Hello and welcome to the Delta Petroleum Third Quarter Earnings Conference and Webcast. All participants will be in a listen-only mode. There will be an opportunity for you to ask questions at the ends the presentation. An operator will give you instructions at that time. (Operator Instructions) Please note this conference is being recorded. Now I would like to turn the conference over to Broc Richardson. Sir, you may begin.

Thank you. Good morning and thanks everyone for joining us today on the call. On the conference call from Delta are Roger Parker, the Chairman and CEO; John Wallace, President and COO; Kevin Nanke, the Treasurer and Chief Financial Officer; Ted Freedman, Executive Vice President and General Counsel; and Carl Lakey, Senior Vice President of Operations. Before we begin, I need to read the forward-looking statements disclosure. This conference call will include projections and other forward-looking statements with in the meaning of the Federal Securities Laws and are intended to be covered by the Safe Harbor's credited there by. 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 oil and gas companies in their filings with the SEC to disclose only true reserves that the company has demonstrated by actual production, will conclude their formation test to be economically legally perusable under existing economic and operated conditions. Delta may use certain terms in the conference call that the SEC's guidelines strictly prohibit us from including in the 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 will turn the call over to Mr. Roger Parker.

Thank you, Broc. Good morning and thank you for joining us for our third quarter conference call. As you have heard from many companies, especially energy companies, the significant and rapid decline in oil and gas prices have caused us to act in an expeditious manner to be fiscally responsible, and to ensure that Delta Petroleum is prudently situated to weather the current environment in the financial markets. With revenue streams cut in half over a 60 day period and credit markets being all but closed, immediate and definitive action was necessary and important. This has obviously had an impact on drilling activity, in all but our lowest risk and predictable areas, which are basically located in the Piceance Basin. It is not a reflection of the potential of areas like the Paradox Basin; rather, it is an acknowledgement that this company will do everything possible to maintain adequate liquidity and to evidence real value of assets for our shareholders. In fact, I would like to note and emphasize many of the very important metrics that have been achieved and here to for used to be the drivers for an E&P company, prior to the worldwide fallout of the financial markets. Number one, we reported that unaudited proven reserve estimates at September 30, 2008 were 657 Bcf equivalent; which represent as 75% increase over year-end 2007. Secondly, we referenced that we experienced a 64% increase in quarter-over-quarter production growth. Number three, EBITDAX increased 98% to approximately $43 million for the quarter. These represent what are supposed to be… what we are supposed to be doing and have been able to accomplish, and the growth should not be ignored because ultimately it will matter again. In addition, announcements were made last week which are supportive of value growth, and should be interpreted… and should excuse me should not be interpreted as tantamount to survivor moods. One of the announcements that we made was that our banks just this week conclude a new credit facility, with a meaningful increase in the borrowing base, evidencing good property valuation even in a declining commodity price environment, and which is also suggestive of good liquidity. We also announced an effort to explore joint venture alternatives for our Piceance Basin asset. This is intended to be a value unlock, as it relates to current company valuations along with prudent balance sheet management. We will only transact or it is the intention of the company that we will only transact on an NAV positive basis. With that, I am going to turn it over to Kevin Nanke, the Chief Financial Officer to reference a few of the financial metrics from the quarter, and then we'll turn it over to question and answers.

