Par Pacific Holdings Inc (PARR) 2007 Q1 法說會逐字稿

Good afternoon. My name is Rich, and I will be your conference operator today. At this time, I would like to welcome everyone to the Delta Petroleum first quarter 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 and 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, Roger Parker. Sir, you may begin your conference.

Thank you, and thank you for joining us today for the first quarter earnings release for March 31, 2007. To get started with, we will refer to the headline which is total revenues increasing to $42.5 million, but oil and gas revenue was down $3 million to $25 million. On the face of the year-over-year comparison, it looks like lower realized prices were responsible for the decrease in oil and gas revenue.

The overall reality of the situation is that property sales are the primary contributing factor to oil and gas revenue being down. Between the time period April 1, 2006 and December 31, 2006, we sold properties that had daily production of approximately 5 million cubic feet equivalent per day, that generated approximately $50 million in sales proceeds to the Company. So had we not sold the properties during this timeframe, or sold the properties that were sold during this timeframe, our production would have been meaningfully higher than the same period a year ago, and therefore oil and gas revenue would have been higher, and would have more than offset the lower realized prices that we had.

The reason I bring this up at this time is to remind and revisit what the financing plan for Delta has been over the prior 12 to 18 months. During this period of time, the financing plan included the sale of noncore, nongrowth assets, so that we could better focus human resources, but also to generate liquidity necessary to increase our drilling capital expenditures in the areas that represent the future of Delta.

As a reminder, our drilling CapEx for 2005 was approximately $90 million. For 2006 that number grew to $175 million, and as of now and projected for 2007, we are expecting 250 to $275 million. A good portion of the CapEx increases in the '06 time period were accomplished by virtue of property sales and borrowing base increases under our credit facility, specifically so that we could keep from raising new equity during 2006, while we tested our high impact areas with new wells.

Even with the hindsight of a year's time, we believe that this was the correct business and financing plan for us to follow. As a result and at this point, we have significant differences to where we were at this time a year ago. As of today the daily production for the Company is higher, even after factoring in all of the property sales that have been accomplished over the past 12 months.

We have a new operational natural gas pipeline at our Vega Unit in the Piceance Basin, which has allowed us to increase production fairly significantly in the first quarter of this year, and it has also allowed to us increase our acreage exposure through a new agreement with EnCana, on lands that surround the Vega Unit with production that will go into this pipeline. We have also established a new repeatable development area in the Wind River Basin through production testing of prior deeper wells that been drilled by the company in the '05 and early '06 time period, and we now have a continuous drilling program on what we believe will ultimately be in excess of 800 drilling locations on 40-acre spacing.

In addition to that, we also identified two new discoveries, one potentially very meaningful, in the Paradox Basin in southeastern Utah. We also have a result from the Utah Hingeline play, and although the result was not what we wanted, the results will be very helpful on a go-forward basis. And then lastly and probably as important as anything else, we also have a new Senior Vice President of operations, Carl Lakey, who started with the Company on April 23. All of these things that were experienced by virtue of the plan that we have gone through over the course of the last 12 to 18 months, and I believe as of today have positioned the Company for very meaningful production and proven reserve growth as we go forward.

We get into the other items related to the income statement, a couple of general comments with regard to DD&A and LOE. As we go forward and accelerate activity in the lower risk repeatable development areas of the Piceance Basin and the Wind River Basin, DD&A rate will come down fairly significantly over the remainder of 2007. We also expect to see that LOE as a unit cost lease operating expense will also come down as we go forward.

The other financing item that I will mention is related to DHS Drilling Company wherein revenue for the first quarter of 2007 was approximately flat to revenue for the fourth quarter of 2006, and this was primarily because three rigs were down most of the quarter. One of the rigs was being refurbished and the other two rigs were down primarily due to a lack of federal permits, not only on Delta-controlled properties, but also other properties controlled by other operators as well. As of now in the second quarter, most of the DHS rigs are in operation, and it is expected that DHS revenue will increase, from the first quarter going through additional quarters this year.

Going from there we will go ahead and move into the operations update section. We put out an operations update in mid-April so the updates as of today are not significant, but they are, there are many things that are moving forward as we speak. In the Vega Unit in the Piceance Basin, we have submitted numerous permit applications for several drilling pads, and we have the expectation that by the end of this quarter, we will be in a position to move two additional rigs into this area, which will give us a total of four active rigs by the beginning of the third quarter.

