先鋒自然資源 (PXD) 2006 Q2 法說會逐字稿

Welcome to Pioneer Natural Resources Company second quarter conference call. Joining us will be Scott Sheffield, Chairman and Chief Executive Officer, Tim Dove, President and Chief Operating Officer, Richard Dealy, Executive Vice President and Chief Financial Officer, and Frank Hopkins, Vice President of Investor Relations. Pioneer has provided slides to supplement their conference today, and these slides can be accessed over the internet at www.pxd.com. Again, the internet site to access the slides related to today's call is www.pxd.com. At the website, select Investor and then select Investor Presentation.

The Company's comments today will 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-K or 10-Q made with the Securities and Exchange Commission.

At this time for opening remarks and introduction, I would like to turn the call over to to Pioneer's Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Good morning, everyone. Thank you very much for joining us this morning. Let me briefly review the agenda for today's call. Scott Sheffield, our Chairman and CEO, will be the first speaker. He's going to discuss the financial and operating highlights for the second quarter of 2006. He will also update you on the key second half operational initiatives and how the Company is progressing toward achieving its production growth goals for 2006 and beyond. After Scott concludes his remarks, Tim Dove, Pioneer's President and Chief Operating Officer, will report on how each of our assets is performing against the 2006 production and operating goals. You may recall we committed to provide this quarterly update in March at our analyst meeting. Richard Dealy, our CFO, will cover the financial highlights from the second quarter and he'll provide earnings guidance for the third quarter. And after that, we'll open up the call for your questions. With that, I'll turn the call over to Scott.

Thanks, Frank, good morning. The ones with access to our slides, we're starting out on Slide 3, Financial Highlights.

We had another good quarter. Reporting second quarter net income of 88 million or a $0.69 per share. Reported second quarter production, 99,000 barrels a day equivalent. We're on track to meet or exceed our exit rates of 95 to 100,000 barrels a day equivalent. We did complete $170 million for our remaining share repurchase program. Since May 11, we bought over 4 million shares, a little over $39 per share.

Turning to Operational Highlights on Slide 4, we're continuing to see, as we saw first quarter, strong production growth from Spraberry and Raton. Which we expect to continue. Continue to see 100% success on our prospects drilling the Edwards Trend. We drilled three more discoveries in the second quarter, we're now 5 for 5. Tim will talk more detail about those. We're are currently running 32 rigs and expect to be at 44 rigs by year end. Both of our South Coast gas projects in South Africa and Oooguruk and Alaska are on schedule, expected to come on second half of '07 and early '08. Our rig did move out into the deepwater Gulf of Mexico in Clipper. We drilled our the first successful appraisal well there. We're currently on the second well. We did increase, through a press release, increase our work interest in Cosmopolitan, that's an oil discovery in the Cook Inlet close to Anchorage from 10% to 50% and became the operator of that discovery and we'll talk about what we'll be doing in 2007 later on. In addition, we had another discovery. The Adam Ford discovery in Tunisia where we've had 100% success with that block with ENI.

Turning to Slide 5, in Summary of Activities, second half activities in North America, I'll comment on the ones primarily that Tim's not going to go into more detail on. In Alaska, we'll be evaluating an appraisal program that will be in our 2007 budget for that -- evaluating that discovery. Cosmopolitan will be planning one to two wells, maybe up to three in 2007. Winter drilling in MPRA ,we're working in new shell plays and existing acreage and new acreage which will add more color as we move into the third and fourth quarter throughout the U.S.

In addition, on the Gulf Coast, obviously we're continuing to see a lot of success coming out of the Edwards drawing 5-for-5 discoveries. We did pick up our rig and start drilling the North Well, onshore Mississippi. It will be down sometime late third quarter, in the fourth quarter. We're starting a rig in mid-August on some infield drilling in Cotton Valley Prospect. Be drilling several list late this year and next year. Continuing to add onshore acreage, both in the Edwards Play and also the Mississippi. As I mentioned, we're drilling a second Clipper appraisal well and we'll be following that with a third well, one being an expiration well. We're starting our Gulf of Mexico shelf property package, which we had mentioned previously is about 3,000 barrels a day, that will be market starting in September and expect to close by year-end or first quarter of 2007.

We're increasing our capital budget by $100 million, primarily due to the Edwards success. Primarily coming from gas processing facilities in 3-D seismic. Bolt-on acquisitions which, is about a third of the $100 million primarily in West Texas and the new Shell gas activity. Initially primarily in Anchorage and also anticipate drilling list the second half of 2006.

On Slide Number 6, in regard to Africa, we're getting ready to start a bigger program in the second half of the year, which Tim will talk about. Drilling five wells, primarily silurian-type list, very similar to what we drilled the last 2, 2 1/2 years. And in West Africa, we're still evaluating seismic on recent 3-D that we shot on some of our blocks and we'll be seeking partners for our 3 well 2007 drilling commitment.

Let me stop there.

