Par Pacific Holdings Inc (PARR) 2007 Q2 法說會逐字稿

Good afternoon, my name is Jason and I'll be your conference operator today. At this time I would like to welcome everyone to the Delta Petroleum Corporation Second Quarter 2007 Earnings Conference Call. Certain statements made in this conference call constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements involve a number of known and unknown risks, uncertainties, and other factors that may cause actual results to differ materially from such forward-looking statements. Many different items may affect results and they include, but are not limited to commodity prices, environmental and regulatory factors, drilling schedules, and capital plans. All lines have been placed on mute to prevent any background noise. After the speakers remarks, there will be a question- and-answer period. (OPERATOR INSTRUCTIONS) Thank you.

It is now my pleasure to turn the floor over to your host Mr. Roger Parker. Sir, you may begin your conference.

Good morning and thank you for joining us today for the second quarter earnings conference call. In attendance on this call today, we have John Wallace, our President, Kevin Nanke, our Chief Financial Officer, Ted Freedman, our General Council, Broc Richardson, our Vice President of Corporate Development, and Carl Lakey, our Senior Vice President of Operations. As you saw in the press release this morning, we have made good strides operationally with the expectation that the trend will continue quarter-to-quarter. Production growth is becoming somewhat more predictable. Our cost structure is gradually improving. Drilling CapEx is increasing, cash flow is increasing in spite of lower Rocky Mountain natural gas prices. And overall financial performance is expected to be substantially better in the coming quarters after dealing with some large one-time adjustments this quarter. We have taken a large impairment of almost $70 million, which was primarily related to significantly lower Rocky Mountain natural gas prices and marginally economic deep wells drilled in the Howard Ranch area of the Wind River Basin a few years ago. In addition, the impairment required a review of the booking of our deferred tax asset, and a decision was made to eliminate this as an asset in spite of the fact that we do expect to be profitable in future quarters, especially as we move into 2008. It is also important to note that we did not experience reserve reductions related to this impairment.

Production for the quarter was 4.23 Bcf equivalent, which was within previously issued guidance. And it would have been approximately 0.2 Bcf equivalent higher or 4.4 Bcf equivalent if not for a processing plant shutdown in south Texas, which lasted for 20 days and affected about 10 million cubic feet per day of our production. We are pleased with the production growth experienced in the quarter, which was 21% higher than the first quarter of 2007 as it relates to continuing operations. We have issued production guidance of 4.4 to 4.7 Bcf equivalent for the third quarter of 2007, which represents an approximate increase of 5 to 10% for the second quarter. This type of production growth is expected as we go forward. With regard to expense, we have realized some reductions in per unit costs with lease operating expense going from $1.11 per Mcf in the first quarter of '07 to $1.05 per Mcf equivalent in the second quarter. And although it is still much higher than it will be going forward, our DD&A rate was reduced by $0.80 per Mcf equivalent from the first quarter to the second quarter and was largely related to the one-time impairment.

We have also noticed a reduction in our drilling costs per foot for both the Piceance Basin and Austin Chalk activities, which is where we currently have the greatest portion of our drilling CapEx. Revenue was up 20% to $49 million, even though Rocky Mountain natural gas prices were substantially lower. This is due to production increases and hedging activities wherein we had previously hedged against the CIG differential and NYMEX for most of our Rocky Mountain gas production in 2007. These hedges continue through '08 and will give us much better realized prices than as seen on daily spot sales. EBITDAX was up 22% from the first quarter of 2007 and discretionary cash flow was up approximately 7% from the first quarter of 2007 and also 7% year-over-year.

Operationally, we are making very positive strides in a number of areas. In the Piceance Basin, Vega area, production has grown substantially from 2 million cubic feet per day at the beginning of the year to 22 million cubic feet per day, currently. With the expectation of being in the 40 million cubic feet per day range by year-end. We now have 4 rigs running full-time, which is approximately 3 net rigs to Delta's interest. And we expect that number to grow to 6 rigs full-time or 4 rigs net to Delta's interest by year-end or very early in the first quarter of 2008. This area should allow for some of the most consistent production growth in the near future. We also note that Barry Petroleum, operator of the Garden Gulch field now has 3 rigs running full-time in that area of the Piceance Basin with the expectation of going to 4 rigs full-time by year-end. This would represent about 1 net rig to Delta's interest from that area.