Thank you, Roger. Net income for the quarter was $49.8 million or $0.48 per diluted share, compared to a net loss of $5 million or an $0.08 loss per diluted share in the third quarter of '07. Oil and gas sales from continuing operations were $49 million, compared to $23.1 million in the third 2007. Continuing operations, exclude our Midway Loop Texas asset, which is held for sale and generated over $9 million of cash flow in the quarter. We had realized oil prices of $107.76 and realized gas prices of $5.97, an increase of 53% and 67% for the third quarter… from the third quarter of '07 respectively. Our net income was materially impacted by a $54.8 million unrealized gain on derivative instruments relating to the significant decline in oil and gas prices at the end of the quarter, 11.3 realized gain on derivative instruments from the sale of certain derivative contracts on September 30th, and $8.1 million in dry hole expense during the quarter. Over production for the quarter was 6.6 Bcfe, an increase of 44% compared to the third quarter of '07, which was at the upper end of our guidance. Additionally we estimate 0.22 Bcfe in production was lost attributable to hurricanes Ike and Gustav. These operating expenses from continuing operations per Mcfe the three months ended September 30 decreased to $1.26 per annum, from a $1.56 per annum in the third quarter of '07. The average LOE per Mcfe decreased due to a shift in production from higher cost, Gulf Coast properties to lower cost Rockies properties. The depletion rate decreased… also increased $4. 28 per Mcfe for the three months from $4.35 per annum in the early year period. This decrease reflects increased reserve additions and lower cost per well in the Piceance Basin capital development program, along with a higher mix from Rocky Mountain properties. With that I will turn it back over to Roger.

Thank you, Kevin. Operator, we will go ahead and open the call up to questions and answers at this time. Thank you.

(Operator Instructions). Our first question is from Tom Gardner from Simmons and company. Please go ahead.

Concerning the capital spending, can you give us an idea of what it was for 3Q and what it might be for full year '08? Perhaps an idea of what your growth guidance might be, given the reductions in '09.

Third quarter was well kept 120.

120 drilling.

It was 120, yes.

And fourth quarter?

Fourth quarter is expected to reduce by approximately 25%. Tom, many of the implemented drilling reductions were initiated in early October, and obviously wells being drilled were drilled to total depth before rig release. So, about half of the drilling rigs for half of the quarter will be released. With regard to I think, the other part of your question was, growth for 2009, is that correct?

Yes.

Growth for 2009, currently we are expecting that we will experience production growth based on the CapEx guidance we put out that will range from the 10% to 15% growth over 208 levels.

Is there any incremental information on the tender offer being reviewed by the Board?

Not at this time. Although, the Board is in the process of reacting and there will be more information coming soon.

Well I think that takes me to my two. I will get back in the queue.

Okay. Thank you, Tom.

Your next question is from [Joe Wagnor] of Tristone Capital. Please go ahead.

Good morning, I was just wondering if you could explain your strategy behind the unwinding of your hedges heading in to what could be a challenging price environment in the Rockies next year.

Yes, absolutely. Let me tell you that we considered that for a number of reasons. I will take you back to the point in time in which we unwound those. We began unwinding on September 30th, the day of September 30th and continued over the course of the next couple of weeks. One of the concerns was for the unknowns related to everything that was going on with all of the banks and the markets, and having an unwillingness to try and determine whether or not there would be counter party risk once the hedges ultimately came into play. That was not the only reason, but it was one many reasons. The other reasons were, we were in a position where we were able to experience a significant cash gain related to that effort. We booked approximately $20.5 million of cash gain by doing so. Lastly, we were paying very close attention to what had become significant number of large capital expenditure reductions that had been announced by numerous companies, related to significantly decline in oil and gas prices. We were and still are of the opinion that with the significant number of rigs that are being released at this point in time and will continue to be released over the next three to six months, that there will be an impact on supply ultimately that will begin to be realized probably in the 2009 time period. We think we will have the affect of having to stabilize especially natural gas prices a little bit better as a result. So, the available capital today, the concern for wanting to make sure that there didn't need to be a concern for any sort of counter party risk, and also the belief that prices will likely at least stabilize if not get a little bit better with supply disruptions, ultimately led to the decisions to do what we did.

Okay, that’s helpful. It looks like the (inaudible) position is growing, finest [types] of rig or well soon, and just talk about your plans for '09, what the lease terms might look like on some of that new acreage and what percentage of the CapEx could be allocated to that effort.

