Good day and welcome to the Delta Petroleum first quarter earnings call. (Operator Instructions) With that in mind I will turn the conference over to Broc Richardson. Mr. Richardson the floor is yours sir.

Thank you, good morning. This is Broc Richardson, Vice President of Corporate Development and Investor Relations. Before we begin I need to read the forward looking statement disclosure. This conference call will include projections and other forward looking statements within the meaning of the federal securities laws and are intended to be covered by the safe harbors created thereby. In that regard you are referred to the cautionary statement displayed on Delta’s website which is incorporated by reference to the information provided on this call. Further, the Securities and Exchange Commission permits only gas companies and their filings with the SEC to disclose only proved reserves that the company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Delta may use certain terms in this conference call that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in Delta’s form 10K for fiscal year end December 31, 2007 as updated by subsequent periodic and current reports on forms 10Q and 8K respectively. On the conference call today from Delta are Roger Parker, the Chairman and Chief Executive Officer, John Wallace, President and Chief Operating Officer, Kevin Nanke, Treasurer and Chief Financial Officer as well as Carl Lakey, Senior Vice President of Operations. With that I’ll turn the conference call over to Roger Parker.

Thank you Broc. Good morning and thank you for joining us to discuss our first quarter results. I’ll open today by saying that the company is now experiencing the benefits of significant preparation and implementation at all levels. And it is being realized in the most important areas which are reserve growth, production growth and cash flow growth. Internally estimated proved reserves have grown by 60% over year end 2007 levels in the first quarter alone. Much of the growth was related to our previously announced Piceance Basin acquisition. But as you can see organic growth has been very meaningful in a short period of time as well. And the company is now estimated to have an excess of 600 Bcf equivalent in proved reserves. Additionally production growth is occurring consistently and at expected levels that will allow for the substantial growth we have projected for 2008. Production from continuing operations was up 68% over prior year levels and the second quarter is projected to be up 8 to 12% sequentially and over 40% higher than the prior year period. So it is very apparent that production growing – production is growing at the significant rates necessary to achieve the high standards that we set at the beginning of the year. We are realizing substantial increases in cash flow. Discretionary cash flow which is a non-GAAP measure was up 87% year-over-year to $31.3 million for the quarter. This is a function of higher commodity prices and production increases and is expected to continue to grow accordingly as we go through the year. This will further allow for plenty of available liquidity as we move forward. In an effort to assist in determination of our currently – current liquidity position we have added a paragraph to this press release describing what…

Yes sir. (Operator Instructions) And our first question comes from Larry Busnardo of Tristone Capital.

Good morning Roger.

Good morning Larry.

First on the Greentown 28-11 well, is that being constrained at all because I think you initially talked about the well being able to flow at a higher rate and the 200 barrels and the 600 million – or 600 Mcf a day seems a little bit lighter than what you had initially talked about.

It is, Larry, it is not being constrained at all. It is limited to production from the “O” and the “P” zone. The Cane Creek interval is not currently contributing at this point in time. Part of the process that we are continuing to go through is gather information, both production and pressure from individual intervals which is what we’re doing at this point. That well is being produced vertically primarily because we do not have another rig to be able to put over it at this point in time. Ultimately it will likely be drilled horizontally in both the Cane Creek and the “O”.

Is that well being flared right now?

Yes.

Okay. Are there any flaring constraints?

No go ahead, Carl, go ahead.

There is a constraint at 50 million cubic feet. Total production however, we’ve been able to work with regulatory bodies to allow some leniency to that. That constraint could still reappear but at least at this point we’ve been able to work with the bodies to allow us to continue to test the well.

Okay. And then just a second one. In terms of the duly completed wells, what’s the comparison on the EURs and the cost of these duly completed horizontal wells versus the initial vertical wells? I think you were initially talking six Bs and 3.5 million a day on those. Can you just give us a comparison between the two?

Larry, this is John. It’s a good question and as far as on the completed well cost we’re expecting that the horizontal legs to the general cost of those legs will equate to an artificial stimulation or a frag. So there will be additional cost but it will only add about 700,000 to $1 million for two laterals in both the Cane Creek and the “O” zone which we’re expecting to be several thousand feet in length. As far as the reserves right now what we need to do is get some of these formations online and before we can really alter our reserve projections. So right now I think our initial reserve projections of six Bcfe we feel pretty comfortable with.