In Laramie County Wyoming in the northern DJ Basin, we have a new field discovery that we refer to as the Cowboy Prospect. We have drilled and completed 6 successful wells, which have gross daily production of approximately 1,000 barrels of oil per day. Individual wells are costing approximately $1.2 million and should recover an average of 125,000 barrels of oil per well. Nearby fields, specifically the Golden Prairie and Shivington fields have produced between 1.5 and 3 million barrels of oil. So reserve recoveries are expected to be fairly good. We are continuing to drill and run 3D seismic to further delineate the field size.

Drilling in the Austin Chalk continues to be a positive. The Simmons well which has been on production for almost 5 months looks to be a 13 plus Bcf equivalent well. And we just put on a new well, the Dickens, 3 days ago at an initial rate of 14 million cubic feet of gas and 1500 barrels of condensate per day. We're also drilling the Woods Well, which is expected to be on in early September. This area has very good economics with more locations remaining to be drilled.

In the Howard Ranch area in the Wind River Basin since last reported we have drilled 4 new wells and recompleted 4 deep wells. And we are encouraged by the initial results. We are waiting on numerous additional federal permits and we will resume drilling activities again later this month at the Howard Ranch area. Moving to the Paradox Basin. The Greentown project specifically continues to be an area of great potential. As referenced in the press release this morning, we have had mechanical challenges related to casing collapse issues in salt formations, but we do believe it can and will be accommodated for as we drill and test new wells. We are currently drilling near the 30 Greentown State 36 - 11 discovery well. And we have recently made a decision to move in a second rig to expedite drilling and obtain results quicker. The second rig will drill on the southern end of the Greentown project near the Greentown State 32 - 42 discovery well.

In the Utah overthrust, we are in the permitting process for our second well in the play at what we call our (Parowan) Prospect. And we believe we will have a permit within the next 30 days with drilling to begin immediately thereafter.

In the Columbia River Basin, the non-operated Brown well is still drilling and Delta now has two drilling permits with a third in process. Our drilling operations should commence sometime after the rig has been released from the Brown well. With that, we will go ahead and turn over the call to questions-and-answers. Operator?

Certainly. (OPERATOR INSTRUCTIONS) Our first question comes from John Freeman with Raymond James. Please go ahead.

Good afternoon, guys.

Hi, John.

First question on the Midway Loop, a while back this was one of the three packages you all were looking to divest. With the excellent results you all have had on the BP America, Simmons and now the Dickens, have you changed your stance on these asset? You sound a lot more positive, saying there is a lot more opportunities to drill there.

The answer is, yes. We -- drilling horizontally in the Deep Chalk does present some challenges of its own, which we did experience early on. Drilling challenges. And we have been able to come over that in a big way. And the well results are so good and so economic that it does not make sense for us to divest of that asset at this time. We do have a number of additional locations to be drilled. And as such, we will keep at least one rig running and possibly two in that area for the foreseeable future.

John, this is John Wallace. We plan to spud the Baxter location here next week. Which will be an offset to the Dickens well. So we do have some running room out here and we do plan to continue to develop these wells. As Roger pointed out, we really have been successful at lowering the cost per foot to drill these horizontal wells and really improve upon the economics.

Okay. And then moving over to the Paradox -- just trying to get the time line right there. When will we expect actual completed results on the Greentown 35 -12 and than likewise, when do you look to spud the Federal 28 -11, and when should we expect results from that well?

Drilling results on the 35 -12 we expect in approximately 30 days completion results. Shortly thereafter, depending upon what our completion procedure actually is. And as far as spudding the 28 -11, we're expecting to spud that well later this month with we expect the well to take 30 days to drill to TD.

Okay. And should I still use 3.5 million a well on the cost?

For right now, I don't think I would change the model verses on cost or reserves. There is a possibility that we think that the well cost may come down. But it's premature at this time.

Okay. And then moving over to the Piceance. You all mentioned that this was one of the areas where the costs had come down. Does that mean that the prior guidance you have used of kind of assuming 1.25 Bs , and 2 million completed well costs. Is it 2 million now lower?