Yes, if you look at the press release, what we've announced is that we will spread an initial well in early 2009. The plans at this moment in time are literally to drill a single well and get a single well result before making any further capital decisions related to the Haynesville. We do believe that we put together a very good acreage position in the better parts of the play. We were very cautious as we went into leasehold acquisition, and did not rush in to large and expensive acreage acquisitions when everything was moving as quickly as it was in the April through July time frame. The end result is that we have a very good across the board average per acre cost for the play, and it's our intention that we believe that if we are patient on a go forward basis, we will be able to obtain an additional acreage at very reasonable prices, but the immediate intent is to drill a well, and get a result and then make further decisions based on that.

Last part of my question in terms of the lease terms. What sort of requirements do you have in drilling commitments?

We only have one drilling requirement forthcoming and that is, that will be taking care of with the well we spud in early 2009. Other than that, we have lease terms that are on the order of three to five years for the remaining leasehold.

It's worth noting that a lot of this leasehold that we are talking about is HBP.

Thank you.

Our next question is from [David Hakkinen] of Tudor, Pickering, Holt. Please go ahead.

Good morning, just a question as you think about Greentown and expected 2 Bcf for the [well]. Remind me what you spent on that well?

The best way to answer that would be to tell you what we spent on the most recently drilled well, because clearly, we have been in a process of doing a lot of work on a lot of different wells in a lot of different ways. Most representative expectation would be based on the Federal 11-24 that we just drilled. I will let Carl Lakey actually make a few comments in that regards.

Drilled well caused a suspending point with casing included it was $4.5 million and we expect completed well cost to be 5.5 on that one, once we've all the available plastics within the well. We think there is room to be able to work that downward a little bit, perhaps another $500,000, another 10%.

David, this is John. Let me throw in here. As part of this fiscal restraint and not drilling in the Greentown area, we are focusing our efforts on the completion activities from these [classic] intervals (inaudible). They are very meaningful; we've tested them in both of the first two initial wells and had rates as high as 1.5 million a day and 600 barrels of oil from some of these upper zones. Additional wells drilled in the area several years ago had [drill] and test rates in these upper intervals as high as 5.5 million a day. So we know they are hydrocarbon bearing. We are just going to take the time and effort while we have some time to focus our efforts on these uphold zones and co-mingle production from what we think hopefully will be several different intervals. That would include the 28-11. So we expect to have incremental reserve from uphold classics that would add to the 2 Bcf.

So you don't expect to take impairments to that well or write that one up. Okay. Then as you think about Piceance Basin program that you have, and where basis is and kind of the extension of (inaudible) delays, what are you building in for basis for 2009 now in to the Piceance economics.

Well what we note and continuously pay attention to is certainly what you can hedge the CIG differential at. If we were to do so, which of course we have not, you could hedge the basis differential at approximately 220 per Mcf across the board if you are willing to do so. We do use that when we prepare budgets and come up with capital budgets for the following year and we have looked very closely at that.

And at that differential what are your rates of return on the wells.

18% to 21%.

At that differential with current NYMEX price environment you are still in the upper teens.

Okay.

And let's say we are looking at that firm sales going forward especially with the completion of this new pipeline, and our goal is to via firm sales to insulate ourselves from the Rocky Mountain differential down the road.

That's all I had, thanks.

Thanks.

The next question is from David Tameron from Wachovia. Please go ahead.

Couple of quick questions. Kevin, could you walk us through the 150 and 175. How you get to that number for 2009, including what deck you are using?

Well David, this is Roger. What we are using is effectively the current strip. And the CapEx budget will be largely related to continuing drilling operation in the Piceance Basin. As we've referenced in the press release, a continuing and fairly significant amount of expected completion activities and attempts in the Paradox Basin and then also obviously by virtue of our transaction in the Columbia River Basin, the expectation that we will have ongoing drilling activity up there throughout the year. And then over and above those activities, there will be one-off wells drilled in a couple of different areas like Haynesville likely in the Utah over thrust and result in individual wells in those areas will dictate whether there is additional capital allocated during the year.

