Hello, and welcome to the Delta Petroleum's second quarter earnings conference and webcast. All participants will be in listen-only mode. There will be an opportunity for you to ask questions at the end of today's presentation. (Operator instructions) Please note, this conference is being recorded. Now, I would like to turn the conference over to Brock Richardson, Vice President of Corporate Developments and Investor Relations. Mr. Richardson, you may now begin.

Thank you and good morning. Thank you for joining us today. On the conference call from Delta are Roger Parker, the Chairman and CEO; John Walace, President and COO; Kevin Nanke, Treasurer and CFO; and Ted Freedman, Executive Vice President and General Counsel. 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 Harbor's credited 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 permit oil and gas companies in their filings with the SEC to disclose only approved reserves that the company has demonstrated by actual production or conclusive formation test to be economically and legally produceable under existing economic and operating conditions. Delta may use certain terms in this conference call but 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 10-K for fiscal year-end December 31, 2007 as updated by subsequent periodic and current reports on forms 10-Q and 8-K respectively. With that, I'll turn the conference call over to Mr. Roger Parker.

Good morning. Thank you for joining us to our second quarter 2008 earnings conference call. We are pleased to provide you with very good results from the second quarter. We had a number of items that represent significant year-over-year growth and sequential growth quarter-to-quarter. On a year-over-year basis presented for the quarter, revenue was up 81% to $69.5 million, discretionary cash flow was up 127% to $40.7 million. EBITDAX was up 101% to $39.5 million and production from continuing operation was up 75%. Importantly, second quarter production was up 16% over first quarter of 2008. And unaudited proved reserves were up 8% over the first quarter of 2008 as well and may now stand at approximately 649 Bcf equivalents which is also a 73% increase since year-end 2007. Our larger scale activity especially in the Piceance Basin is beginning to have a very positive effect on the cost side as well. As an example, DD&A was down $0.71 per Mcf equivalent from the prior year quarters. After adjusting for non cash and realized derivative losses, we had earnings of $4.7 million or $0.04 per diluted share. Operationally, I will some general comments about our big impact areas and then open it up to questions-and-answers. In the Piceance Basin, things are going well and as expected. Unaudited proved reserves are growing, production is growing steadily, drilling time is getting much better, we've referenced in the press release that the average number of days to drill in the first quarter of '08 was 15 days, we referenced that in the average for the second quarter was 13 days, and I can tell you that the average for the month of July was 11 days. We also have significant additional pipeline capacity that is underway to accommodate the larger growth that is expected…

Thank you, sir. (Operator instructions) Our first question comes from the Michael Bodino of Coker & Palmer. Please go ahead.

Good morning, guys.

Good morning, Michael.

Just couple of follow-up questions. I know you've had a reduction of drilling base in the Piceance Basin, how does that impact your allocation of rigs going forward? Are you still going to ramp up the rig count there as previously described?

We reference in the press release that it is still our intention to go to eight rigs by early '09 – first quarter of '09. What we're doing right at the moment is trying to appropriately manage the number of rigs in operation between now and when additional pipeline capacity will be available. That additional pipeline capacity, also referenced, will be in place and should be available essentially right after year-end. So, without saying exactly when we will put additional rigs in operation, we still do intend on going to eight as we enter 2009.

So, do you think, given the reduction in drilling basin in additional rigs that drilling 200 wells in the Piceance Basin next year is achievable?

Yes. I think it's very achievable.

Okay. On the overthrust. I know this is your last earning well on your 3-well commendment [ph] there, what happens going forward if this is un-success well? Do you continue to prospect or is this last one in the area depending on how Parowan test?

No. I think, we've got a lot of hope for the entire area. And one of the things that I would point out is that the operation that Wolverine and Occidental Petroleum have going to the Northwest which is recently experienced and additional discovery, experienced a number of dry holes on separate structures after the Covenant field was discovered and before the Providence discovery was announced. So, we think that we obtained a very key piece of information when we drilled the Parowan well. That piece of information was the existence of Mississippi in oil all the way down on the very Southern end of our leasehold position and that gives us a significant amount of continuing hope and interest in all of the leasehold that we have between the Parowan prospect and the Covenant Oil Field. So, regardless of the outcome on this next structure that we will drill, we will still have significant amount of interest in the project itself.

On this Beaver prospect, are you targeting just the Navajo or are you going deeper on this well also?

Just the Navajo. Mike, it's John. Now that and the Twin Creek. The Twin Creek as we've reference in the past were dig where we did Mississippi oil in the Parowan feature is also known that the Twin Creek is productive at the Covenant field. So, we will – we're looking at both of those formations.

And the Parowan is a fractured limestone reservoir, correct? (inaudible)

Twin Creek.

The Twin Creek.

