先鋒自然資源 (PXD) 2004 Q2 法說會逐字稿

Good day, everyone, and welcome to Pioneer Natural Resources second-quarter earnings call. This call is being recorded. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Timothy 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 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 select Investor Presentation.

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

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

Thank you. Good morning. Again, we appreciate everybody taking the time and effort to listen to our second-quarter call. Beginning on -- ones that have access -- on slide number 3, we did report net income of 70 million or 58 cents per share with record cash flow of about $265 million. We continue to reduce debt, getting debt to book below 44 percent. Reduced debt about $65 million; 164 million for the 6 months.

Obviously what is most important for the quarter was that we announced in May a strategic merger with Evergreen Resources, which I will comment more about, of how the process is going and the integration.

We did complete a debt exchange offer with 3 series of outstanding Senior Notes, essentially issuing 527 million and extending out those terms out to 12 years at 5.875 percent. We continue to buyback stock; again second quarter we have repurchased a little over half a million shares for the first half of 2004.

We did achieve in May first production from Tomahawk, Raptor, and Devils Tower. Devils Tower we just have 2 wells producing; we will have several more wells coming on by the end of this year. Announced a couple discoveries at Thunder Hawk in the deepwater Gulf of Mexico, and another successful well where we have had a 100 percent success rate in our block with ENI, the Dalia Number 1 in Tunisia, which is already on production. Did enter a joint venture with ConocoPhillips and Anadarko in NPR-A and acquired leases on more than 800,000 acres. We picked up a 40 percent interest in Block H; we will be operator covering 400,000 acres in Equatorial Guinea. We awarded all of our leases that we were high bidder on in the Gulf of Mexico lease sale -- Central Gulf of Mexico lease sale, where 14 of them are in the deepwater.

My next slide, number 4, updating you on the merger with Evergreen. Obviously we feel like it was one of the best assets in onshore North America, gas assets. It does rebalance Pioneer's drilling program. Provides over 2,000 drilling locations extending our RP ratio. Provides us a lot of unconventional gas expertise that we are already starting to leverage in both the Rockies and in Canada. We expect to mail in the next 2 weeks by mid-August to shareholders, and close sometime mid to the third week in September. Based on discussions with the SEC so far and comments, we did clear Hart-Scott-Rodino already. So obviously we will expect to close in mid to late September.

Slide number 5, we have had extensive on-site meetings every week since we have announced with the Evergreen staff both in Denver and in Trinidad to ensure a smooth transition. We have made plans obviously to accelerate development that we discussed. We will be drilling approximately 300 wells in the Raton Basin in 2005. A lot of that obviously is ordering the additional stimulation fleets and also cold tubing units that we have already ordered and being constructed for use in the 2005 drilling program. We have identified several key Pioneer employees that will be moving to Denver; and also we still expect our estimated cost savings of about 8 to $10 million per year by the combination of both companies.

Slide number 6, again the importance of this transaction, it does increase our presence in North America. You can see what it does in regard to our lower-risk onshore base on slide number 6. Onshore base will be about 43 percent of the Company's production, with the Keys and the Raton, the Piceance and Uintah obviously coming from the Evergreen transaction, providing a fairly good growth profile through 2010, both coming from primarily the Raton Basin and also in Argentina.

The impact to the onshore U.S. base by Evergreen is discussed on slide number 7. Production increasing roughly about 150 million per day. When you look at pro forma for the second quarter, increasing percent of Company production from 36 percent to 43 percent. As I mentioned already, we are adding over 2,000 drilling locations to our base, increasing that to about 4,500 locations, and extending the RP ratio in our onshore U.S. base to 23 based on pro forma production from both Companies second quarter of 2004.

On slide number 8, obviously Argentina is continuing to hit record levels. We have seen a movement up in gas prices as we had mentioned in May, continuing to increase over time. Argentina is importing base from Bolivia at $1.60 per Mcf. You can see as footnoted, the residue price right now is 40 cents, when you look at our gas in the Neuquen basin. On our rich gas it is about 65 cents additional coming from the liquid content in several of our more recent discoveries. In addition, Tim will discuss a new oil agreement in regard to Argentina that was negotiated in late May in regard to reducing our percentage, we used to -- since all of our crude is sold locally, we were getting about 90 percent of WTI. Now above $36 we're getting 80 percent; Tim will talk more about that and the effect on the quarter and on future quarters. But again Argentina continuing to grow. Ramping up gas production as you can see with both our discoveries and also with continued increased demand in the country.