I actually have one more slide and probably the most important slide. On Slide Number 7, this is what we laid out in the first quarter. I'm showing a five-year track of all of our categories, the development drilling, resource plays and high-impact expiration. I think the most important message is after we have six -- or two data points, the first half of 2006, we're above target, we expect to continue above target, and obviously we're very excited about it. With what is happening with the Spraberry, Raton, especially the Edwards, and I'll let Tim talk more detail about each of these specifics.

Tim.

Thanks, Scott. Yes, we are, we are very encouraged about the early returns in terms of the production growth as coming from our accelerated drilling campaign as Scott has mentioned and really, North America is a linchpin buying that as everyone knows. We have launched a low-risk drilling campaign that has really been the key to the early success. And we're drilling in areas where we have established essentially 100% success rate. That is Spraberry, Raton and Horseshoe Canyon. And importantly, North America does represent about 93% of our current production, so it is clearly the key to our growth plans. In the second quarter, production in North America was about 92,000 BOE per day. Importantly, that's up substantially both from the standpoint of a first quarter, we were up 5% from the first quarter, but up 16% from the same first half period in 2005, which is clearly substantial, and it comes from the growth that was mentioned in the play Scott alluded to. We do have the rigs necessary to implement our growth plan and we'll have, in North America alone, 40 of the rigs Scott mentioned in place by year-end with a substantial number of those working today. And accordingly, we have a lot of confidence that our production target that we established in the March Analyst Conference for exit rate of 90 to 95,000 BOE per day will be able to exceed the high-end of that range.

Now, I'll go through a production scorecard by area, Frank alluded to this. This is one of the things we're trying to make sure we deliver on a quarterly basis, how are the assets individually performing. Importantly, we're seeing a significant ramp-up in Spraberry production, owing to the accelerated drilling I mentioned in this area. 23,000 BOE per day was the rate in the second quarter, that's up about 10% from the first quarter, so you can see the impact of drilling and up substantially 26% from the first half of last year. That is, on the one hand, the result of substantially increasing the rig count and well count in the field area, in fact, we plan to drill 340 wells in West Texas this year, and we have the rigs in place or coming and contracted to do so, and believe we'll be able to hit that 300 plus well count by the end of the year. In addition to which, though, we have been able to enhance the productivity of some of the drilling by going deeper with some of the wells into the Wolf Camp, we feel like we have added net incremental reserves by 15 to 20% by doing so at relatively low cost.

Scott alluded to a small acquisitions, bolt-on type that we made in the Spraberry. Pleased with those because we can turn them into substantial value adders and production adders by virtue of downspacing.

Interestingly enough, after all the years we have operated this field, we're still out-leasing, we've added 75,000 gross acres this year and those essentially add pre-reserves in this field. So it's a real big positive to take this existing asset and enhance it by leasing. Suffice it to say, we're confident on this asset as we'll be able to meet or actually exceed most likely, the March forecasted analyst meeting exit rate shown in the graph.

Turning to Page 10 this is is the mid-continent review. Of course, these assets here are principally Hugoton and the West Panhandle field and essentially what we have done with these asset to keep them into a successful maintenance mode. Can you see that production in the second quarter was 129 million cubic feet per day equivalent, just down slightly from the first quarter. That means we've done a good job of essentially keeping production flat. And in addition to which we have some drilling campaigns, hopefully that will enable us to maintain that kind of a record and if we're able to do so, can you see we're on track to substantially exceed the March analyst forecast for exit rate in these combined fields by virtue of the activity that we're planning in the second half of the year.

Turning to Page 11, the Edwards Trend, this is obviously extremely important to us and we're making very good progress in terms of the development and expiration drilling campaign in the Edwards. You can see our production was up just only slightly in the second quarter to 41 million cubic feet per day equivalent, obviously this is mostly coming still from Pawnee. We have had little contribution in the second quarter, that being through the end of June from the new exploratory wells and in the first half of the year, we also, in a relative compared the history, limited some development drilling in Pawnee as we began to focus more on new prospect drilling in the Trend. And Scott alluded to substantial success there. You will see us have more focus on some of the more typical infield drilling at Pawnee in the second half of the year and we have about a 25-well developmental appraisal program in the second half of the year. We feel very good about the production from this trend exceeding the analysts forecast done in March as well.

What I will do now is give you a little bit more detail on Slide 12 regarding some of the recent drilling and what that means in terms of the resource here. We have, importantly, experienced several more successes in the Edwards Trend and it gives us that much more confidence in the longer-term potential in the Trend, where we continue to believe that the area holds in the neighborhood of one to three TCF growth potential with very strong returns. We also continued to lease acreage in this long trend, 250 miles long through Texas, we now have added about 30,000 acres since what reported in the first quarter. We still have an active leasing campaign in the trend and have been successful there.

Scott alluded to three successes, we were refer to those as Bonita, Barracuda and Wahoo. These are, depending on which one you're talking about, between 30 and 60 miles northeast of the Pawnee field. As you remember, the Stingray well, which was announced last quarter was 100 miles northeast, so this is now drilling prospects along the Trend north and east of the Pawnee field. The Sidor prospect, which is actually southwest of Pawnee was announced earlier this year in terms of the drilling there. As for the three wells, the new wells, the new prospect drilling, the logs indicate that we have significant gas in place and we believe they have been highly successful. We need to, obviously, test and appraise these wells and we would expect that they would all be on production in one form or another as we get to the end of the quarter and the fourth quarter.