No, John, this is Roger. I think 2 million is a good number to use for the time being. Although we do expect that by virtue of a number of improvements out there, including a new long-term deal with one of the frac companies that we will be able to experience average well costs below that number as we drill significantly greater number of wells. We also have gone through that lot of the initial infrastructure costs that you experience in any start-up of any play. And a lot of the things -- a lot of the costs that we're experiencing over the last 12 to 18 months are not going to be as necessary or as high as we go forward.

Okay. And then, last question I had and then I'll turn it over to somebody else. On the Utah, if we just assume that spuds at the end of September, when just rough idea would you expect results on that well?

Are you referring to to the overthrust?

Yes, yes.

Okay.

It'll take 30 days to drill to the first primary objective. That being the Navajo and then an additional 30 days to drill to the secondary -- the second primary objective, if you will, which is the [Kibab] So you could expect 30 days into the well and the Navajo. If we do indeed have an oil-bearing feature here, news will be shortly thereafter. And we would probably not take that well down to Kibab We would take subsequent down to. If results are unknown based upon drilling shows, then we'll go ahead and take the well down to the kibab log the entire formation, and that would take 60 days.

Great. Thank you all, very much.

Thanks, John.

Our next question comes from David Tameron with Wachovia.

Hi, good morning.

Morning, David.

Can you talk in the Vega? Can you talk about some of the well performance? Obviously looks like your production's going to ramp pretty nice before year-end. Can you talk more of what you're seeing out there, expectations, kind of how the drilling program's going, et cetera?

Yes, I tell you what, David. I think we may have Carl Lakey, our senior VP of operations give you some response to that question.

Thanks.

Just a moment.

Okay. Our initial results IP in these wells between 1.2 and 1.5 million cubic feet a day and about 1.2 to 1.25 Bcf for reserves.

David, this is John again. I will say as we move north towards the north Vega acreage in our earning ratio with EnCana, the wells appear to be getting better. There's a very likely possibility that at some point down the road we will guide the reserves in that area higher than at 1.25. But currently we're sticking with that.

That's where I was going with it. As you move more towards the EnCana acreage it does look more encouraging?

It gets better, yes.

And in your Cowboy, up in Laramie, can you just talk more about how much running room you have there? How many acres? What the extent could be? Do you have some size of magnitude?

Yes, David, that's an area that we have generated internally. We've acquired most, if not all the acreage. That is why we're doing the 3Dshoot. We think this might encompass several thousand acres. Currently, as well on a 40-acre pattern. The 3D will help us to extend the field over what we currently have mapped based upon subsurface geology but what we have mapped on subsurface geology would lend this field size to be about 10 wells. But we think the area of the overall area could ultimately be 30/40, even north of that as far as ultimate well count.

Okay. And is there any -- talking about the (Inaudible) is there any potential gas?

Not measurable.

Okay. That's all I got. Thanks, appreciate it.

Thanks.

Our next question comes from Robert Lynd with Simmons and Company.

Morning.

Hi, Robert.

Morning, Robert.

Roger or John, can you tell me what type of diagnostic work you've done on the Greentown and Salt Valley wells to determine where and to what manner the casing collapsed?

Well, diagnostically, the best explain this is running in and out of the hole, in and out of well bores and our testing efforts and setting packers and various different things. And that's how we're really noticing where we're seeing some collapsed casing problems. I will tell you, it's worth noting that in this area 20 miles Southeast of our Greentown area is the Long Canyon field, and the Long Canyon field produces from the Cain Creek formation, which is just below our ozone, a few hundred below our ozone. And that particular interval looks no different than one of the specific interval that is we have in our Paradox, plastic interval that is we refer to. In that area, the Discovery well, the Long Canyon No. 1, made over 1 million barrels of oil has been on for approximately 45 years. So ultimately, we know we can produce these wells, in this salt section. Has a similar salt section as we do in Greentown. And conversely down there or similarly down there, there are numerous horizontal wells that are in one specific classic interval that have ultimate reserves average probably half a million barrels. And those wells have been on for 15 to 18 years. So we know that you can produce these wells in this salt section. I will tell you that this is unique. If you look around the world, you won't see stack (Inaudible) intervals in a salt section. That's the predominantly. That's the predominant pay interval. But our casing caliper log tells us a lot about the casing collapse where we're seeing it. And it's not 100% collapsed, it's just weakening of the casing and where the casing moves some. But because we know in the Long Canyon area that you can produce through this entire salt section, we know we can overcome it. Our new casing design is hopefully going to overcome the collapse forces. Again, you just don't see a lot of plays like this that you can use as a go-by because most plays involving salts are up against the flank of salts, not actually in the salt play itself.