And that 700 to a million, was that for both horizontals?

For both horizontals.

Okay, great. I’ll just back in. Thanks.

Thanks Larry.

And the next question we have comes from John Freeman of Raymond James.

Hi guys.

Morning John.

First question I had, it looks like just looking at your most recent presentation that you increased your acreage position in Greentown by I guess almost 20% via I guess you only have 6,000 acre farman [ph]. Can you just elaborate on that?

Yes, that’s a farman we have from a third party. It requires two more wells to fully earn the acreage via the agreement. We plan to drill the second – we’ve drilled one well, we plan to drill the second well here this summer and the third well later this fall. It’s high up on the anticline. We think its very perspective acreage and its lands that sit generally between the first two original wells.

Okay. Moving over to the Piceance – I’m just trying to get an update kind of on where you all stand from kind of what you all’s initial kind of goal was in terms of cost per well. I think your original goal was like 1.8 million and I think you all were internally modeling like 15 days to drill. Just kind of what the latest kind of trends have been there.

We’ll let Carl Lakey take that one.

Yes. In the first quarter our actuals came in at 2.15 using some field estimates for cost and haven't fully hit the accounting system yet. We feel confident in those numbers. Second quarter we're averaging around two million, still with the intent and the belief that we can get our costs down towards that 1.8 number.

Okay and I'm sorry, on the two million how many days was it taking to drill?

We're averaging 13.3 or four in the second quarter.

John, it's worth point out that our current drilling as we move north from the Vega area is in that portion of our acreage position where we're having to put in road infrastructure, pipeline infrastructure for the first time. So the initial wells will be a little higher than later development wells as we put in the infrastructure cost for the development.

Okay, yeah, because it does look like you're beating your expectations at least on days to drill. What is the kind of current EUR assumptions in the Piceance? I mean, I know the IP rates have been going up at a decent clip.

Yeah.

Well basically, go ahead.

Go ahead, John. Go ahead.

The basics on the EUR map that we have in our presentation materials as we move north the pay column gets considerably thicker and we expect the EUR reserves pro, on a pro-well basis to increase similarly. That is in the Vega area we'll move from the 1.2 bcf per well contour north of 1.5 bcf as we move north into the north Vega and especially into the Buzzard Creek unit itself.

Okay, and then last question I have and then I'll drop off. On Cocklebur Draw, maybe if you could just elaborate, you kind of just mentioned that there's going to be big differences in what you're doing in Greentown versus Cocklebur Draw at least in what your kind of interval that you're going after.

Cocklebur --

Yeah. Sorry, go ahead, John.

The Cocklebur Draw prospect is more analogous to the Hamilton Creek production than EnCana has in the gothic shale, versus the Greentown is a little bit deeper and it's a paradox formation within the paradox salt sequence.

Okay, thanks guys.

Thanks, John.

The next question that we have comes from Robert Lynn [ph] with Simmons and Company.

Robert?

Mr. Lynn?

Sorry, I was on mute. Hopping over to Greentown, just curious as to what you learned from the verticals. How sure are you that this is a natural weight-fractured reservoir?

We have a pretty good understanding based upon Corinell System SMI logging and imaging that all these reservoirs, all these clastics are fractured. One of the reasons that we've done, what took so long if you get to the horizontal drilling is we needed to understand the fracture azimuth and we needed to understand which is the best way to orient these horizontal wells. If you look at other resource plains whether it be the Baken, the Barnett, even the Austin Chalk, they do work vertically but they work much better horizontally. And given the idea we're on a large structure, fracturing is both structural and because these are clastics confined to salt there will be expulsion fractures for in the shales where the hydrocarbons were expulled from the shales. So we're expecting fairly intense fracturing. We think that they are vertically-oriented fracture planes. If you look at the Cane Creek field to the south, while the discovery well is over a million barrels from a vertical well, most of the economic drilling was from short radius horizontal wells that averaged approximately 600 feet in length. We're planning to drill several thousand feet based upon our experience that we've garnered in the Austin Chalk plane. And basically in a plane like this every 100 feet that is drilled horizontally potentially adds additional reservoir and would increase reserves accordingly. So if you look at the resource planes, a lot of them been increased in their productivity and their economics by horizontal drilling. We just needed to understand better what the fracture orientation was before we begin orienting our horizontal wells.