In terms of the Stingray discovery which was announced last quarter, we have just begun to initiate production from this well, and in fact, we're now embarking upon a three-well appraisal program and in conjunction with that discovery. The thing to note here, this is really related to and similar to the Pawnee model which, is to say we have 3-D on the Stingray discovery in its area, it allows us to, with confidence, begin a development program immediately, which is what we'll be able to report about through the end of the year, that is extending the Stingray discovery into the related field area. So we have to watch the drilling in this campaign and hopefully have a lot of success in the Stingray appraisal program.

In the Sidor area, we don't have current 3-D. So one of the things we're going to do is begin to shoot a 3-D program over the Sidor area in the second quarter next year and we'll be able to then optimize a development program beginning about them. We're actually permitting the seismic as we speak. We did drill four successful well in the Sidor area as was announced earlier, two of those are currently on production. We have had a mechanical problem with one of the wells where we have to redrill the horizontal leg, so it's not currently on production, and in the fourth, we're continuing to do testing.

In total today, we're producing in the neighbor of -- neighborhood of 5 to 6 million cubic feet a day from the three wells currently on production from the Edwards Area. We will be drilling three additional new field prospects up and down the Trend during the third quarter, similar to what we did in the second quarter. We have the rigs available to develop the prospects, we have four rigs dedicated to the play and two more coming before the end of the year.

One thing to note also, we are encouraged about what we're seeing in terms of uphold potential in these various wells where we have seen Wilcox potential and other horizons as well that have uphold potential. That gives us even that much more confidence in what these wells can deliver in terms of the resource.

Overall for the year, we're still on target to drill between 35 and 40 wells with about a third of those targeting the type of new prospects that I have mentioned. All in all, Edwards looks very encouraging, gives us that much more confidence about the kind of resource play this can be for Pioneer.

Turning to Slide 13, Raton has, we're pleased about the fact that Raton has begun to really respond to our increased activity. That would be drilling and adding compression in the field, as well as well head compression. You can see the results here in the second quarter. We had 152 million cubic feet a day from Raton, up 2% from the first quarter but 8% from last year's first half. We're on target to hit our rig count, sorry, our well count, about 330 wells this year. Really, really pleased to see this field responding to the activity and we now expect that our production will exceed -- this is an annual growth target of 5% to 7% -- we think we will exceed the 7% target this year versus 2005, and we'll exceed our forecasted exit rate that we put out in the March analyst forecast.

On Page 14 is a summary of work we continue to do on three coalbed methane pilot resource projects in the Rockies. Of course what we're doing here is applying our CBM expertise to what we acquired of course in relation to what we have been doing in the Rockies at Raton, and our knowledge on completion technology and water handling and all the things from a technical standpoint to make these projects work, with the idea of trying to determine whether we have the next impact-oriented CBM resource play from the three projects.

Lay Creek is the first one listed here. What we're saying by the end of the year, we'll have 22 wells from the two existing pilots, we'll be looking at the production results and determining the next steps. In addition to which we're still in the process of drilling and testing the three additional pilots we're adding to the south. In Columbine Springs, we have similarly, a large 35-well pilot we'll be looking at beginning in the third quarter for its production results. Castlegate, we have a 25 well pilot.

In all these areas, what we're watching is, let's say a total of 82 CBM wells that hopefully will allow us to determine what are going to be the next future development plans for these areas. We continue to see Lay Creek with significant resource potential, over 1 TCF.

We're also pursuing conventional plays, we have several wells planned, 4 wells in fact, for the second half of the year in the Entrada conventional gas play and the Uinta, we're also shooting the 3-d seismic.

So lots of activity, lot of things to watch, and hopefully we'll have success in some of the pilots that we're closely watching between now and the end of the year.

On Slide 15, Canada is ramping up in terms of production. We were delayed in terms of our Horseshoe Canyon activities due to wet weather in the second quarter. We are going go to three rigs, it appears, to make sure we can catch up with our campaign. We drilled 20 of the year's 200 well campaign already. We can easily drill the rest of these wells between now and the end of the year. We have already seen the production response expected, that is, our second quarter production at about 49 million cubic feet per day, equivalent, that's up significantly about 23% from the first quarter and up and from last year.

We're also evaluating our Mannville pilots. We have now drilled four horizontal list in the Mannville and are in the process of completing those wells and in a couple of cases where we're already dewatering the wells. The objective here is to get our own data to determine the Mannville potential on our own acreage, such that we can then use our CBM expertise to unlock the puzzles of Mannville. We'll be also drilling a couple more wells, pilot wells in the third quarter. Suffice it to say, though, Canada is on target to meet its targeted exit rate as shown in the graph and that was given to you at the March analyst conference.

