by the end of the year -- this year. Then we show Harrier coming on, producing starting next year, the sidetrack. We will test Harrier the next few days, and will put out a press release, as to that test. Right now we do not want to bring Harrier on as we think we will lose potential gas reserves, from Tomahawk and Raptor. So Harrier will not come on at this point in time until January 1. And then, when we give out the test rates here in the next few days, when we test it, then that will be our rate. And we show Harrier coming on and producing, I think for about four, 4 1/2 months. In our slide we presented last week, and that's the P-90 case, which is roughly 12 to 13 Bcf next year.

Thank you very much. Just got a simple question on. Are you adding to your Raton compression?

We always will, as we are growing and drilling 300 wells per year, we will have to add to our compression. In our current policy,-- what came on, is that we, a lot of people do rent and we do on own, all our compression in all of our key areas in the U.S.

Thanks.

You're welcome.

And moving on, we'll hear from Ryan Zorn, of Simmons and Company.

Hi, and good morning, everybody. I wondered if you could maybe give a few more details on this Canadian CBM land position that you have recently initiated? It sounds like, you know 400 locations, is that a material increase? If you could refresh my memory as to what Evergreen brought to the table?

Yes, I believe on our slides we presented last week we had roughly about 600 potential locations that we show drilling over the next several years from both Evergreen, C.B.M. and also from the recent acquisition.

Is this position, kind of a bolt on to what you had already or is this a new area?

Same area, in Horseshoe Canyon. I think we are planning on drilling about 80 wells in 2005.

OK, all right. Thank you.

Welcome.

And moving on. We'll now hear from Gil Yang of Smith Barney.

Good morning, Tim, first question is for you. Just to go back to the tax issue. What percentage of your taxes are cash taxes? I calculated 40%.

No, cash taxes of our total income are going to be around 5% to 6%.

-- Total of the tax bill is 40%. So 5% to 6% of total income will be cash tax.

Yes as I mentioned, you can calculate it just looking at the numbers. We had $7.5 million of cash taxes during the quarter.

Yeah you're probably getting confused with deferred taxes.

OK, all right, but the bottom line is 5%, 6% you are paying in cash taxes. And that is the number that we would use going forward after your NOLs are exhausted.

Here is the way to look at it, Gil. In the three months we just ended, if you take a look at the PNL, we had 104 million of income before taxes.

Right.

We had an income tax provision of $23 million. OK, and of course that was relatively low, owing to the fact we had the Gabon impairment benefit. In that particular -- this particular quarter, of the 23 million provision, $7.5 million was cash. In the normal quarter, as we anticipate the fourth quarter will be, our total tax provision will be more in the neighborhood of 36% to 39%, of which we would still expect the same amount of approximate cash taxes, 5 million to 10 million for the quarter. That will be the approximate run rate until, as I mentioned 2007, at which time we'll have a much larger component of cash taxes out of the total.

OK, so in 2007, what is the number, I guess is what the question is? Is it 2007, cash tax proportion is how much?

Well, I've got to look at my modeling to give you back an answer on that. But obviously will be substantially higher. And we'll still have deferred taxes as part of the provision, as well. I would say, Rich advises me it's perhaps about 20%.

OK, Of income?

That's Right.

All right. Then an operational question. You said that you are going to double the numbers of wells you're drilling in Raton from 150 to 300.

No -- No, what a sec -- clarifying statement here. We have drilled year-to-date 153 wells, on target to drill the 200 that are planned for this year. So it will be increasing to 300 in 2005. So a 50% increase.

OK. -- So the 200 gets to you 10% growth. The 300 gets to you 15% growth?

Yes, we show 14 in our internal modeling.

Yeah OK, all right thanks.

Thank you.

And moving on, we'll hear from Ray Deacon, of Harris Nesbitt.

Tim, if you were to look at the Raton and the growth there, what would be the, you know, since it's going to account for, you know, I think the number is about half of the internal growth going forward in your risk exploration case. -- What do you see as the chief risks there?

Yeah Ray, I don't think -- it's probably half the growth in the base plan.

OK.

Of just Raton and Argentina, were the two big growth profiles. And the risk plan is probably only 1% to 2%.

OK.

And your follow-up question was?

Well just, you know, what would be the risks to this growth? I mean are you stepping out into areas where the geology is not as well known? Or is it, you know pipeline access? Or what would be the things to keep an eye on to kind of monitor whether that growth looks achievable, I guess?

Yeah, I think the biggest issue that Evergreen had and we could have, but we'll have less other problems, is adding the personnel into a small population in Southern Colorado. We are in the process of hiring about 40 to 45 field personnel, assuming our growth -- I mean a lot of those people are going to come from our three core areas in West Texas, mid continent and Texas panhandle.

OK. All right. Got it. You know, I guess, what would be the next - I know you talked about this last week, but on Ogurik (ph) when should we hear news on the next well? It's probably going to be early 05, is that right?

As we said Ray, the last week that, we will make a decision by the end of this year. So we will let something out by the end of this year, early January.

OK. Great. Thanks.

And next we'll hear from Ken Beare (ph), of Johnson Rice (ph) .

I just have a quick follow-up on Horseshoe Canyon. You said you’ll all drill 85 wells in 2005. From that what kind of production do you think, you will have maybe exiting 2005? I know it's a slow process to ramp up, but just to give a sense as to what kind of volumes would you expect, when you exit?

You know Ken, I think the typical well makes about a 100 Mcf a day, a little bit better. And 80 wells, we don't start until after we finish our winter drilling program. So you are not going to see a lot of effect from the 80 wells, until you get into 2006. But since we're selling roughly about 1/3 of our Canadian production, you'll see our production drop off after the first quarter, after the sale. And then you'll see it start -- over the five-year plan, it's increasing about 10%, 15% per year, primarily due to the CBM activity, and also remaining Chinchaga locations.

OK, Fair enough, everything else has been answered. Thanks guys.

OK, Ken.

Now we'll move on to Warren Clifford (ph) of Clifford Capital Management (ph).

Yes. There is something I am evidently confused on. I wonder if could straighten me out. I thought companies were restricted from buying their buying around the earnings report?

We essentially released these earnings last week. And that was --. If you take a look back through our press release last week as well as our slides, you will see we put out a range of about 65-70 and this is right in the midpoint.

OK, So that frees you from any restriction then?

Yes, correct.

OK, Thank you.

There are no further questions at this time. I will turn the conference back to our host for additional or closing remarks.

OK, Again. We thank everyone for listening last week to our presentation on our model 2005 through 2008. Again, thanks for listening today. And I look forward to seeing everyone over the next few weeks. If we don't see you all until January or February, everybody have a Merry Christmas and a happy new year.