Now that would actually be three net rigs as opposed to four, because the two new rigs that are being moved into the area are going to be on EnCana agreement lands, and the expectation at this time is that EnCana will be participating for its proportional share of the working interest in the new rigs. We are also working toward continuing to increase our activity on these lands by the end of the year, with the expectation that we would be able to go to six rigs running full-time prior to year end, which would be four net rigs to the Company. We have also started operations in the Howard Ranch area with a new continuous drilling program.

We moved DHS Rig 18 into the area about 45 days ago. We have now drilled two new wells and are moving to the third well as we speak, and we are also beginning completion operations on the first two wells that have been drilled under this new program. Based on the success that we have had in the recompletions of the wells, the deeper wells that were drilled previously, we expect that as we move into the latter half of 2007, we may accelerate activity in the Howard Ranch area as well.

In the Paradox Basin, we do expect to begin drilling activities again in the Greentown prospect area later this month. We have been waiting on federal permits which we believe we will have most likely this week, and we will begin additional drilling operations during the month of May. We are also currently waiting on additional permits for locations at our Salt Valley prospect area, and also our Gypsum prospect area, both of which will be drilled after additional permits have been received.

With regard to the pipeline effort for the Greentown prospect area, we continue to work with the BLM, and we continue to experience very good cooperation on their part, and as has been referenced before, we expect that we will be able to have a pipeline constructed and operational within 12 months from now, to specifically service the Greentown area.

From there we move down to the Midway loop Area in Gulf Coast Texas, this is where we have the deep dual lateral Austin Chalk drill going on. As has been referenced in prior press releases, you can see that we have put on some very good production in that area recently. We have a number of locations remaining to be drilled down there, and as such we currently have two wells drilling at the moment. The Dickens A214, which began drilling about 45 days ago, and also the Woods A82 which began drilling just this past weekend.

In the central Utah Hingeline play, we are continuing with our permitting process for a new well on our second prospect area. At this point in time, we are expecting that we will have a permit in midsummer, and we will plan to move a rig on and immediately begin drilling soon thereafter. So some time in the July/August time period is the best expectation for a spud of a second well in the central Utah Hingeline play.

In the Columbia River Basin, the nonoperated Brown 7-24 well is currently drilling, and is expected to reach total depth in early summer, and as has been referenced before, we would also expect that midsummer would be a timeframe for additional information out of not only the Brown well that is currently drilling, but very possibly out of the other two wells that have already been drilled to date.

On the Delta side, we are continuing with the permitting process on our leasehold. We currently have three permits that we are working on, one of which we expect to have issued probably within the next 45 days. A drilling timeframe for the company on company-owned lease holds will be dependent upon a combination of when that permit is issued, but also the availability of DHS Rig 7, which is currently in the Columbia River Basin. The expectation is that that will also be, that both permits and the rig will be available in mid-summer.

Lastly, before we turn it over to questions and answers, we did place an additional commodity hedge for Rocky Mountain natural gas production, wherein we have the CIG basis differential as part of the hedge, and we did so for a volume of 15 million cubic feet per day for the 2008 calendar year time period, with a $6.50 floor and an $8.30 ceiling.

With that, I think we will go ahead and turn the call over to questions and answers.

(OPERATOR INSTRUCTIONS) Your first question comes from Joe Allman of JPMorgan.

Good morning, everybody.

Good morning, Joe.

Roger, what is the maximum number of wells you think you will drill in the Columbia River Basin this year, operated?

The maximum would be two. Right now we are truthfully just on the planning stage for a single well, but certainly given the fact that we have DHS Rig 7 in the Basin, it would be the intention to try and keep it there.

And will both of those be in Klickitat County, and also how long does it take to drill a well, do you think?

Right now, the wells that we are permitting are in Klickitat County. The expectation from our side is that wells are going to take between 60 and 90 days to drill in this particular area.

Okay, all right. Appreciate that, Roger, thanks.

You bet.

Your next question comes from Michael Bodino, Coker & Palmer.

Good morning, guys.

Hi, Michael.

I have a couple questions that I can get off my chest here, and then I can come back in the queue. I am trying to get a sense of how extensive the noncore asset sales were. What properties are left in Texas, particularly, outside of the mentioned properties and Austin Chalk and Newton?