Turning to Slide 16, 16 shows Africa production. It's on a slight decline, as expected, but still solid product. Sable continues, this is the South African oil project, continues to exceed our expectations. Tunisia has been essentially flat. We have had a couple of recent wells tied into the Adam concession production, effectively offset declines. We're going to be wanting to do is to of course ramp up drilling and we'll talk about that on the next slide.

In fact, on the next couple of slides, we'll be talking about what we plan in Tunisia in terms of drilling and also talk about the South Coast gas project.

On Slide 17, is Tunisia. Our efforts here are focused on making North Africa, including Tunisia, a core area for Pioneer, and toward that end, one of the steps is to ramp up drilling as I mentioned. We have so far had 100% drilling success in the Adams concession and we have had Adam 4 currently on production, Adam 5 was in July, a couple of wells for the second half. These are ENI-operated wells. Importantly, in Jenein Nord, we're bringing in a rig into Tunisia, this is a block operated by Pioneer, it's adjacent and to the west of Adam and we plan to drill a couple of wells by year end. The idea being extent to the west the same concepts that have worked in the east and the Adam concession. Additionally we'll also be drilling a well in Borj El Khadra, that's a large block to the south of Adam. So ramped up activities, the hope being that we can increase production here and turn this North African asset into a core area for the Company.

Slide 18 is a recap of where we are in development projects. I can suffice it to say, both of these key development projects are on budget and schedule. Scott already mentioned South Coast Gas coming on the second half of '07. We're doing development drilling out there as we speak and doing very well.

Oooguruk, we've got a photo here of our gravel drill site. You can see a lot of activity down there in the island. What effectively we're doing right now is gravel farming. We're moving the gravel around and drying the gravel so as to encourage settlement of the island to prepare for this next winter's campaign to fabricate the productions in drilling facilities on the island. We have armor bags that were recently delivered and these bags will be filled with gravel and armoring the sides of the island to protect against wave erosion, that will be the most current activity. We'll be planning to be out there drilling development drills hopefully in the latter part or second half of 2007, first production 2008, the project's going very well.

Slide 19, well in summary, I would say the second quarter was strong operationally and we're starting to see the fruits of our strategic shift to a lower-risk, onshore, North American focus. You can see our production overall for the quarter, Scott alluded to, 99,000 BOE per day, that's up 4% from the first quarter and we do feel like if we expect that our exit rate will be 95 to 100,000 BOE exit rate that we put out in the March analyst forecast. We'll be able to meet and exceed the high end of that as we look at our current outlook. And that's coming, of course, from the ramped up drilling activity, our rig count going up, success in the Edwards and some of our other key areas and we're pleased to say our key development projects, looking out to '07 and '08, the Oooguruk and South Coast Gas are on schedule. So I guess I'd summarize it to say we're confident, as Scott already mentioned, we're exceeding some of our early forecasting and the early returns from our long-term plan look very encouraging. With that, I'll pass it to Rich for a review of the financials for the quarter.

Thanks, Tim.

Looking at Slide 20, as Scott mentioned, we are very pleased to announce a strong quarter of the financial results, reporting a net income of $88 million or $0.69 per diluted share. Net income included income from continuing operations of $66 million or $0.52 per diluted share, and this amount includes three unusual items that reduced income of operations by about $0.07 per diluted share. As we go down the slide, you will see that similar to I'm sure what you've seen with our peers that have Texas and Canadian operations, we were impacted by a Texas margin tax and the Canadian tax rate reduction.

The Texas margin tax increased our deferred tax expense for the quarter of $13 million or $0.10 per diluted share. Really the result of the state of Texas changing its franchise tax system to a more income-based tax system. We did get the benefit, a deferred tax benefit in the quarter of $10 million or $0.07 from the recent reduction in the Canadian federal and provincial tax rates. Those are phased in over the next few years. We expect our Canadian effective tax rate to drop by about 4% after the phase entry is completed.

The third item and impact was a loss on the early extinguishment of debt. Back in April, we did a bond offering and then used part of that proceeds to refinance the bonds that we had that were 6.5%, 2008 bonds, that come due in January of that year. We ended up buying 346 million of those and associate that recognized a $5 million after-tax loss to extinguish those.

Income from -- or net income also included income from discontinued operations of $22 million or $0.17, and at the bottom of the slide, can you see this is primarily comprised of business interruption, insurance gains that we received on our Devil's Tower downtime related to Hurricane Katrina. We also recognized during the quarter the $6 million gain on the disposition of our Argentine assets and had operating income of $4 million during the quarter, prior to the closing of that transaction of just regular operating income. So in total, discontinued operations was $22 million or $0.17.

Turning to Slide 21 for a discussion of our realized commodity prices, you will see our commodity price realizations include the effects of hedging and deferred revenue amortization associated with our VPPs. It's important to point out our VPP deferred revenue amortization is included in Owen Gas revenue volumes. So at the top of the oil and gas bars on this slide, we've highlighted that portion of our price realizations that are attributable to the VPP, deferred revenue amortization.