So at Long Canyon, did they have similar casing issues there? Or is this just --

They did and they do. Even on the Long Canyon well, they've had to go in and swedge out casing collapse in the past and have been able to overcome at the well making 50 barrels per day and it's been on for 45 years. It can be overcome. It just -- it's a different learning curve that there are not a lot of go-bys out there. We think we have made big strides in our new casing program.

What are you going to do differently with the new wells? Are you beefing up the casing? And how much does that add to cost?

Let me turn it over to Carl because he knows the specifics of this. He's been working on this ever since he got here.

The short answer is we are beefing up the casing materially. Our collapse resistance is going to be up, not quite double what it was in the original casing, plus a more robust cementing procedure to also keep the salt off the casing. In addition, we're also running a larger strain that should allow flexibility going forward operationally. So based on all the research we've done in salt section drilling in other parts of Rocky Mountains and in the world, our casing design is at the top end of what has been designed successfully in those provinces. So we feel pretty comfortable we're going to have this beat.

Okay. Sorry to keep on this. But do you guys have an idea of how the reservoir was performing before this casing collapse issue?

No, unfortunately, we noted some of the zones are hydrocarbon bearing. Some of the zones we didn't get very effective tests off. We did not have sustained test information due to this casing collapse. On numerous of the uphold zones. And that's one of the frustrating things about where we sit right now. But I can tell you in these new wells that we believe that this new casing program will allow us to give effective long-term production tests on different specific intervals.

Okay. John. Thanks for that. I'll get back in the queue.

Okay. Thanks.

Our next question comes from Larry Busnardo with Tristone Capital.

Hey, again. Just to follow-up on the Paradox basin questions. When was first determined you were starting to have issues with the casing?

We've -- Larry, we've kind of experienced it all the way along. This is Roger, we've experienced it all the way along. We have noticed that in many of the intervals, we have had expected that it would be limited to certain intervals. And as we've gone through and attempted completions in most of the zones in the wells out there, we've actually experienced it in most of the intervals. Which has caused the detailed review with regard to how the wells will be designed going forward.

A lot of this is fairly recent, Larry, especially in the Salt Valley well. This happened the last couple of months.

Okay. And I heard you talk about the different casing or thicker casing and beefing up the cement job. To me it sounds like you're going to be adding costs to the wells, but you talked about being able to actually lower the cost. When you talk about lowering costs, is that more associated with just going into a development mode?

That and the possibility that we won't complete all these zones simultaneously.

We are also under the belief, Larry that we will be able to reduce the drill time on these wells from what we originally experienced when these wells were first drilled a year ago.

That's a good point. We have a new drilling procedure as far as the type of drilling that we're going to do that we think will save time and money.

That's more a function of you guys just being able to drilling more wells out there and understanding the play more. Correct?

That's correct.

Right.

Looking forward to the remainder of this year, you've got one rig running, you got a second rig that you are going to be adding. How many more wells can you get drilled in the Paradox between now and the end of the year?

You can -- at the moment you can assume 30 days per well, per rig. So the hope would be that we'll have 6 to 7 wells drilled by year-end. We probably won't have results from 6 to 7 wells, but we would expect to drill 6 to 7 wells.

Okay. So you plan a continuous going forward then?

Yes.

Shifting over to Howard Ranch. Was that 4 new wells you said that were drilled? How many total wells you drilled now at Howard Ranch?

Well, we've drilled 4 new wells and wee recompleted some of the older or excuse me the deeper initially [lance] producing wells. And of those 8 wells, we've completed 6 fully. And we're really just beginning completions on 2.

So there hasn't been any recent activity out there?

No, we're going to continue kind of restart a continual drilling program once we've got some federal permits. Probably in the next couple of weeks.

Okay. All right. Thanks, guys.