The other properties that we, there are really three primary areas where we own properties in Gulf Coast Texas at this point, Newton, as you referenced, the Austin Chalk that we have mentioned in here, and then also the properties that are in McMullen and Atascosa County, areas that we refer to as Caballos Creek and Opossum Hollow. Each of these three areas in Texas, we believe, have remaining opportunities that we need to look at and focus on, and are focused on, but having said that, I think it is also safe to assume that none of those three areas represents long-term growth for the Company.

The real question would be, with regard to how long will we own those properties, the answer is, I am not quite certain. I think the best thing to do at this point in time is for us to pursue the good opportunities that we do have in each of these areas, and let that dictate the timing of what is done in the future. But right at the moment, the focus is on drilling additional wells that we believe will increase production and then make decisions later.

Okay. My second question is, I remember last press release you put out some guidance for the second quarter. I can't remember if that was net of asset sales, and are you reaffirming your production guidance that you previously stated a few weeks ago?

Yes. I will go ahead, I have got the April 16 operations update here in front of me, so I will go ahead and refer back to it, and specifically to the paragraph that says, production related to recently-completed sales of certain Texas/New Mexico/Kansas and Australian properties totalled 6 million cubic feet equivalent per day.

After considering the volumes attributed to those sales, the Company expects total production for the second quarter of '07 to reach approximately 4.2 to 4.5 Bcf equivalent. So the answer to your question, Michael, is yes, we have considered property sales before we put out, or before we projected our numbers for the second quarter, and as of now we will reaffirm the numbers that we put out on April 16.

Thank you. Your next question comes from David Heikkinen of Pickering Energy.

Just had a question as you roll forward through the year and increase activity levels, what do you think your quarterly CapEx will be third quarter and fourth quarter?

Hold on a second, David, I have got it right here. David, on the drilling CapEx side, it will be approximately $69 million per quarter on average for the third and fourth quarter.

Okay. That is useful. Then looking at the Q2 guidance, just to split oil and gas now in that guidance after the sale?

Yes. The split, let's see. The split is approximately 60% natural gas/40% oil.

Okay. I will get back in queue. Thanks.

Okay, David. Thank you.

Thank you. Your next question comes from David Tameron of Wachovia.

In the Piceance, can you talk about what your ramp is going to look like with EnCana? I know the drilling commitment says 128 over three years, can you talk about what the program probably looks like?

A couple of things there. The 128 that we referred to the in the press release on April 16th, if you refer back to the sentence there, it says that we can earn into up to 12,000 acres gross, by drilling a minimum of 128 wells over the time period, well over a 36-month time period.

The reality is that we expect to drill significantly more than that, and the plan as referenced earlier in the call here, was that we would have four rigs running full-time on the EnCana agreement lands as of the first quarter of 2008, and with four rigs running full-time, we would expect to drill eight wells per month, or 96 new wells per year on the EnCana agreement lands. And then in addition to that, we would keep two rigs running full-time on Vega, which would allow us to drill 48 wells per year with the two rigs running full-time at Vega.

Okay. Can you talk about where this acreage in relation to existing? Does it fill in the gap? Am I correct in assuming that?

It truthfully completely surrounds the Vega Unit. Most of the drilling activity going forward is going to be immediately to the north of the current Vega unit drilling activity, but the area of mutual interest in the exhibit in the agreement outlines an area of EnCana leasehold that essentially does completely surround the Vega Unit itself.

All right. Okay, good. Thank you. Quick question, Howard Ranch? I think the last update you guys in April said you had completed a fourth well that came on at pretty good rates. Have you completed anything since, or can you talk about what you averaged out there in terms of IPs, and what you are looking for EURs? Any change there?

No. We don't have anything new since, we are in the midst of completing the first two newly drilled wells as we speak, and we will probably have new rates as early as next week. We don't have any new production since the last press release there.

With regards to expectations going forward, the last well that we did recomplete was a very good rate. It is above average for our expectations. Going forward, what we expect is an average initial production per well of 1.5 million cubic feet of gas, and about 75 barrels of condensate per day, and also to reiterate the EUR numbers, we are using a 1.3 Bcf equivalent number at this point.

We have wells, the first four wells that we have recompleted in this area have EURs of between 1.3 and 1.9. We think 1.3 is a good number to use for modeling purposes going forward, and I will also reiterate that we expect well costs to be on the order of $1.65 million per well. Let me also for modeling purposes, since you asked the question, refer back to the Piceance Basin momentarily.

Okay.