Twin Creek. I'm sorry. My last question – I let somebody else jump on here – in the year, you mentioned your reserves that on the Piceance Basin 515 Bs I think you disclosed the unaudited reserves to be six – whatever the number is. 603?

649.

649 (inaudible) down. The incremental 134, can you give us a general breakdown of where those exist? How much were in Gulf Coast, how much are in the other Rockies?

Yes. Hang on. I'll give it to you on essentially a percentage basis. No, he's looking for incremental. Other Rockies is approximately 60 Bcf, so a little bit less than half of the incremental, and then the balance of that would be in Gulf Coast, Texas.

Other Rockies would be primarily the DJ Basin, we have a pretty consistent going program, and it had quite a bit of success.

Alright guys. Well, I'll jump back on and let somebody else ask some questions.

Thanks, Michael.

Thanks, guys.

Thank you. Our next question comes from Tom Gardner of Simmons & Co. Please go ahead.

Good morning, guys.

Good morning, Tom.

Hey, I was just – referring to the Piceance, what the strip price would cost you to re-think ramping up to 8 rigs into play next year?

I think if you had a strip price that approached $6 NYMEX, you'd certainly have to reconsider accelerating or continuing to accelerate activity. That will also be a function of what the differential is, but obviously the differential tightens the lower NYMEX goes. The other part of it is, I think many of us in the industry have the attitude of– there's a little bit of a self-fulfilling situation here, and that is that if you get down below $7 NYMEX for any sort of extended period of time, drilling activity absolutely goes lower and it does not take long for available supply to go lower as well. But if you did get into it, an environment where you had $6 NYMEX and you expected it to occur for an extended period you would definitely rethink the amount of acceleration that you would undertake.

Do you all feel like you have sufficient off-take capacity to handle that incremental volume going forward?

Yes. This is new pipeline project in the area is going to be more than sufficient for us to market our development plans for the Vega area.

I think it's very important to point out that this 600 million a day pipeline that is beginning to be constructed as we speak is going to be servicing essentially only drilling activity in the Collbran Valley of the Piceance Basin, and as we stand today, the primary operating activity in that particular area is being done by Delta Petroleum and Plains Exploration. So, 600 million a day of capacity is being created essentially and primarily for our properties and their properties. So that should give an indication as to how much growth we expect out here.

Thank you, that's helpful. Jumping over to the Paradox. You mentioned the Greentown Federal 26-43D in carrying some challenges there drilling this O zone. –Well, first of all, what do you think the issues are there with the obstruction and casing, and what do you do to overcome those issues?

Well, let me make a quick comment before the discussion about the “O” zone. The one thing we did not have was any problem drilling the “O” zone. The drilling went very well and the shows were quite substantial. The problem that we have at the moment is inside the wellbore which is unfortunate but it essentially doesn't have anything to do with the play itself. Having said that, I'll let somebody try and explain what our problem is.

In order to cement off the salt section that makes up the curve portion of the wellbore, we ran a packer assembly into the liner effectively gets the very top of the “O” zone but not really into it. That packer assembly is made up of aluminum and theoretically it should be much easier to drill up with a mill than the steel casing surrounding this packer assembly. So, it's normally takes just a few hours to drill up this aluminous assembly and then you move on down the hole and this liner is unperforated. Just a liner in the hole, submitted in the hole. Unfortunately, what's happened in this particular case and is very, very rare but the coil tubing mill that was drilling up the aluminum assembly, at some point, cut into our or wore a hole into the liner and was diverted into the formation itself, in the very top of the formation. And right now, our difficulty is getting back into that liner, because every time we go in the hole, all the tools are diverted to this hole in the liner. So, plans are to continue to work through this and to finish building up the small amount of remaining aluminum that we need to in the packer assembly because we retrieve most of it. And then, go down to the bottom of the liner and begin perforating the wellbore. The drilling portion has been easy. As you can see how far we drilled these wells, whether this is Cane Creek or the “O” zone. There are long laterals and if put that in perspective, the laterals in the Cane Creek Field of the south are much shorter. Our guys have done a very good job on drilling side of achieving significant link in the “O” zone. We just have got to get pass this problem, which is abnormal, this packer assembly. The other two wells that we drilled that we're getting ready to frac, we elected not to run this packer assembly and not to submit that portion of the wellbore. And, as such, we don't expect any problems going forward.

Great. Just one last question I'll hop off. In the Colombia River Basin, are you still actively seeking a partner?

We have ongoing discussions with a number of different companies on a number of fronts but not really prepared to discuss anything.

Okay. Got you. Thank, guys.

Thank you. Our next question comes from the John Freeman of Raymond James. Please go ahead.

Hi, guys.

Morning, John.