Our next question comes from Joe Allman with JPMorgan. Please go ahead.

Hey, everybody.

Hi, Joe.

Morning, Joe.

Hey, good morning. What's your ETA on getting that rig over to the Gray well in the Columbia River Basin?

It's the -- Joe, it's the rig that is currently drilling on the Brown well. And we don't know when that well will be complete. So it's entirely dependent upon when the rig becomes available.

Okay. Can you confirm that that well is through the basalt? I think when in an Xcel press release, Xcel bought half of EnCana acreage indicated in their press release that it was through the basalt. Can you confirm that?

Yes, we will be careful not to make any comments directly about the information. But given that that's out there, yes, we can confirm it's through the basalt.

Okay. And then depending, I think EnCana said it would release results no earlier than the end of this year. How might the result -- will the results -- I guess you're going to start your program before EnCana releases results potentially. Will the results of the first three wells there impact your activity? Or are you just -- you don't think it's going to impact your activity?

No, not in the slightest. We're a little bit south of where EnCana's been drilling. And we have three different prospects that are all independent of one another and definitely independent upon what EnCana's results have been.

Okay, that's helpful, and in the Paradox Basin for the Greentown and Salt Valley. You mentioned $3.5 million, is that just Greentown? And what would be the cost of the Salt Valley wells in your estimation? And then give us some guidance on the reserves for Greentown and Salt Valley?

The cost of Salt Valley is less because it's not quite as deep. Salt Valley's in the $2.5 million range. And currently we're looking for cost to be especially on the development side of Greentown to be 3 to 3.5 million on a per well basis.

Okay.

I don't think we've learned enough about the specific individual classic intervals to change any of our forecasts as far as future reserves. So those stated in the past, I think we definitely think that it has that same kind of potential. So --

Are we talking like Greentown 4 to 6 Bcf per well and Salt Valley 1 to 2 Bcf per well, something like that?

With Salt Valley, that's probably a number that's closer in line. I'll come back to Salt Valley here in a minute. But at Greentown which is really the predominate field we internally been modeling 6BCF. And we currently have no reason to change that estimate. In the Salt valley area, we're a little perplexed in the initial wells producing predominantly oil and very little gas. Yet all the wells used to define the prospect tested gas and very little oil. It's a little bit more of an unknown target as far as what we think ultimate reserves would be at Salt Valley. It's currently not producing at a rate, even though it's only producing from the formation. We were looking around 2 Bcf equivalent.

200,000 barrels per well.

200,000 barrels per well for Salt Valley.

Our next question comes from Michael Bodino with Coker & Palmer.

Hey, guys, how you doing today?

Good, Michael, how are you?

I'm just fine, a little busy on these earnings. Couple questions, I have one follow-up on the paradox. I think we've gone through that in quite some detail. One of the things you didn't mention was the pipeline infrastructure. Where are you in process of permitting building time line of that? And given the issues, is there anything that would push that out any further?

As far as the pipeline itself, we've completed the deeper work, which took the majority of the time in this process and is now in front of the BLM And we're hopeful that the -- I know the BLM working on EA and we're hopeful to see something later this fall. As far as the exact time line as far as construction and for sales, we're still operating under a May '08 for the pipeline being operational.

So these issues are you consider kind of non-issues relative to pipeline in there?

Correct.

Correct.

Okay. Moving on to a couple other areas that I wanted to get questions in on. Howard Ranch. Now that you're getting some production history out there on the recompletions and the new drills, any good estimate on where costs are migrating to or what EURs in that area look like?

Yes, Michael, it's Roger. On the wells that have been and I'm referring to to the 8 wells at this point, the 4 new and the 4 recompleted deep wells, 2 of which are still experiencing additional completion work. We have an estimate of a total of 5BCF of gas and 200,000 barrels of condensate for reserves on those--- well actually that is for 6 wells. It does not include the 2 that are being completed as we speak. So the reserve estimates are maybe slightly less than what we had originally said, which was 1.3 Bcf equivalent per well. But the economics appear to still be very good. The wells are coming in at approximately $1.75 million per well. And we're looking at approximately 1.05 to 1.1 Bcf equivalent for the initial wells. I would say that given that we think that this extends over a much larger area, it will probably take another 15 to 20 wells to have a real good handle on what individual well economics would be. And we do expect that costs would be able to come down.