On slide number 9, just reemphasizing our offshore producing asset base. Continue to see great performance from all of our key assets. Both Canyon Express, Devils Tower still have several wells coming on over the next 6 months. Falcon is still performing obviously at record levels. And Sable, with our recent injection well being drilled, we are seeing much better performance out of Sable over the last several months.

In regard to commercialization, (indiscernible) the status of several projects, on slide number 10, we will be making a decision by the end of the year on our Oooguruk discovery in Alaska. We are continuing to negotiate our final numbers on a production and handling contract for Ozona Deep; and evaluating options for Thunder Hawk both in regard to evaluating the seismic and when we will drill an appraisal well.

Continue to evaluate the gas markets on the gas discoveries that we have made, both in our oil discoveries that are behind pipe and also with our 2 wells in Anaguide in regard to bringing on that gas production over the next several years. Gabon, we did see receive approval of our EEA, and we're getting final bids on our numbers here shortly. That project is still coming on in 2006.

South Africa gas, we're in final negotiations there on our final gas contract price and getting final bids on our development costs. Both those projects should be completed in regard to those current negotiations and finalizing planning development for both projects by the end of this year, showing fairly good ramp up in production in 2006 and 2007 from a series of these projects.

On the exploration side, as I mentioned already, we continued to add acreage both in the Gulf of Mexico and the North Slope of Alaska. We picked up more acreage in West Africa; still anticipate picking up additional blocks in deepwater in several countries as we are finalizing negotiations both with ourselves and also with our Kosmos joint venture.

Ghadames Basin, we're planning on several wells in Tunisia over the next several months. We will drill at least 2 prospects this winter in the North Slope. Plan to drill about 6 to 10 wells in the Gulf of Mexico over the next 12 months. Then we will probably be drilling our first wells with Kosmos and drilling some other wells in West Africa in 2005. From a risk exploration profile, you can see on our risk exploration success, the impact to the Company's production over the next several years.

Slide number 12, when you put together each of the characteristics, both especially with the Evergreen transaction, you can see we feel very confident that the Company can easily grow at 10 percent annualized compounded growth rate over the next several years. In addition, we have several -- at least over 1 billion just in the next 2 years -- of excess cash flow in 2005 and 2006.

We have modeled -- as we have averaged about a little over $100 million a year of acquisitions. We are continuing to look at acquisitions in our core areas in regard to what we could do with that excess cash. We will continue to be looked at buying back stock. Obviously the first amount of cash flow, which Tim will talk about with the slide, will be used to reduce debt. That will be completed by the end of the first quarter of 2005. Obviously, we still have a lot of excess cash flow in this environment. Let me stop there and turn it over to Tim to go over the second quarter.

Thank you, Scott. The second quarter was a solid operational quarter for us, as we reported record production and operating cash flow for the quarter. Earnings as Scott mentioned did come in at the lower end of guidance for 3 specific reasons that I will cover in the next slide.

On slide 13, we show again 70 million of net income, about 58 cents per share; and operating cash flow of about 265 million. That is up 39 percent from last year's second quarter. DCF, discretionary cash flow, we reported 295 million; that is $2.45 per fully diluted share. In the case of EBITDAX we reported 326 million for the quarter; that is basically on our projected run rate of 1.3 billion per year.

Turning to slide 14, I thought I would cover some of these items in a little bit of detail just to give you a feel for these items that did affect the earnings. There were 3 main items, 2 of which were mostly non-cash charges that caused earnings to come in at the low end of our earlier guidance. As Scott mentioned, at the end of May we got some information regarding oil realization changes in Argentina. As you recall from some of our prior discussions, the government imposed a 20 percent export tax on crude oil during 2002; and through time because of that we had diverted most of our sales into the domestic market, where prices had gradually returned close to parity with WTI. Scott mentioned about 90 percent of WTI.

During the latter part of the second quarter, the government of course has been faced with a very difficult dilemma. They have been trying to keep a lid on domestic gasoline prices despite the fact that crude oil rose from 35 to 40 and over $40 a barrel. As a result, the government has implemented a new pricing structure -- again, Scott covered some of this -- for domestic oil sales during the quarter, the latter part of the quarter specifically, that in essence has lowered the domestic prices to export parity.