I see. And just to be clear, the horizontal legs are going to be in the place—are you still planning on stimulating this or does this replace a vertical stimulation? And are you –

It'll be a vertical stimulation. What we were trying to overcome was vertical wells and artificial or fracs, was being able to frac into a fracture network. We believe that you can still do that and we did prove that by virtue of some of our completions especially in the O interval. But we were not able to frac into a sufficient—into a large enough area that would equate to a, say a 2,000-foot horizontal well bore. We believe that ultimately we may drain as much as 80 acres with the 2,000-foot well bore and additional cost for the horizontal leg far outweighs the additional cost of a second well within that 80 acre unit that would be required under a vertical program.

And you're not going to stimulate the horizontal leg.

No, if you look at the Cane Creek field those are all, to the best of my knowledge, those are not stimulated and we believe that the vertical fracturing network is extensive. We believe that it's open full of hydrocarbons as evidenced by all the shows that we encounter while drilling through all these formations. And so at this time we're not planning to artificially stimulate the wells. As we garner more information going forward, if we think that we can increase the productivity by fracturing these wells we sure have the experience and the capability of doing so.

Right, and do you plan on running casing in the lateral length or will these be open hole? Can you open hole complete these wells?

Carl, one second, they're just going to be a—we're going to run a pre-drill in the liner in the hole.

It'll be perforated.

Okay.

Correct.

Yeah, and then just one final question, this is obviously a pretty complex area. I mean, do you anticipate any initial problems with horizontals here?

So far, you know, all the experience we have obtained in Austin Chalk plane where the vertical depth is approximately 14,000 feet and with a 6,000 foot lateral we're actually drilling 20,000 foot wells. The target zone is much thicker here in the Cane Creek and in excess of 100 feet in the Cane Creek. And in excess of 85 feet in the O zone relative to a 30-foot zone in Austin Chalk. The pressures are similar. The temperatures are greater in the Austin Chalk and so we believe and we have experienced today relative, I don't want to say ease, but we have had procedurally drilling horizontally in the Cane Creek formation has gone relatively smoothly so far. So we're expecting to be able to drill several thousand feet in these horizontal well bores. The one factor that we need to understand in designing our wells is what faulting might do in a particular interval, but right now we're not seeing a lot of faulting

Okay, and just one final question. What is—why are you running three rigs to drill three horizontals at the same time? What is the thought process behind that?

Well, the primary reason, Robert, was to get results sooner than later. We had a rig, DHS rig that was being moved from Texas up to the Rocky Mountains which became available, and we already had vertical well bores drilled to total depth, so we moved the third rig in and so that we could get as much information as possible in a short period of time. The decision to go forward with three rigs or more rigs will be made after the pipeline becomes operational and we have the results from this activity.

Okay, thanks. That's all I had.

You bet. Thank you.

And the next question we have comes from Michael Bodino with Coker and Palmer

Good morning guys.

Good morning, Michael.

Not to beat a dead horse here, but just want to ask a couple follow-ups on Greentown. I know things have changed relative to the initial plans on drilling from where we were last year going now horizontal. Relative to the reserves, you've got a little production history now and we're still talking 6 bcf. Is that zone-specific to these two zones you're drilling horizontally or is that all the zones behind pipe?

The 6 bcf numbers that we've been talking about previously and continue to talk about now are essentially for the clastic intervals from the O interval down to the bottom of the well bore. So it does not have any reference to the other clastics that continue to remain behind pipe above the O.

And what are your plans ultimately with those zones? I mean, clearly you've tested hydrocarbons in a lot of those zones.

There's –

Michael, we expect that once the pipeline's in and maybe some time next year that there very easily could be a second drilling program in this area focusing on the shallower intervals. What we don't know at this time is would that also be horizontal at specific intervals or would that be vertical completions. But I can envision a program that's roughly 5,000 feet to 8,500 feet and then the main development in the O and the Cane Creek with drilling horizontal legs in reservoirs that are roughly 8,000 to 9,000 feet to 9,000 to 9,500 feet.