Looking specifically at oil and excluding the deferred revenue component, you can see we benefited from the continued rise in oil prices ,with the second quarter being up 20% on a realized price basis, to $56.71 from the first quarter and up 51% from the same quarter a year ago. Similarly in NGLs, we did benefit from the run-up in prices there, a 6% increase in the second quarter over the first quarter and a 26% increase this quarter as compared to a year ago. Conversely on the gas side, we did reflect the softness in gas prices during the quarter and our realized the gas price dropped about 7% from the first quarter to the second quarter and is down about 6% compared to a year ago.

Turning to Slide 22 and production costs, our total production costs for the quarter increased 4% from the first quarter. This is primarily the result of the Company increasing our estimated [ad valorum] taxes for 2007. You can see that in the yellow part of the bar. If you look at the red part is the cost that we have more control over, you can see that base LOE was essentially flat during the quarter.

I would like to focus at the bottom of the chart on the orange box there. What we've done is adjusted our production cost for BOE and base LOE for BOE and the VPP volumes to get a truer underlying view of what's happening to our costs in the field. And you can see that base LOE has gone up 16% in the past year and if you do the math you can see the production costs in total has gone up about 15%. This is at the lower end of the -- what have the industry average has been coming out and so we're pleased with that, especially given the increase in service cost and commodity prices that we've experienced during the past year.

Turning to Slide 23, a ratio of costs incurred, for the first six months of the we incurred $718 million of cost incurred, that includes $44 million associate of discontinued operations in Argentina and the deepwater Gulf of Mexico prior to their sale. Specifically. looking at the second quarter, can you see that acquisitions and land was $64 million. 60% of that number is related to a bolt-on acquisition we did in West Texas during the quarter and the remainder is really land acreage costs that we acquired in and around our core areas and a couple of new shell plays. You can see from the slide that the bulk of our spending was in development drilling, which was dedicated to our core areas. Where we have the rigs ramping up. And you can see that to a lesser extent we spent some money in advancing our resource plays that Tim discussed.

Looking at Slide 24, where we show our timeline at the top of the slide of our debt maturity schedule. Can you see in 2018, as I mentioned earlier, we added some new bonds, about 450 million of 6 7/8 senior notes We used the majority of those proceeds, as I mentioned, to refinance 346 million of our senior notes that mature in January '08 and post these actions you can see that from the timetable there, that we have no meaningful bond maturities until 2016.

I think it's also worth pointing out as part of the Evergreen transaction, we assumed 100 million of the 4.75% convertible bonds due in 2021 that you can see in line there. Those bonds are beginning to convert since we have a call option into this year. I expect all of those really to convert by the end of the year. But in the second quarter, we had 2 million of those convert and early in the third quarter we've had another 71 million of those convert. In total, if the 100 million of the bonds convert by year end, we will, you know, increase our shares by or issue 2.3 million shares, but I think it's important for everybody to recognize they reflected in our diluted share count and have been since the Evergreen transaction.

We still maintain our same debt objectives that we had at the March analyst conference and throughout the year and we would like to keep that debt-to-book capitalization below 35% and debt to EBITDA of less than 2 times. At June 30, our net debt to both capitalization ratio was 22% and our net long-term debt to second quarter annualized EBITDA was less than 1. We'll continue to monitor our debt situation and look to protect our balance sheet and future capital budget by opportunistically hedging future production as we see price spikes.

Turning to Slide 25, give you a quick update of our third quarter guidance. We expect production to range from 95,000 to 100,000 BOE per day with the lower end of the range reflecting the timing of oil shipments in Tunisia and South Africa. Production costs are suspected to be similar to the first and second quarter at $11 to $12 per BOE. Expiration and abandonments are expected a range between 20 million and 65 million, with 0 to 40 million of that range being drilling related and 20 to 25 million of that range being seismic related. And as Scott mentioned, we have two higher impact of list going down in quarter, one to test the prospect adjacent to our Clipper discovery and another to test our [Norfoot] acreage in Mississippi. Excluding those two items, you can see that the majority of our third quarter activity is dedicated to the resource plays that Tim discussed coming up in the next quarter.

Looking at the bottom of the slide of the expense items, you can see between DD&A and effective tax rates, those are very similar to what we gave guidance on the second quarter, as well as our results for the second quarter, and represent business as usual type activity levels.

As is our normal case, we have provided supplemental information at the back of this presentation for your review and to help with modeling and analysis. I would encourage everybody to take a look at that. And at this time I'd appreciate everybody's time, and we'd like to open it up for questions.

[ OPERATOR INSTRUCTIONS ] First up in the roster is Brian Singer at Goldman Sachs.

Thank you, good morning. With regard to the Raton Basin, are you seeing any changes in reservoir characteristics there, or is the improved production versus the 5 to 7% growth rates more related to the timing and increase in activity?

You -- as you recall, Brian, last year we had flat production for about nine months until we had El Paso CIG increase the pipeline capacity. I think that's -- relieving the whole system of pressure has allowed production to increase significantly. So that's why we really saw no production increases in the first nine months of last year. We were bucking up against too much pressure. The pressure system has been relieved and so, we're back on to, you know -- Tim feels pretty confident we're going to exceed it. We feel confident we'll be on the 5 to 7% range, potentially higher on an annual basis. So, getting the entire pressure system relieved and increasing the well count from where Evergreen was, about 200 wells per year to our 300-plus wells per year.