The result was for us in the quarter we reported a differential of almost $14 per barrel off of WTI for Argentina oil sales, including some prior period adjustments. You can see some more information back on slide 31 where we were provide supplemental information on the differentials. Although in the future, we don't anticipate the differential remaining this high, we're concerned about how the government is going to roll this structure forward into perhaps this quarter and maybe thereafter.

It is very unclear right now exactly how long this situation will last. But I thought I would give you some information how the formula works. It is only in place and applicable in the case where WTI is between 32 and 42 per barrel. In the event that WTI is over $36, the producers receive 86 percent of the price they would otherwise receive. For WTI below -- I'm sorry. For over $36 the producers receive 80 percent and below $36 the producers receive 86 percent of the price they would otherwise receive.

So as an example, if you just use the WTI of $42 per barrel and you take into consideration the normal quality and transportation differentials we have shown through time, about $4 per barrel, this would yield a net price in Argentina of about $38. So with the new structure, the producers receive 80 percent of $38 -- this is in those cases where WTI is over 36 -- or about $30 per barrel. That then represents about a $12 differential off of the WTI.

Obviously we're not very happy about this. It is a significant tax on producers and will have a negative impact on our Argentine results as long as it's in effect. Hopefully it will be offset somewhat by planned increases in gas prices that we have already begun to see, as Scott showed you in that one slide.

Secondly, the second topic relates to exploration expenses. Overall exploration expenses came in near the top of our range, including all categories of expense. We reported about 40 million or so of exploration and abandonment expense along with G&G for the quarter. In addition to new investment in seismic in Argentina and Alaska, we did drill a dry hole on our first well in EG, which represented about 6 million of exploration and abandonment expense. In addition we also have the right to recoup about 5 million of additional cost that we incurred in drilling the well from one of our partners, from future production. But because the first well was successful, we would have to write off this receivable as other expense during the quarter. What we will have to do is wait for a future exploration success in EG that establishes revenue in order to re-establish that receivable as an asset. As a result, other expenses were hit by that amount. The other expenses also included a non-cash charge of about 2 million related to some oil hedges that were FAS 133 ineffective and over $1 million in relation to expenses for our Senior Note offering.

As Scott also mentioned, we have filed and the Gabonese government has proved our EEA; and as a result we were forced to abandon a well that was drilled in 2002 along the southern portion of the Olowi oil rim, which is not a part of the current development plan. That led to a non-cash charge of about 9 million during the quarter.

Finally, we reported a relatively high income tax provision of about 43 percent. This is higher than what we would normally have, a U.S. statutory -- and this is federal and state rate -- of about 36.5 percent, mostly because of these international exploration and abandonment expenses that I just discussed. In the case of the EG well expenses, the deferred tax benefits that were created by the dry hole we cannot recognize until we have future revenue that will allow us to use them. In the case of Gabon, we don't pay income taxes; actually taxes are sort of boiled into the royalty. So we pay a higher rate of royalty to account for them. So the expensed well that I mentioned on the southern part of the oil rim does not provide any tax benefits. So in both of these cases, although we incurred the expenses, we receive no corresponding reduction in our income tax expense.

Actually, for the third quarter, we are forecasting more of a normal range, say 36 to 39 percent income tax provision based on our current spending plans. Obviously, as we look ahead, it is going to be important to be calculating out country by country spending in tax rates in those countries in order to get the tax provision estimates accurate. It is important to note, I think, that our cash taxes for the quarter were just under 5 million due to our significant tax attributes. So most of the things I am discussing on these tax items are non-cash. We anticipate that cash taxes will be somewhere in the range of 4 to 8 million in the third quarter.

Turning to slide 15, going through some of our normal slides, revenue was essentially flat during the quarter with the first quarter, even though production was up slightly. We did have the Argentine oil realization effect and hedges, which have the result of keeping overall revenue essentially flat.

On slide 16, covering production, again a very strong production quarter. Overall gas sales up to 722 million cubic feet a day. We were up in both the U.S. and Canada slightly. U.S. production was 558 million cubic feet a day for the second quarter as compared to 550 in the first. Canada was up to about 41 million cubic feet a day, up slightly from 40 in the first. So overall production in North America, 599 million cubic feet a day. Argentina had a tremendous quarter of course, as they have had great winter demand; 122 million cubic feet a day. We anticipate their demand to be also strong as we going to the third quarter.