Would, when you think about that is there a good rule of thumb that we can think about relative to horizontal wells for each leg? That is certain horizontal length or is there X amount of reserves that you should be able to produce? Or is it too early to come up with a number like that?

Well, it's too early in this particular area but in the Cane Creek field, you know, roughly reserve expectations are roughly half a million barrels or 500,000 barrels in the average horizontal length of those short radius laterals was approximately 600 feet.

Okay, moving to another area, I mean, relative to the gray well that you're getting ready to drill, could you walk us through a little bit and remind us how thick you think the basalt is in that area? And relative to that, obviously that's impacting your 120 to 150 a day drilling program or is that just padded for that?

Well, that does add, you know, that is what we think is a conservative estimate. But based upon drilling in the last several years, you know, that's going to require execution on a drilling procedure that was, I don't want to say perfected, but was used by Shell in the early '80s. So we have drilling charts from those initial wells and we feel like that we understand what some of the drilling challenges are and how to overcome those. Having said that, I think that the amount of days to drill is a pretty good estimate, I think that the cost and the timing that we feel pretty comfortable with. As far as the depth we're projecting to come out of the basalt, around 8,000 feet and it's a 15,000 foot well which will be one of the only wells, if we're successful and in hitting our prognosis, would be one of the only wells in the basin to drill through the Roslyn Formation. So we're projecting a Roslyn Formation of about 4,400, 4,500 feet in thickness and we're projecting this well to go through the Roslyn Formation into some of the lower intervals which also have significant shows in the active 133 well.

Perfect, I'll get back in the queue. Thanks.

Thanks, Michael.

The next question comes from Greg Brody with JP Morgan.

Hey guys.

Morning, Greg.

Hey, I'm just trying to get a sense of the size of the Midway Loop acreage. I was just looking through your 10-K and you have 21,400 as of year end and then your proof reserved were 24 B's. Any change in that as a result of your modified reserve number?

Not significant reserve number changes. We have essentially been drilling proofed undeveloped locations and we have not expanded on the acreage position there.

Okay, and then just in terms of the thought process behind selling it, the potential sale of these assets. Could you provide a little bit more color around that?

Yeah, we're, I mean the bottom line answer is that we're running out of additional potential here that would have a meaningful impact on the company going forward. We think we're better suited to spend CapEx in there. There are other areas like the Paradox Basin and also to have our human resources working those areas more diligently as well.

Okay, and the shift in the CapEx. I was trying to get a sense of what your CapEx was for the quarter. I'm kind of backing into what your berm was, but you actually haven't—do you have an actual number?

Yeah, the drilling CapEx for the quarter was approximately $86 million which is in line for what we had issued for the year.

Let me just look at mine. No, no, in terms of liquidity targets on your last call you talked about how Tracinda was focused on making sure you had a couple hundred million dollars of liquidity given the credit environment that we were in. I would say that that's improved a fair amount, especially for energy investors. Is that still a target you have in mind or is that changed a little bit?

Well we, no, that has not changed. I think the one thing that I would say that has changed is where the liquidity will come from. As of right now we have recently gone through our bank redetermination efforts in mid-April and we expect to have fairly significant increase in our borrowing base capacity. We have spent a lot of time reviewing the other financing opportunities that do exist out there that would essentially allow us to use the $300 million of cash that we have set aside for the EnCana transaction. But when you look at the cost of those types of financing activities versus the cost of our borrowing base credit facility, we think it's most prudent at this point in time to rely on that for available liquidity as we go forward. We also, as mentioned earlier, are obviously experiencing pretty significant increase in cash flows as well.

That's helpful, then just a detailed question on the Piceance gas processing facility?

Yes.

Could you just describe what actually happened there and then just do you have any further concerns about that?

Yeah, well in a general sense we do not have any concerns going forward. We had significant discussion with the operator of the pipeline system and as you might expect, and I'll turn it over to Carl to let you, or have him identify what occurred in the month of March.

In the month of March they were doing a plant expansion and as sometimes is the case during plant expansions unforeseen events arise from the start up of new equipment that delayed the resumed function of the plant longer than expected. Some of that was electrical and some of it was reliability with compressors. We believe those have been resolved and shouldn't be a forward issue.