Each rig that we have in operation has the ability to drill two wells per month, but we are in an area where we are typically drilling eight wells per pad, which means there is a bit of a lag time between initiating drilling activity on a pad, and putting wells into production. So it's not safe enough to say that you will be putting on two new wells per month per rig.

As we get into six rigs in operation full-time, we probably will have completion activity going on literally at all times, but between now and then, you will have periods where we are drilling and not completing anything, and then bringing a number of wells on over the course of a couple of weeks period of time, as we complete all the wells on a single pad.

Okay. Most of your stuff is in the Valley, right, not the plateau?

That's correct, yes.

All right. I will let somebody else. Thanks.

Thank you.

Thank you. Your next question comes from John Freeman of Raymond James.

First question is the 50 to 75 million increase in your CapEx from your year-end call, how much of that is just due to the EnCana transaction?

A fairly significant portion of it is, John. Right at the, I am sorry, I was going to try to be a little bit more exact for you. About two-thirds of the increase is related to the EnCana farmout, or excuse me, EnCana agreement acreage.

Great, thanks. Then on Newton, on your year-end conference call, you seemed to be encouraged, you all identified a couple of stones that had a much higher [water] tide. You avoided those and production was improving, and the James Gray #2 was looking better. We were waiting on results for Gray #3. I just noticed there wasn't any mention of the Gray wells in the operational update last month or in this. So looking for an update on what you are seeing on the the James Gray wells?

The update on the James Gray wells is that the lower Wilcox in the James that is present in the James Gray 1 and 3 wells is producing very well. The lower Wilcox was surprisingly gone in the James Gray #2, which is between the #1 and the #3. And the Upper Wilcox testing that has been going on in the James Gray #2 is not complete at this point in time, although I will say that it is not as good as the Upper Wilcox production in the Newton Field proper, that we have been drilling over the last couple of years.

Okay. Thanks. Then on the Paradox Basin, just looking at your most recent presentation, your well permit applications are kind of spread out between infills and stepouts. I am trying to get a sense of the next few wells that are drilled in the Paradox, are those going to be more infill drilling near those first two discoveries or step outs?

It will be a combination of both. The next well that we drill will likely be what we call the Greentown 35-12, which will be one mile to the west of the Greentown 36-11 discovery and fairly close proximity. There are some geologic reasons why we want to drill in close proximity to that well.

The second well or second set of wells would be more of a step out, and would be located between the Greentown 36-11 and the Greentown 32-42, and the reasons for drilling those locations are two-fold. One of course, for the additional geologic testing, but also secondly, to earn additional lease hold that is currently owned by another company.

That is very helpful. That is all I had. Thanks, Roger.

You bet. Thanks, John.

Your next question comes from Robert Lynd of Simmons and Company.

I want to hop back to the Piceance. What are current operating expenses here, including transportation? And is there room for improvement? Second, can you walk us through how you guys plan to drive down overall drilling in completion costs?

Drilling and completion related to the Piceance?

Yes.

It is always, as with virtually every resource play, as time goes on and as you get past the point where many of your up-front infrastructure-related expenses have been put in place, you absolutely begin to experience a reduced on average well cost. In addition to that and specific to this area, we have numerous sands in the Williams Fork formation that are productive out here, but like any other play, some of those sands are better contributors than others, and as you go forward and identify which part of your section is giving you the greatest contribution, you are better able to design fracs for those individual intervals, but also to limit on the completion side the amount of expense that you have to incur to essentially get the same production and the same reserves.

We have already noticed that pretty significantly just in the completions that we have encountered from the mid-December through mid-April time period. And as a result we have seen well costs come down, well I don't to want to say well costs, I want to say completion costs come down almost 10% during this period of time, and the experience has been on average better per-well performance.

In other words, the average IP of wells that we were completing in the December/January timeframe was about 1.1 million cubic feet per day, and on the most recent pad that we have been completing, we have had a variation in frac design, and also daily production that has increased on average quite a bit for the, and when I refer to increased production, I am referring to a peak month rate or an additional 30-day average rate.

And the average rates have gone from 1.1 to 1.3 million cubic feet per day on the last pad that we have completed here. So the expectation going forward is that we will be able to notice a better and reduced cost, especially on the completion side. On the drilling side, we have also encountered some changes.

In other words, what we are doing right now is we are drilling with a shallow rig prior to moving the large rig on a pad. We are drilling all of the surface holes first, and then moving the shallow rig off to another pad and when we move the primary rig on, it is coming out from underneath surface, and as a result the overall there drilling time is coming down. So far, it has been about a day and a half average per well that we have been able to come down. That is approaching 10%.