If you take a look at oil, in the blue, oil is 45,000 BOE a day. That is down slightly, principally just because of timing of Sable oil sales. If you take a look at the effects of the new production, Tomahawk and Raptor did not begin producing until mid-June, so they really had little effect on the second quarter. There will have a larger effect on the third. Devils Tower, even though it came on in late May, it was only with 1 well; and now we have 2 wells producing; so it didn't have much of an effect in the second quarter. Each will have a bigger effect in the third, as we bring on 2 more wells in Devils Tower and you get the full quarter for Tomahawk and Raptor.

As a result our production range for the third quarter should be 185 to 200,000 BOE per day. All of the numbers I am referencing here exclude Evergreen. In fact all the numbers we are showing you for the third quarter estimates do not include Evergreen. Upon the successful closing of an Evergreen transaction we will come out and revise guidance at that time.

Turning to slide 17, daily production volumes. Again, you see the effect in Africa of a reduction in production down to about 10,000 BOE per day. Again the timing in South African in cargo liftings. We do anticipate the production being up in the third quarter due to the reasons I mentioned. But also the range will depend upon how many cargoes of both South African and Tunisia oil actually can be booked for the third quarter.

Off slide 18, show pricing. I have already discussed the effects in terms of oil, and you can see that in the bar where our realization dropped somewhat to just under $28 per barrel. In the case of gas, even though NYMEX was slightly higher for the second quarter, we did have a higher component of Argentine gas at a lower price during the quarter; and of course you have the normal hedge effects.

On slide 19, production costs. Our production costs were up slightly, but they're in the range for the guidance for the second quarter. The real reason for this is really identifiable to one project, and that is Devils Tower. When we bring Devils Tower on production in May, we began to make fixed cost payments for both May and June even though our production was limited for the both of those months. Just a contractual relation between us and the spar provider. As a result, that explains almost all of the increase in base LOE. We will begin to see that come down through time as Devils Tower production ramps up, of course. We do anticipate that the range will be similar in the third quarter, 540 to 590 per BOE.

Slide 20, other cost. We show G&A having been 17 million for the second quarter. Anticipate a similar range, slightly higher in the third as we will be expensing certain integration costs pertaining to Evergreen. In interest, 21 million for the quarter. It should come up a little bit in the third quarter because we do not anticipate any capitalized interest during the third quarter. DD&A for the second quarter was 837 per BOE. That is in our range of guidance. Third quarter we anticipate being slightly up, 875 to 925, as we again get the effect of higher production in the higher basis wells -- Tomahawk, Raptor, and Devils Tower being the principal ones where we will have more production impact. Those are higher cost basis projects and at the margin increase overall DD&A rates.

On page 21, I have pretty much already covered the whole business of exploration and abandonments. We did have significant seismic expenses during the second quarter, principally Alaska and Argentina. Of course those are, as I say, investments in the future; and we will have the same in the third quarter, where we have some substantial expenditures in West Africa, deepwater, and Alaska that would hit third-quarter earnings. The range we're posting is about 25 to 45 for the third quarter. They will include those seismic charges.

On page 22, we incurred about 185 million of capital during the quarter. A couple of notes regarding acquisitions. We were able to close a $20 million Spraberry small tack-on acquisition. And that number that is shown as 52 million for acquisitions in more land (ph) also include our acquisitions of Gulf of Mexico leases as well as Alaska, the NPR-A and related matters.

If you then turn to page 23, Scott already covered our debt reduction results. 65 million down for the quarter. We're on target to meet our debt reduction targets we announced pertaining to the Evergreen transaction, about 600 million. I anticipate looking at our modeling that should be sometime at the end of the first quarter. We have already achieved 164 million, which leaves 436 remaining. I feel very comfortable we will meet that target in early 2005.

On page 24, we show our hedge position. Really there's no changes to this hedge position. It does not include any hedges that were put in place on Evergreen's books that were made after the merger announcement. So these are just the Pioneer hedges.

As I already mentioned, we do have supplemental slides as usual. Those are slides 27 through 32, in which we cover the typical items such as non-GAAP financial measures and the impact of terminated commodity and interest rate hedges, and also this business of oil and gas differentials. So with that I will pass it back to Scott.