A couple of more notes in that regard. Last year, we were a little slow getting the drilling campaign cranked up, this year we're pretty much on schedule and really doing well, keeping the campaign up to speed. Secondly, I mentioned this, or alluded to it at least, we have done a lot of work this year on field compression but more importantly, well-head compression, lower pressures in the field and, therefore, add incremental production at the well. That's well been very, very positive for us. We have a lot of running room to continue those field improvements.

Thanks; of the $100 million in additional capital spending, how much of that is going to the Edwards Trend and what level of production does that new activity expect to contribute to the end of the year if any?

Yeah, I think you saw on the Edwards slide that we, I think we only show another, or actually our mark is another 4 to 5 million a day, I think. On that slide that Tim was going over. Obviously, we expect it to be much higher. Things are a little bit slower in regard to getting wells on. Primarily, a lot of our leases, as Tim mentioned Sidor Ranch, for instance, not able to shoot the 3-D. A lot of our discoveries are in the middle of good hunting territory. We have to wait until after hunting season, sad to say, so we're seeing delays there. But we should have somewhere between 10 and 15 new wells on production by the end of the year and we'll report each quarter. It's probably, you know, about 25% of the extra cost, the $100 million is for 3-D, additional 3-D, probably buying more acreage. As we had the discoveries, we're picking up more acreage around the discoveries. We didn't have 100% of them. In addition, the gas processing facilities, we're having to install in some of the new fields.

Great, thank you.

Next up from Bear Stearns, this is Ellen Hannah.

Good morning.

Hey, Ellen.

Just a couple of questions following up on the Edwards Trend. Can you refresh our memory in terms of the size of the discovery you're looking at and also the well costs there.

The well costs are still in the $3 to $4 million, $2.5 to about $3.5 million range. The expiration wells are probably toward the high-end. As we get into development campaign, they'll be about 30, 35% lower. Ranges of size is probably anywhere from 25 BCF of the 22 to 25 prospects, 22 -- 25 to as high as 300 BCF.

This is in total.

No, this is a typical, the 24 prospects.

Okay.

Have a net reserve of about TCF, Tim mentioned there -- they are 1 to 3 gross TCF.

Okay.

I think we released in March, we had a net 1 TCF potential and the typical prospect size is in between roughly 25 and 300.

Okay. Thank you. And another question, moving to the coalbed methane potential that you talked about in the Rockies, Lay Creek, you mentioned the TCF of resource potential. Is that recoverable or net to you or is that in place?

Those are a little over 1 TCF grow potential, our share of Lay Creek is 50%. That's recoverable numbers, though.

Okay. One last for me, can you remind us the Cap Ex is, the estimated for the Oooguruk development?

Let's see, you're talking about next year or this year?

Yes, next year.

Let me pull that number. Frank, do you have it?

Why don't we -- .

We'll come back to that, Ellen.

Okay.

We'll pull the number and get back. We'll report it after the next question.

Very good. Thank you very much.

Next is Bob Christensen, Buckingham Research.

Yeah, I was not clear on the Edwards reef. What is the EUR per well and what is the typical, let's say, initial production?

Yeah, it I think we laid out, Bob, 3 to 4 BCF, 100% on reserves per well and I already laid out the well cost. Initial rates anywhere from 2.5 million to about 3.5 million per well. It's very similar, I have looked at, even though we're not, what is interesting, we're not in the Barnett Shell, but I have looked at probably about 500 [oconcures] and it's very similar to a typical Barnett Shell well. Decline curve. Very hyperbolic decline curve.

And what is the clean-up needed on these? You said more processing. Was there liquids in it?

The time it takes we need, we determined -- we took Pawnee from 50 BCF to 300 BCF primarily due to horizontal drilling and 3-D seismic and we have to understand the back reef, full reef, how many reef systems there are in each of these discoveries, so we have learned through 5 to 7 years at Pawnee that we have to have 3-D. So we're drilling a lot of our expiration prospects on 2-D. Stingray which just happened, we had a 3-D on it, we can accelerate activity there. Once we have discoveries, then we're going back in and shooting 3-D before we start an aggressive drilling campaign.

Bob, also to note, regarding treatment itself, the Edwards is not unusual to have wells in the low, single digit in terms of H2S. We have to put [aiming] treatment out there for these wells.

And with the wells, are they acidized initially.

Yes.

What is the completion in the horizontal leg, I guess.

It turns out about, we're drilling most for expiration wells are vertical.

Right.

Most of our development activity will be more horizontal. We determined at Pawnee the economics are better drilling horizontal wells. They're generally acidized. Occasionally, we'll put a frack on it.

Thank you.

By the way, in regard to Ellen's question, regarding Oooguruk spending in 2007, that's approximately 140 million.

We'll move on to the next question, Robert Morris of Banc of America Securities.

Good morning.

Morning, Bob.

Just two questions on the nearly $100 million this year you spent on acquisitions, what is the net production associated with that?