First question on just kind of the basis differentials. If I'm looking at the hedges that you all put on, at least based on the fact there's only one that was done at the CIG, would I read that to believe that you all think the basis differential contract quite a bit from where it is next year?

Well, that and, John, I think we told you in the past, especially what this new pipeline is up and operational, we really would like to manage our gas especially at the Piceance Basin by virtue of firm transportation. And when you pay a fixed rate to get to a market that theoretically sells for very close to NYMEX flat. And that really is our goal, we need to get enough volume to be able to effectively manage that firm transportation, but that is the rationale behind not hedging us, and to significantly in to '09 with CIG and using NYMEX only because we want to pay firm transportation to get to a NYMEX flat market. Firm transportation is any worth $1.10 to roughly as this new project as high as $1.40 – $1.45.

Okay. And then moving on to Columbia River, I just want to verify that the depth that was written a couple of the articles up in Washington is right. What depth were you at when you had the fire?

It's roughly 2,500 feet.

Okay. And then, at least as far as you all are aware on the wells that were drilled previously by EnCana did any of those encounter natural gas in the basalt?

No. That's one of the things that sets up this prospect in the Southern area and the space in there are numerous gas seeps that are found in local water wells, used by farmers in– for irrigation purposes. There are farms and ranches in this part of the world that actually use the natural gas, through gas seeps for domestic use. The only other area in the Basin that had significant gas seeps like this is in and around the Yakima 133, which is probably the thickest gas column drilled to date in the Columbian River Basin and it's not necessarily indicative of the gas accumulations, but it does mean gas is in the system.

Okay. And then, just as you were drilling through the basalt did you have any of the issues that, I mean, obviously EnCana had a whole host of issues trying to drill through it and using two rigs and everything else? Did you all have any issues before then?

No. No. We were employing some technology that our DHS guys have used in geothermal drilling in California and Nevada and that particular drilling procedure was proven to be extremely effective and very fast in drilling through the basalt section. Having said that, the fire has slowed us down and we'll be back to drilling here the next day or so.

Remember too, John, that in drilling this Columbia River basin well, what is the diameter of the surface hole (inaudible)? 30 plus inches isn't it? The whole diameter is 30 plus inches. So, until you set your surface casings, so, the upper portion of the well can actually be and is expected to be some of the slower drilling that you experienced well while you're drilling out here and we certainly noted that once we got passed surface casing, the penetration rate picked up quite a bit.

Okay. And then, just last question. I'll hang on – I'll jump off. On the Paradox – just based on the fact, your initial vertical well, the vast majority that flow rate was coming from the O interval anyway and just based on, I guess, what you all seem to formed the Cane Creek. I understand you saying that you believe the Cane Creek is perspective on half the acres but at least in the near term loan development kind of basis. Is it safe to say you're going to bail on doing the dual laterals and look at maybe just doing a longer single lateral into the o?

Yes. But we are going to focus on the O zone.

Alright. Thanks guys.

Okay.

Thanks, John.

Thank you. Our next question comes from David Tameron of Wachovia. Please go ahead.

Good morning.

Good morning, Dave.

Couple of question. Can you give what your CapEx was for the quarter? Anybody may have said that and maybe I missed it.

Yes. CapEx for the quarter was $108 million.

Okay. And what your outlook for the second half of the year? (inaudible)

Should be approximately $200 million. We should come in maybe slightly ahead of the original guidance which was $350 to $370. And by slightly, I mean slightly over probably more in the order of 380 million.

Alright.

That is – David, that is drilling CapEx.

Yes, yes. Okay. When I look at the Piceance, what's – when you start talking about it, if assuming that things works out as plan, eight rig program in 2009, what type of production growth you think you could put up with the Piceance alone next year?

Pretty dramatic. I guess, what I would refer back to you, we haven't really guided toward numbers for 2009, so I'm going to stay away from that, but what I'll do is refer back to what's occurred over the last 12 months. 12 months ago, we only had two rigs running full time in the Vega area. And we didn't go to four rigs full time until early in the first quarter of this year. So, between mid-year '07 and mid-year '08, we grew production by close to almost 40 million a day. And that would be with an average, if you look at four rigs per half the year and two rigs for half the year, that would be with an average of three rigs. So, I think it's very reasonable to assume that you would have pretty substantial production growth in '09 especially with the available pipeline capacity and effectively more pipeline capacity than we'll need.

Okay. And for the second half of the year, you're still going to stay around the same level, (inaudible) 60 million at gross?

Yes, we're going to be restricted on pipeline growth or production growth due to pipeline capacity between now and the end of the year.

Okay. Alright. And then one more – one more question. On the discontinued ops, what's in that line? Was that still the midway?

Yes. That's primarily your Austin Chalk property that we've held for sale.

Okay. Any progress on that front?