Thank you, Tim. We will now open it up for questions.

(OPERATOR INSTRUCTIONS) Brian Singer, Goldman Sachs.

A couple of questions, first on Evergreen. Any more clarity on your expectations assuming that the merger does complete, or production growth, or to what extent you want to invest money in Evergreen's CapEx, and to what extent you want to grow production in 2005?

We will not come out with our core 2005 budget probably until late November, mid-December. We will give out target ranges at that point in time. But really based on what we're seeing in 2005 and what they have stated publicly, we don't see much of a change. Obviously we're going to be accelerating the drilling activity and we will factor that in, in regard to when we give out estimates in late November, early December.

But we are -- we will be accelerating the activity in both Raton, and it looks like that with initial results up in Canada and some of the coal activity that we're seeing already with some of the recompletions we may be accelerating that activity also.

Great. With regards to Argentina, can you talk more about the cost structure there and how your returns compare versus some of the other regions, especially in light of the oil price issue?

Yes, in regard to oil drilling, one of the big benefits we're getting is the fact that we are still way below 2001 cost because of the devaluation of the peso. So it is still our lowest finding cost division. So, that is the big plus. It is also our lowest operating cost division. So, even though revenues are less than, for instance, the U.S. obviously, we get those two big benefits. So we're still seeing tremendous economics on them.

Oil drilling, continuing to run several rigs. On the gas drilling side, in most of our new gas drilling we are essentially getting 65, 70 cents, escalating to a little bit over a dollar over the next 12 months. When you add somewhere between 40 and 65 cents, and the fact that the finding costs are only about 25 cents an Mcf on the gas side, it is very, very economical.

Has your LOE at all ticked up with the tick-up in gas prices? Or can you be specific on what your latest LOE rate is?

It's not much. It is still running about the same.

I know you mentioned that Devils Tower and Tomahawk/Raptor did not contribute that much to second-quarter production, but is there any specifics on the contribution to oil and gas production from each of those projects?

We are not going to give out details, but it is very insignificant. We only had one well producing for -- I think it produced about 15,000 barrels a day; we only have 25 percent of it for 30 days. Tomahawk and Raptor came on like expected, and we are producing over 300 million a day gross at the Falcon area. So, it will have a lot more impact during the third quarter.

Great. Thank you.

Ray Deacon, Harris Nesbitt.

Scott, can you tell me what are the next steps in Oooguruk in Alaska to establish commercialization there? Is it more drilling? Is it acreage acquisition?

No, it is really -- we collected lots of core and log data and seismic data from an agreement with ConocoPhillips. Then we're combining the recent discoveries with Kerr-McGee to see if there is any potential of tying both projects in together in making that decision. So that is really the key driver.

In addition, we are going to the state and asking for some royalty incentives also, so there are several things working on both the reservoir end, royalty end, and also with Kerr-McGee's discoveries that were involving all 3 components.

But the crude, if you look out in the strip market, the crude strip out in the 2008 and 2007, 8, and 9, it is up to about $33. So as we continue to make that decision, the long-term crude environment -- obviously where we could easily hedge -- is getting better and better.

Okay. Can you talk at all about your plans on the Evergreen assets for the coalbed methane potential in Canada, and what they have in the Piceance and Uintah? Is there any capital plan for that?

We are putting the teams together on all 3 pieces. We have not officially increased any activity at this point in time. We will make a decision in November-December. But we're trying to solve some of the issues that Evergreen has had in regard to gathering, in regard to the Piceance and Uintah. We're assigning a lot more people to evaluate the opportunities to accelerate the drilling; and we're doing the same thing in Canada.

Great. Thanks a lot.

Andrew O'Connor (ph), Strong Capital.

I wanted to know, given the current spot in future prices for oil and gas, and looking ahead to next year, are you guys inclined to change what you currently have hedged or is in place for 2005?

Right now, the only thing that we will do is, unless there is a project specific, I think -- just too tight a supply and demand in regard to prices, so crude is still in extreme backwardation, going from 43 to 33. So we will probably not do any hedging at all on gas or crude unless it is project specific. For instance, Oooguruk, if we sanction that project at the end of the year, you'll see us do some hedging in 2008-2009 to lock in the economics at $32, $33. We will probably not do any more hedging.

Okay. That's helpful. Thanks, guys.