Who was the operator with that?

The operator is DCP Midstream.

That's all I have. Thank you very much.

And the next question we have comes from Ron Sanchez with Spencer Edwards.

Hello gentlemen. I just wondered regarding your Austin Chalk in the Midway Loop there, you announced that you're completing this lateral portion that you redrilled. What are the production numbers on that going to look like and what is your working interest and what did it cost?

Ron, the expectation is that it's going to be a strong well. It's in the immediate area of our better wells that we've drilled down here. We certainly experienced the significant shows that you expect from the better wells while drilling down here. The individual well cost has gone up dramatically as you might expect with regard to the requirement to essentially redrill the entire lateral. Having said that and even with the increased cost of the well, we still expect the well to be very economic individually. I think that answers your questions, doesn't it?

Okay, well, just in general, what was your—why are you trying to sell this field or this decision or what's your reasoning for pulling out of this area?

The primary reason as mentioned before is that we're essentially out of running room that would have a meaningful impact on the company on a go forward basis. We're out of leasehold.

Okay, thank you sir.

Thank you.

And the next question we have comes from Michael Bodino with Coker and Palmer.

Hey Roger, just a couple of follow-ups. Relative to the Utah overthrust, I know that the Parowan well you lost some pay in the Twin Creeks limestone. Industry rumor suggests that in the covenant fill there's some production from the Twin Creeks. Do you have any insight to what the Twin Creeks can produce? I understand it's fracture launched and reservoired so it may vary, but is there anything you can provide on that?

Well, that—we can't with regard to the production from the covenant field, but what we can steer you to is other overthrust fields that produce in the Wyoming, Utah overthrust belt that were discovered 25, 30 years ago. There are numerous fields in that overthrust area that do produce meaningful recoverable amounts from the Twin Creek lime above the Navajo in that particular area as well. So, John, do you have any additional comments in that regard?

Roger, you're right. To expand upon that the Wyoming overthrust belt which is upwards of ultimately a two billion barrel provenance, approximately 25 to 33% of the production was derived from the Navajo Formation so it is a meaningful –

The Twin Creek Formation.

Excuse me, the Twin Creek. It is a fracture reservoir and you really can't give and I sense for pro-oil reserves, unfortunately because it is fractured and hard to determine the characteristics based on logs. It requires production history. But it was a meaningful contributor in the Wyoming Utah overthrust belt.

Okay.

We have heard the similar rumors about the Twin Creek potentially being a contribution in the Central Utah Hingeline area.

And, you know, given the recent discovery of the Providence Field and now there's a couple different field discoveries in that Utah overthrust, has there been any additional work on getting through the size and make arrow macro data that you have? Is there anything that you can elaborate on relative to high grading prospects or?

You know, no, I would say though it is really important is the Parowan feature was one of our southernmost structures and we did evidence the Mississippi oil that tells us that a large percentage if not all o four prospects could be in the fairway of worldwide migration and therefore could be potentially hydrocarbon traps. As mentioned before, overthrust fields or overthrust regions take on the appearance of a string of pearls where they're in an elongated pattern along a leading edge thrust fault that can be seen in the Canadian overthrust belt and the Utah Wyoming overthrust belt. And now you have a second discovery in the Central Utah Hingeline belt that is along that leading edge thrust where all of our structure are also located. It's beginning to have the appearance of the string of pearls, but time will tell to see how many fields are ultimately discovered in the Central Utah Hingeline area. But it does give us a lot of confidence and a lot of excitement going forward that at least a large portion of our acreage is in the right area.

Okay, and my last question, given the acquisition of the EnCana acreage and some other fill-in acreage around Vega plus the aggressive drilling program around the Paradox and Piceance Basin, any thoughts about providing interim reserve reports during the year?

Michael, it's Roger. I, you know, we referenced the quarter end numbers on this press release and I think that it may be reasonable to expect that same thing on a go forward basis.

All right, thank you.

And Mr. Parker, gentlemen, we're showing no further questions at this time.

Okay, very good. Well, thank you for joining us for our first quarter conference call and we'll look forward to the next one. Thank you.