Okay. The last question I had is on the Columbia River Basin, I know you mention in your press release that drilling there is likely commensurate after the Brown well reaches TD. Where are you in the process of talking to or trying to solicit partners for that project?

Michael, it's John. We've been approached by several different companies about our acreage and CRB. This is not something we actually generated. And we begin talking with some various different groups. We do not have anything to announce. I will say there's been a fairly significant interest by pipelines, end users, and ENP companies and I think it's fairly safe to say that they have a lot of interest and appeal, at least in our acreage position. But we currently are just in exploratory talks with (Inaudible)

Our next question comes from Jack Aydin with Keybanc.

Hi, guys. Most of my questions were answered. But one, go back -- going back to the CRB. John and Roger, what kind of recourse you talking about that EnCana has drilled so far 3 wells there? What kind of costs you're looking at?

Jack, I think that's probably a question that EnCana probably ought to answer. I can tell you what our cost estimate is for our first well, which is going to be fairly deep well is going to drill through the primary roslyn formation and into the deeper formations that we think might be potentially perspective as far as conventional reservoirs. So it will fairly deep well to 15,000 feet. Our drilling costs on our fee are $12 million and our completed well costs are $18 million with obviously a very large frac bill in the Roselyn

John, let us hope that first of all it's successful. But just for hypothetical. If the first well is not what you're looking for or you got what, nothing what you're looking for, would that condemn the next two wells? Or you will proceed with the NEC two wells?

No, Jack, tough remember that this is -- we're not looking for a new field, we're looking for a new basin. And this is a big aerial extent, the Columbia River Basin. It's twice the size of Connecticut and currently two old wells in the basin and now two wells by EnCana. That's really kind of touching the surface as far as exploration efforts in the basin. So our prospects are all independent of one another. I can tell you if we drilled a particular prospect and it didn't work, you probably will not drill anymore wells on that prospect. But we have 14 separate prospects throughout the basin and they're not really dependent upon one another. We feel pretty comfortable that we understand the source capability of the basin. We feel pretty comfortable that we understand the reservoir rock potential for the basin. So each prospect pretty much stands on its own.

Our next question comes from Michael Scialla with AG Edwards.

Hi, guys.

Hi, Michael.

On the Piceance with the success we've had there, are you still thinking in the Vega area that 20-acre spacing is appropriate or is there any potential to go into to tighter spacing?

Michael, it's John. We really have done, I think an effective job of trying to design our frac links and our frac work to drain 20-acre spacing. So while there's been the idea that the true spacing of the Williams fork and the Piceance Basin is somewhere between 10 and 20, we really have done a fairly effective, at least recently in our last several wells seen some effective results in what we think that we're trying to design a 20-acre drainage pattern. And having said that, I think that's what I was alluding to earlier that we might see more reserves on a per well basis than we previously guided to. That's where it'll come from, Michael is actually trying to increase our fracs. A full 20-acres instead of something less than that and have to do a 10-acre program as far as to reach the additional reserves left behind and obviously have some accelerated drainage. So we really are targeting a 20-acre spacing.

That makes sense. With the plan to get to 6 rigs by the end of the year or early '08, I know you haven't put your capital plans together for '08 yet, but would you think you keep 6 rigs flat for the remainder of the year? Or would you hope to continue to ramp that into '08?

We, Michael we do expect to have at least 6 rigs running full-time throughout the year. It is possible as we go through the year that we would look to ramp-up activity. But we have not budgeted for or made plans to do that as of yet.

And then along the same lines with Howard Ranch. If you get a rig back in there, what do you think you could do there next year? Are you constrained by permits? Or do you just need to go slow to see more results there?

It's a combination of both right at the moment. It's a combination of going slow and getting the permits in the appropriate areas right at the moment. But with success over the remainder of this year, that is an area where we could ramp up rig activity fairly easy going into '08.

Okay. And then the 6 to7 wells you mentioned in the Paradox, were those all in Greentown? Or was that a combination of Greentown, Salt Valley, --

It will be a combination of Greentown and Gypsum Valley, Salt Valley in the press release we noted that the Salt Valley we would not drill any new wells in the Salt Valley until we've been able to determine with a fair amount of certainty that we can get passed the casing collapse issues at Greentown.