Okay. If I look at asset sales, how much of that 150 to 175 is asset sales and then …I know as asset sales picked up on the… the assets held for sale and the balance sheet picked up by 20 million.

Yes. And it ticked up by 20 million related to additional wells being drilled in the interim.

Okay.

And I think the best thing to do would just be to reference the balance sheet with regard to that number at this time.

Okay. And the 150… so, of the 150, 175, to clarify, 86 of that, about half of that (inaudible) to asset sales?

That's correct.

Our next question is from Tom Gardner of Simmons and company.

Yes, Tom, I guess we could have kept you on.

No worries. Just one last question. I was going through Husky's 10-Q and noticed that they had acquired 50% working interest in 844 acres and that's for $100 an acre. Just wondering if you could tell us what is meant on this?

Well, sure. It's a transaction that we previously announced that we are in a relationship that we are very excited to have. We have a large company with very substantial balance sheet that believes in the potential for the Columbia River Basin as we do. We have a stated intention of drilling at least three wells in the Basin, one of which is the well that we are currently on, the Gray 31-23. I think that one of the things that we are certainly interested in trying to do is obviously establish that there is gas in the basin and gas in economical amounts, and we will be looking at all parts of the basin, especially parts of the basin that have previously been drilled and evidenced good gas flows in the past. So, it's a relationship as I mentioned that we are excited with about. It does not change essentially the Delta net acre position. We as part… or immediately prior to the transaction that you are referencing, we acquired the remaining leasehold ownership of EnCana. As such, by the time we close the other transaction, we ended up with approximately the same number of net acres that we had prior to both of those transactions.

The next question is from [John Margolis] of Spectra, please go ahead.

My question was answered already. Thank you.

Okay. Thank you.

The next question is from [Joe Wagnor] of Tristone Capital.

Okay, Kev, just wonder if you can fill us in on the plans or I guess the destination of the two or three rig that you were running down in Greentown (inaudible).

Yeah, that's a good question. Let me make a comment with regard to the DHS rigs. They were DHS and they are DHS rigs. DHS has done a very good job of finding additional work for these rigs in what is clearly a tough environment. So at this point in time rigs released by Delta are going to work for others. When possible, the rigs will try to go to work for other operators in as close proximity as possible to the areas where they have been released. That will allow us to maintain flexibility going forward. It's been beneficial to us to have a drilling company where that we own 50% of and where we have a first time or first call on all the rigs. Specifically so that we can stop and start much quicker than other companies are able to do.

Okay. Thanks. With respect to (inaudible), can you give us more on the plants there and what sort of needs to be seen before you decide to take the well deeper.

Yes, what we have done in drilling the well to our current depth, we encountered a significant drilling break at the very bottom of the well. This could mean many different things. But we are hopeful that it means its present of the thrust fault we've been searching for. We are currently running a VSP or Vertical Seismic Profile to image what is below the current TD, been able to image seismically from down deep in the well bores a lot more accurate of the picture and then out to show us if there is indeed a thrust fault there that we've been looking for. It might show us what the geometry of the rocks below the thrust fault is, and at what stage they are. So it's going to be critical for us to figure out what it looks like below us. But we are encouraged that we think we may have found the fault, and so it will probably take us about three or four more days; a day to shoot the VSP and a couple of days to interpret it and then we'll know what it looks like below us.

Okay, thanks. And then back on the Columbia River Basin, any comments to whether you [saw] the salt on that latest well?

No, we've intentionally not referenced any of that information. At this stage of the game, our desire is to drill the well to total depth and make comments there after.

Thank you. And there's one last one. Any color on the cost of the individual classic completion that we've done in Greentown.

That depends on the frac and the frac design. Carl what's the range.

Give or take 200,000

200,000 per interval. And each one of these wells has got 15 plus intervals to look at. As for me we are going to complete all 15. But all these wells had significant shows in upper intervals that we have drilled in this place.