No, we've only spent a third of the $100 million on acquisitions. The rest of it was acreage. So, very miniscule, probably five hundred barrels a day.

Okay.

So not much. Mostly picking up more puds than probables.

Okay, second question. You mentioned before, you thought your funding development costs would be $15 -- to $20 per year, given the success you have had in Edwards Trend and acceleration in the Raton, is that still a good number or coming down in your mind?

We're not going to change the guidance at this time. We're still in the 15 to 20.

Okay. Thanks.

Next up is Citigroup's Gil Yang.

Hi, can you, in Southwest Gas, do you have a what is called MPB?

We don't understand the question.

Do you have -- you have to have a black partner or something like that?

Oh, black empowerment. BEE. You got the letters wrong there.

In South Coast Gas. In general, the entire country, all the industry's under those type regulations, due to the riskier nation of the oil and gas industry, both us and the National Oil Company have not been able to find partners. For obviously due to high-risk nature of the expiration production business.

And what does that mean towards, towards the development of the project?

All the interest we have given out still stands as we have stated. We have, I think, 45%.

45.

45% and the National Oil Company has 55%.

You're allowed to go ahead and develop it?

Yes.

Okay. So all you need to do is try to get a partner. Is that right?

That's right.

Okay. With respect to Edwards, can you comment on what the full-cycle development cost per well is for all of the infrastructure, the aiming plants, the gathering is going to be, the process in gathering.

I think we stated in March an 8 to $10 range. All in finding cost for BOE, even though it's gas. So $1.50, $1.60 per MCF.

Gil so far in our activities in the Edwards, the new developing areas we're using skid mounted aiming treatment that is relatively cheap. It's really not that significant. A lot of the discoveries we made are in and around existing pipes. We have a lot of pipe to lay. So, the incremental infrastructure cost so far has been relatively small in the scheme of things.

Okay. But it sounds like the infrastructure doubled your full-cycle [F&B] cost.

No.

I'm sorry, sort what have you see based on the individual well.

I think the drilling, if you remember, based on what Scott said, is essentially $1 for MCFE.

Okay.

Incrementally, you'll have another -- another third for the development.

Okay.

You have to add acreage, 3-D seismic and the gas processing, that's where you get the other 25 to 30%.

Right. Okay. So -- okay. That's probably like $0.50 per MCF. And then finally, how many pud locations are you able to bulk around each successful exploration well?

It all depends on, really depends on the discoveries and the size of them. We really have to do appraisal work. Pawnee, it took us 5 to 7 years, you know, to go from 50 BCF to 300. It takes time.

It depends on your comfort of certainty for the -- .

That's right, exactly.

And what is the spacing you're using right now? Where is that --

We're drilling primarily on 80s.

Did you see that, you have any sense whether that can come down or not?

We're starting something, we're -- we'll comment more in the third and fourth quarter, but the average pay in some prospects are 100 feet, sometimes 4 or 500 feet thick and we're going in and drilling is this -- some laterals. And we're starting to see early success there. We'll comment more in the third and fourth quarter. So, if that works what, it tells me is that can you go to denser spacing. So, you have 300 feet of pay, can you can drill a horizontal well to the top 100 feet and another to the bottom hundred feet.

Okay.

We're starting to do some that of the -- some of that work also.

Okay. Would they be stacked out of the same vertical hole or separate?

Yeah, same vertical hole.

Okay. Thanks.

Moving on to Sven Del Pozzo at John S. Herold.

Hi. How are you?

Fine.

I was looking at recent discoveries announced by OMV in the block -- Jenein suit and the production per well seems to be similar from what I recall from your Adam, somewhere between 2,000 and 3,000 BOE per day. And it seems like your block is almost entirely surrounded by other producing blocks there and since is you have 100% working interest in it, and it seems to be a relatively low, geological risk, if you get -- when you get this rig in the fourth quarter, if you can drill two wells there, does that imply you will be able to drill eight wells next year or are you going to sharing that rig with your Borj El Khadra block?

That's a good question. OMV had two significant discoveries, we haven't commented on them simply because, you know, from a competition standpoint, we wanted to watch the production, but obviously, it will greatly affect more aggressive drilling campaign going into 2007. It opens up the southern part of our block there, so we're very excited about the two discoveries.

Do you think you'll be sharing the rig between the Borj El Khadra block and this Jenein Nord?

We have 2 rigs already for these 5 wells, it'll more of a 2007 program.

Something like 8 wells in 2007 in the Jenein Nord block would not be out of the question?

We haven't set our budge yet, Sven. We are obviously get -- trying to get the ENI to be more aggressive. They're coming around. We expect a more aggressive program going in 2007.

Okay, but that's in another block and this one, you have 100% working interest in.

No, we don't.

No?

No, we don't have 100% in that block.

Okay, could you please -- .

Oh, Jenein Nord, I thought you said BEK.

Let me see if I can answer your question for you. We're bringing a rig from the U.S. to Jenein Nord, okay?

Yes.

Read between the lines.

All right, and you, is this a PSE arrangement?