Okay. So most of those are going to be in Greentown then?

Most of those will be in Greentown.

Yes, most in Greentown, at least one in Gypsum Valley.

Okay. I'll try one more on the CRB, probably won't answer me. But it seems like you were anticipating that well, the Brown well was pretty close to TD on the last call. And it's still drilling now. Has there been any drilling problems there? Or has it been going deeper than you might have initially thought?

Michael, it's a good question, but you were right before you asked the question. [ Laughter ]

Okay, well, I had to try. That's all I have, thanks.

Okay, thanks.

(OPERATOR INSTRUCTIONS) Our next question comes from David Heikkinen with Pickering Energy.

Hello, just one wanted to dig in first question on the Vega. What are your current well costs? And what do you think they can go to as you kind of stabilize a 6plus rig program?

Out well costs are running right at $2 million right now. And we're hoping that we can see 1.8 on the horizon and as time goes forward, we may find ways to do better. I think those are the reasonable and attainable.

And thinking about prioritization of capital. Whenever you think about, what areas have the Vega ramping up activity, that would indicate better economics there than other areas. How do you allocate when you think about your allocation of capital? What would be your weakest area? What would be the strongest?

Well, I don't know that you could refer to areas where we have active drilling programs going on as being weaker or stronger. The Austin -- the individual well economics on an area like the Austin Chalk are probably the best that we've got in the Company right at the moment. But the difference between drilling there and drilling at the Piceance Basin is that you can drill 8 wells with a single rig in the same period of time that it takes to drill one well in the Austin Chalk. So in terms of proven reserve growth and production ramp-up and overall economics, you're not terribly dissimilar. I think in areas, certainly in areas when you look to places like the Paradox Basin and the Howard Ranch area in the Wind River Basin the economics are good and the real question or the expectation is that the economics are going to be very good. We've got a lot of work to do to prove exactly what they are in the Paradox Basin, although initial indications are obviously we expect them to be very good.

Howard Ranch we would expect something to be more similar to the Piceance Basin but able to repeat many times over a larger area and give us a much larger base to grow from than a place like the Austin Chalk. So we're really looking to try and build on what we've already got working in areas like the Piceance and Austin Chalk and add to that through these other areas.

Okay. What was your CapEx in the quarter? And what's your year-to-date CapEx?

Do you have that? David, hold on just a moment.

Okay.

We're wrestling around for the actual numbers. I will tell you that based on the budgeting discussed at our let's see second quarter actual was 60.5 million drilling CapEx.

Okay. And total CapEx?

First quarter -- well total CapEx 6 months is 121 million. Drilling CapEx. And the and we are still as mentioned before, we are still on budget for a total 2007 drilling CapEx of 270 million.

Okay. And kind of thinking about, again, that ramp-up in spending going into the back half of the year and then what the implied '08 budget is. How do you think about financing? What the run rate '08 budget would be verses where your cash flows on EBITDA are? As also as you see, we haven't published expected cash flows or production for 2008. We obviously do expect good production increases, which will translate into cash flow increases by year-end. I think there's no doubt that as we go into '08 and as we ramp up these drilling programs we will need to consider if we do increase our drilling CapEx as we expect, we will need to consider other ways to finance the additional increases. The likely scenario is that at that point in time and probably not until early in 2008, we will look at some property sales which would include primarily areas in south Texas not related to the Austin Chalk. So that is the at this point in time the primary idea for financing, drilling, CapEx increases as we go into '08. Okay. And then just final question thinking about the Paradox Basin and the well integrity problems. Kind of targeting investing $25 million roughly there. Is that aggressive given not a clear path understanding well integrity?

No, we don't think it's aggressive at all due to the results that we have experienced. We think there is a very large reserve potential in what we have seen. And we think that that absolutely warrants the gathering of additional information at this point. And really as quickly as we can.

Okay. So no concerns really a lot of confidence in the new casing design and not having well failures from here forward?

Yes, I would be, yes, that's correct.

Okay. Thanks.

Okay, thanks, David.

At this time, we have no further questions, gentlemen.

Okay. Thank you for attending today's call.

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