We have the data room that will be opening the second week of September and then expected closing during the fourth quarter.

Alright. Thanks.

You got it. Thanks.

Thank you. Our next question comes from Larry Busnardo of Tristone Capital. Please go ahead.

Hey, good morning.

Morning, Larry.

Just on the Piceance first, just on the production. The 46 million a day, that's a net number correct?

That is correct. Yes, and it should say net number in the press release.

And then you gross up by what? 80%? Is that DNRI?

Yes, approximately and it's – well, it varies, but I think it's like 80.5.

So effective by year-over-year you maxed out at that rate or fairly close to it correct?

We have some growth that we might be able to achieve over the next 60 days but it's not going to be significant.

The new pipeline that you're talking about or the new one that's going to be coming out early next year, does that have access to regional take away or what pipeline is that going to tie into?

Yes, that will get us to the White River hub and there's numerous pipelines, interstate pipelines, some of there that you can sell into.

Go east, west?

You can go east, west, southwest. Yes, you can go east, or west.

Okay. Do you have a firm take-away capacity coming out of the region.

We're negotiating that right now.

We do have some and we also will have some related to our transaction within EnCana we announced earlier this year.

Okay, and then a couple of follow-ups on Greentown. I guess just looking at the Cane Creek, and how are you going to focus on the O zone here going-forward. What are your thoughts on the Cane Creek and when that may be tested again on the Eastern part of the anchorage?

Well, right now, Larry, we're going to focus on the O zone. I would say we don't have any immediate plans to test the Cane Creek, but I will tell you that what gives us confidence to know that we think that it will work is if you look the big flat, bar of flats fields which are King Creek fields to the Southeast. In those fields, the Eastern side is where you find the big wells, and the Western side is the very marginal wells, and so that's why we think that the Eastern side is going to be more appealing, but we won't get to that until we slipped off the top of the anticline [ph] in our O zone development and then we'll look at the Cane Creek. So it will be a little while. I will remind that in the 32, 42 that we completed above the O zone in several intervals and found very significant oil rates and that is something that also will focus somewhere down the road but you could– for the next time being, for the next 12 to 18 months, we'll be focusing on the O zone almost exclusively.

Larry, the other positive here is that we do have an operational pipeline now and as a result, we will be focusing our attention on getting production up from these areas as best and as quick as we can. We think the best way to do that is to focus our attention on the ozone.

Okay. I know, you've done quite a bit a science to-date obviously on these wells that you drilled. Has your thoughts at all changed from a geologic standpoint, or do you view it more as being a mechanical or more completion issues than anything else?

Larry, it's more mechanical completion. The job you really hasn't changed. In fact, every well we drill in the O zone, we see that over-pressured gas. That's what gives us a lot of comfort in believing that this going to be a large field, at least in the O zone. So it's more on the completion, not really in the completion side, because I think our – the Genesis we've experienced with our frac design has proven at least (inaudible) 11 that we're very effective with this new frac design. What we really need to do is perfect the drilling and the running of the pipe in these wells and again, that the major challenges is salt [ph]. So, that's kind of what we're after.

Do you have 3D over this area?

No, there is not 3D over the area and salt is very hard to see geophysically.

Okay. So, is it 2D or what type of data do you go off of?

There's 2D in the area.

Okay. Alright. Okay. I think, that's it for me. Thanks.

Thanks, Larry.

Thank you. Our next question comes from Greg Brody of JP Morgan. Please go ahead.

Good morning, guys.

Good morning, Greg.

Just a couple of follow up questions with respect for CapEx for the year, how much is non-drilling CapEx? How much additional CapEx will it be for the full year?

Well, if the non-drilling CapEx that we'll have for the year is essentially already been experienced, and the largest items were in the form of the acquisition that we did with EnCana and then also the cost of building and completing the Paradox pipeline. The combination between those two is approximately $425 million but those costs have already been incurred. So that will be the line share of CapEx for the year, non-drilling CapEx for the year.

That's helpful. And then, do you mind providing update on the sale process of the mid-way loop assets?

Sure. We engaged Tristone to represent us in the sale of that asset. They are currently preparing for the opening of the data room, the second week of September and we expect that we would probably end up with a closing sometime in the fourth quarter.

Fourth quarter. And final question. Are you seeing any opportunities for additional acreage acquisitions in your core areas?

Well, in a general sense the answer is we're always looking at that. We do see some other opportunities, we will be paying attention to it. And when meaningful situation come about, we will try and react.

Sure. Thank you very much.

You bet. Thank you.

Thank you. We show no further questions at this time, I'd like to turn the conference back over to Mr. Parker for any closing remark.

Okay. Thank you very much. We appreciate your joining us today for our conference call and we look forward to the next one. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.