Richard Friary (ph), Delphi Management.

I think in the early part of the call you mentioned something about 10 percent growth. I'm wondering if that is production from the drill bit or what that number means.

Yes, almost all of our growth -- over the past 5 years we have averaged about 12 -- has been organically through the drill bit. And most of it going forward will primarily be through the drill bit over the next 5 years.

I see. Very good; thank you.

(OPERATOR INSTRUCTIONS) Louis Marks (ph), Chesapeake Partners.

Just as it relates to Evergreen and after the completion of the merger, can you just go through the options that you will have for the Forest City Basin assets that they were unable to get an acceptable bid on? Do you intend to keep those? Or some further divestiture in the future?

Yes, we will make a decision at closing whether or not to try to -- I think there was some interest in some smaller acreage parcels in regard to some farmouts, whether or not to farm those out. We will have to make that decision at the time and evaluate the current opportunities.

Thank you.

Mark Meyer, Simmons & Co.

One question. I guess the change in the Argentine oil price formula sounded kind of like it was a bit of a surprise. I just wanted to know any thoughts on whether the risk to actually capturing some of the higher gas prices has gone up given what you see on the ground there, in terms of the economic pressures that the country is experiencing?

No, because on the gas side, actually, even though it's probably getting up to $1 -- including liquid prices it will be up between $1.50 and $1.75 within about 12 months. With them having to rely for the first time on imports from other countries such as Bolivia and paying $1.60, they are going to have to allow prices to continue to increase higher, because their only alternative is fuel oil or LNG over a long period of time. They have still a lot of gas potential in Argentina. They did put a 20 percent export tax on regard to gas prices. So I think as they allow prices to escalate, the government will be able to capture -- as they see the price increase -- capture any profit there on exported gas only.

So, on regard to crude, at the time obviously we didn't see crude going to $42 a barrel in late May. So we saw it as a 4 percent reduction, because we were getting about 90 percent of WTI. So under the agreement it was 86 percent; but obviously with crude over 36, it is down to 80. I really see that staying about the same. So, as long as we don't see the pressure on the cost side of the business, projects are still very economical on the crude side.

Scott, one more real quick. On Devils Tower, the first 2 wells, what was the completion time, start to finish?

I have got a couple people in here; I will have to let them address it. Start to finish, Bill? I've got Bill Hannes in here today and Jay Gillamotte (ph).

25 to 30 days per well.

25 to 30 days per well.

Is that being used as an assumption going forward?

Yes, in regard to our modeling for the other 6 wells. So you will see probably a well come on every month.

Okay. Very good. Thank you.

John Seltzer (ph), Maple Leaf Partners.

On the shares outstanding, I guess you noted you had repurchased a half a million shares. But the number went up quite a bit I guess in the last 6 months. Were there new shares or was that all options?

We have options that have expired. They have a short-term, 5 years; and any new shares that were issued were options.

All right. Thank you.

Rehan Rashid, Friedman, Billings, Ramsey.

Quick question on Evergreen. I don't mean to get too nitpicky, but I think the guidance from Evergreen for the second-quarter production was 12.3 to 12.4; they came in at 12.1. Any thoughts on that front? Anything particular going on? Just inter-quarter variation?

I think they were within their guidance. They are at the low end of their guidance. It happened to be for a couple freezes they had in April, snowstorms; and also the fact that they hadn't completed one of their main trunk lines yet, in regard to tying. There was about 54 wells that have not been tied in yet. So, those are the two reasons. Piceance in Canada performed better than expected.

Got you. Thanks.

John Zeringer (ph) with (indiscernible).

You don't expect to capitalize any interest in the third quarter. What did you capitalize this quarter? And did you capitalize any G&A expenses as well?

Capitalized interest was 700,000 for the second quarter. We do not anticipate capitalizing any for the third quarter. We did not capitalize G&A.

Thank you very much.

Everyone, at this time there are no further questions. I will turn the conference back over to our speakers for any additional or closing remarks.

Okay, again. Thanks. We appreciate everybody taking the time and effort to listen in. Look forward to continuing to see people out in conferences on the road. We are obviously very excited about closing this transaction in September and moving forward. Looking to another great year in 2005. Again, thanks. Please call us if you have got any questions in regard to the call or the press release. Thank you.

That does conclude today's conference. We would like to thank you all for joining us today. Have a great day.