So the hope is that as we go forward, and have a much larger scale effort going on out here, we will be able to experience an overall reduction on both drilling and completion side, and then also some of the items that we have been experiencing costs on, which are primarily related to water disposal wells and gas gathering infrastructure will also come down, because a lot of what is necessary going forward has been put in place while we have waited on this Calbourne Valley gas system pipeline to become operational.

Thank you, that is helpful. That's all I had.

Okay, thanks.

Thank you. Your next question comes from Mike Scialla of A.G. Edwards.

Good morning, Roger. I wanted to ask you on the Paradox, given the performance of the first two wells there, are you still thinking that structure at Greentown is on the order of a couple hundred Bcf, or has your thinking changed at all since you have seen how those first two wells have performed?

Our thinking is quite a bit higher than that, and I will refer back to press releases earlier in this year, both on January 11 and March 1. Right now we are of the expectation that the discovery is a very meaningful discovery. We think that the aerial extent is very probably greater than the 7-mile distance between the first two wells drilled, and given the acreage position that we currently have, which is 29,000 net acres plus the additional acreage that we will be earning into coming up here, we think that the reserve potential for this area is well in excess of a couple hundred Bs, and is very likely on the order of a couple of Tcf equivalent.

Is that just for Greentown, or is that all of your Paradox prospects?

That is just for the Greentown area.

Okay. As a follow-up, you had recently changed your expectations on the first two wells as far as the EURs. Was that as a result of some more production testing, or what gave you the confidence to boost that up to, I think you're saying now, about 10 Bcf per well?

No, we didn't say 10 Bcf per well. What we said was that the first two welled that been drilled, both project out at this point to be able to achieve in excess of 10 Bcf. I will refer back to the January 11 press release wherein we identify that one well, the Greentown 32-42 had 5.8 Bcf equivalent of proven reserve at 12/31/06, but only half of the intervals, potentially productive intervals were completed by year end in that well.

And then secondly, in the Greentown 36-11, it had 2.7 Bcf equivalent proved reserves as of 12/31/06, but only 2 of 12 intervals had been completed in that zone. So the expectation is that each of those two first wells drilled will recover in excess of 10 Bcf per well. On a go-forward basis, we have increased our expectation on average for the overall area.

Before we began drilling this area, our belief was we would be drilling wells that would be able to produce on the order of 2 to 4 Bcf equivalent, and at this point in time, we are expecting that wells will be able to produce in excess of 6 Bcf equivalent per well on average.

Great. Thanks for the clarification.

Thank you. Your next question comes from Jack Aydin of KeyBanc.

Hi.

Hi, Jack.

Most of my questions were answered, but let me go at it this way. How long will it take you to get the Paradox Basin on production and what is required in between, and how much capital we need to, for the infrastructure to give us those wells on a production?

Okay. The Greentown project pipeline is currently in the permitting process. We have been working with the BLM for about six months now and after the original discoveries were made, we have very good cooperation from the BLM at this point. There is an existing utility easement between Greentown, the Greentown project area and the Northwest Interstate Pipeline that we will ultimately be connecting into.

And as such, it is going to allow for I think a little bit more streamlined process, especially with regard to obtaining the permits necessary to go forward with construction. Right now, the expectation is that the pipeline itself will not be operational until right about this time next year. So we are projecting 12 months. That is primarily related to winter stipulations on some of the lands out there. We will request that winter stipulations be looked at to try and identify whether or not there is an ability to build a portion of the line, or very possibly just go forward with construction of the line in an effort to try and expedite that process, but I think for planning purpose, it would be necessary to assume 12 months from now.

In the meantime and from the capital expenditure side, we expect that we will probably drill an additional eight to ten wells in the Greentown project area during this period of time with an average cost of $3 million per well. So 25 to $30 million on the drilling CapEx side and then on the pipeline construction side, we expect that the pipeline itself will likely cost on the order of 20 to $25 million, most of which will be experienced probably in the first quarter of 2008.

On the Piceance Basin, what is the cost per well? How much is it costing you to drill those wells?

Right a the moment and on the last pad, our wells averaged about $1.9 million per well and as referenced before, we would hope to be able to improve on that as we accelerate activity out here.

Okay. Thanks, Roger. That is all for me.

Thank you, Jack.