I beg your pardon?

Is it a PSE arrangement you have with IPAP?

Yes.

What would your net working interest be in the block? If you discover, if there's a well and it's producing 5,000 barrels a day, how much net of that is to you guys?

If the IPAP exercises their back in rights, we'll have 50%.

Okay. All right, that could still be pretty big to you guys.

Yes.

All right, thank you.

From Credit Suisse, this is John Wolff.

Morning. Looking at the cash flow statements, generated $158 million in the second quarter and the run rate spending is 350 million. Understand the balance sheet is strong. But I was wondering how that might change going into 2007, you know, depending on the oil gas prices, looks look you generate 7 to 900 million. Would you continue to want to outspend cash flow at that point?

John, our goal is to get in 2007, as close as we can to our cash flow. This is really a one year taking part of the proceeds from the divestor to jump start a lot of our development drilling programs, so we expect next year to be within 10% of this point in time of estimated cash flow.

Is there anything obvious you're spending a lot of money on this year that wouldn't be recurring in 2007 from a development standpoint?

We see a big drop-off in South Coast Gas from 2006 to 2007. Oooguruk still stays high. Oooguruk won't drop off until 2008 substantially. Those are the two big projects. Clipper appraisal won't pick up until, development on that one won't pick up until 2008 spending, so it won't be much in 2007.

What is the figure for South Coast Gas this year in terms of Cap Ex?

About 120 million, I think.

Yes.

Okay. Okay. So is that to say --are there things in exploration that would change next year. You probably drill, I would think you would drill more development wells in 2007, given your growth pools.

Yes. You're probably -- I don't know what your cash flow for is next year, I know you're a pessimist on gas prices.

Even at $8 gas, I have you at about $900 million.

Yes, you're still way low based on our forecast. Based on strip. So it's probably a disconnecting your model with our model.

Strip and our products forecast might be different than his.

Okay. Thank you.

Okay.

We'll go to a Dan Morrison at Aperion Group.

Hey guys. Can you elaborate on, you mentioned looking at some shale plays and you have historical position in the far west Texas stuff. Is that one of the areas you're contemplating or are you looking elsewhere?

Right now, I will only comment our shale plays are in the state of Texas and in the Rockies.

Okay. And when will you spud your first Norfoot test?

It's already spudded, and we expect to be down by the end of the third quarter or middle of fourth quarter.

Great. Thanks.

And we'll take our last questions from John Herrlin with Merrill Lynch.

Yes, hi, some quick ones.

Hey, John.

With Clipper, during the delineation mode, is this something you will develop or sell?

Yeah, we stated our intention is to develop it. Obviously -- generally, you get your maximum prize for the people that bought our recent deepwater and paid attractive prices. You generally have to take it fairly far down the road, John, to develop it, to get your maximum price. So our intention is to develop it and bring it on and at the same time, if we need a bunch of capital to develop out Edwards as we see it, obviously it's a good place to go. But the intention is to keep it and bring it on I think we stated it's a 2009 start up.

Okay. Same as before.

Yes.

Next one for me is the Canadian gas that was kind of your biggest gas pop. Could you break down your coalbed contribution versus your more traditional, conventional drilling, in terms of the volume add?

Tim may know that.

I think, John, as I mentioned here, our drilling campaign, we've just really recently started cranking up. So really, I'd say Horseshoe Canyon contribution has been flat for some time at about 5 million cubic feet a day. The increment you're seeing is from the incremental drilling we did in the north to the northwest BC area and other areas, more conventional gas in Southern Alberta. We don't really delineate these in detail, but it's really from this last year's winter drilling campaign.

It's behind pipe stuff?

No, it was new drill stuff in the case of the Southern Alberta stuff and actually some new, probable drilling in the Chinchaga field in northeast B.C. So not behind pipe.

Okay, last one for me is on basis differentials, you continued to widen a bit on the U.S. on oil, narrowed on gas. What is happening now?

We're seeing clearly a situation with gas prices having fallen the last quarter. A tightening of gas differentials in North America. It's in response to the high-level demand from the Mid-Continent production that we have seen substantial reductions in differentials for both our Rockies gas, as well as Mid-Continent gas. I expect with gas prices increasing, we could see a little more of the margin expansion. I mean sorry, differential expansion as we get in the next quarter. It's typical that margins tend to respond to prices in a similar way.

In terms of oil, I don't have a particularly good answer for you on oil as to that differential widening. We could probably do some analysis and get back to you, John.

Okay.

What did you say, Rich?

Calendar Versus trading.

We have a series of contracts on oil that are based on either calendar, NYMEX or trading month NYMEX. You can get quarter-to-quarter swings, depending on what is happening with the price. I don't think it's anything fundamentally in oil. We can get back to you with details on that.

Thank you.

That will conclude the question-and-answer session. Again, thank you all for your participation. I would like to turn things back to our presenters and hosts for additional and closing remarks.

Thanks. We're confident the third quarter will be just as good. We're looking forward to this call again in about three months. Everybody take care.

Thanks again for joining us. That will conclude today's conference call. Again, have a good day.