Okay. What is the average thickness of those classic intervals and I think are some early challenges on fracing these wells and having some sort of effects from the salt with the (inaudible) is there any concern about being able to keep those fracs within zone.

No. Actually we found… one of the benefits of the salt is, that it's a first class frac barrier. So the fracs are very well contained within the salt. The concern that we've had with salt redeposition is related to gas expansion during the production phase and we found that by being careful with how hard we pulled the well and providing periodic fresh water flushes to keep the salt below the saturation point in the water, we are able to mitigate the problems. So we will feel like we are well positioned to handle that.

One of the problems that we had in the past was collapse casing and that collapse casing that we had was stronger pipe that would normally be used for this depth of well. But the current casing design has extremely strong or high collapse strength pipe and so far we are in and out the wells all the time and having no problems whatsoever. So we have a lot more confidence in being able complete multiple zones and commingle than production than we once did when we were completing the initial wells and perforating several different intervals. As far as the classics themselves; they vary in thickness. Some are considerably thicker than this "O" zone or the Cane Creek. Some are about the same in thickness. All of the wells drilled have net classic intervals of about 1000 feet in total, and the "O" zone makes up about 70 feet of that. So there are numerous intervals and a lot classic to go.

That's all I have, thank you.

Thank you.

Our next question is from John Freeman of Raymond James. Please go ahead.

I am just trying to go back a little bit in time again on the Paradox Basin. Just trying to see maybe what kind of thought process, how it's changed from the start. Earlier in the year, the vertical wells, the biggest issue was that the decline was a just a lot steeper than you all anticipated to my understanding. It was just mentioned a second ago, is that, once the water treatment shelf started doing the fresh water treatments, the declines are much better. So you kind of figured it out, that part of the decline curve and it looked like at least that on a vertical basis these wells were going to work, and then we ended up going to the horizontals, and obviously have had some completion issues. I am just trying to walk through maybe when we were originally looking at this probably earlier in the year. What's changed between now and… then and now?

Go ahead John.

Well probably start from me and then let Carl talk for a second (inaudible). But John I mean you are very astute in the fact that our ability now to frac and get further away from the well bore in a vertical world makes the vertical drilling much more appealing. I will tell you though, if you look at this part of the world, the only known sustainable production is from the Cane Creek interval to southwest of our… southeast of our production. We are not developing the Cane Creek horizontally here. We had an issue with the bottom seal. But now with the ability to frac long distances in the well bore and the fact that the pipe is proving to be collapse resistant. We really feel that we can target this in a multiple zone completion mentality not too dissimilar than all the other places that we chase. It's an evolution of technology. It is not an abandonment of one to the other. Carl and his group, and you can walk through some of the frac designs you've done. But it's really an increase in the ability and the effectiveness of the fracs that allow us to believe that we can do this vertically.

I think it's a case of comfort. I think the other thing as John alluded to, one of the things that drove us towards the horizontal in the first place was that value capture from the Cane Creek interval which was the prototype in the Basin. As we went through the process in our Cane Creek, we had a problem with the bottom seal and didn't see it. So with that said; we are finding the vertical completions in intervals other than the Cane Creek, it seem to work just fine and we are quite happy with them. So we will continue to exploit that.

Thanks. And then just shifting over to the Haynesville, can you give me just a ballpark number the 16,000 net acres, how much of that is in the Coupee Parish?

In Coupee Parish; well very close to the Coupee Parish is the majority of the acreage.

Okay. Thank you.

We show no further questions at this time. I would like to turn the conference back it Mr. Parker for any closing remarks.

Okay. Thank you all for joining us for the third quarter call.

Thank you. That does conclude today's conference. To access the digital replay for this conference, you may dial 1877-344- 7529 or 1-412-317-0088 beginning at 2:00 p.m. eastern time today. You will be prompted to enter a conference number which will be 424757. You will be prompted to record your name and company when joining. The conference is now concluded. Thank you for attending today's presentation.