(OPERATOR INSTRUCTIONS) We have a follow-up question from Joe Allman of JPMorgan.

Outside of Greentown, could you once again go over your plans for that? You are waiting for permits to other fields, and what are the plans for your other exploration areas?

Right at the moment, the two other areas that we would expect to be able to drill in 2007 are the Salt Valley prospect area, where we do have the single well discovery as we speak, that one while that area certainly looks to be economical, it is primarily an oil discovery at this point, but the individual well economics are not what they are over at the Greentown.

In other words, right at the moment, the expectation is that Salt Valley wells will cost on the order of $2.5 million per well, and have an average recovery of 200,000 barrels of oil per well. Because it is oil and does not require a gas pipeline to begin sales, we will probably periodically drill a couple of wells in the Salt Valley during 2007, but they will primarily be fillers, if you will, for what is available on the permitting side.

The other area that we are very interested in drilling right now is called the Gypsum Valley prospect area. That is down on the southeastern portion of the basin. The geology related to the Gypsum Valley is very similar to that of the Greentown prospect discovery. So as soon as we have permits and surface use agreements worked out in that particular area, we would look to drill a well sooner than later, and the expectation is that that will probably be midsummer. That area is different from the Greentown project area in that if there is a discovery made on that prospect, we would be able to go into immediate sales.

There is a pipeline that bisects that prospect lease hold, and there is capacity on that pipeline, and in the event that a discovery is made, we would be able to begin drilling development locations fairly soon after making a discovery. So at the moment those are the plans for the Paradox Basin. We do have two other prospect areas, one called the Fisher Valley and other called the Cocklebur Draw, both of which we are continuing to work on from the land side. As they move further down the land acquisition phase, we will look to begin permitting wells in those areas as well.

And Greentown, I think you are currently producing oil. Could you talk about how that is going, and is that meeting expectations, or --?

At Greentown or Salt Valley?

At Greentown. Those are oil and gas wells and you can't produce the gas, but you can produce the oil, is that right?

Yes, you can, but what I'll say at Greentown is because we are trying to plan for and appropriately size a pipeline for this area, the primary effort on the Greentown wells over the course of the last 60 to 90 days has been to test additional intervals, perforate, and frac additional intervals so we have not had either of those two wells on consistent production in the meantime.

Can you talk about how those tests have gone? Are they looking pretty good?

We will have to more to say about those probably in the next update, but I would refer back to the comments I made earlier, related to Mike Scialla's questions about what we think as far as per-well reserve recoveries go for these wells.

Thank you, Roger.

You bet.

Thank you. We have a follow-up question from Michael Bodino.

I have got two quick questions. One on the Paradox Basin. Given the fact there has been a lot of chatter from other operators in the area, what are the, what's the probability that you will end up having partners on some of these wells or maybe in the pipeline system?

Let me add to the pipeline system to begin with. With regard to the pipeline, we think it's very important for Delta construct, own, and operate the pipeline. So that is our plan with regard to the pipeline itself. With regard to ending up with additional partners, other company partners on future drilling activity, yes, I think that that is very possible just given that there are a number of companies that have fairly significant acreage positions that are in close proximity to where we have our own acreage.

Okay. Kind of a similar question, on the Columbia River Basin, you obviously have a lot of acreage there. Now that you have done this financing, what is the Company's current thoughts on going it alone, and maybe drilling 100% working interest well, or taking a prospect in bringing a partner in?

We are considering all of that as we speak. I think certainly when we got into this area, we were very comfortable with what we have seen on the geologic side.

Not only with regard to what was drilled 25 years ago, but also with what we have seen recently, and as such, it is possible that the Company would go forward and drill 100% on its own, but given the significant acreage position that we have, which is approximately 450,000 acres that we own 100% of, I think that certainly lends itself to the idea that additional industry participation would also not be a bad idea.

Okay. Thanks very much, guys.

You bet. Thank you.

Thank you. There are no further questions. I would now like to turn the floor back to management for any closing remarks.

Okay. Well, we thank you all for joining us today and we look forward to the next conference call. Thank you.

This concludes today's Delta Petroleum conference call. If you have missed any portion of today's conference call, you may dial into digital replay at 877-519-4471 for domestic parties, and 973-341-3080 for international parties. All parties must enter the PIN number 8756208, followed by the pound (#) sign. This replay will be available from May 7, 2007, until May 14, 2007. You may disconnect your lines at this time, and have a wonderful day!