Welcome to the Delta Petroleum Corporation 2008 year end and fourth quarter earnings conference and webcast. (Operator Instructions). Please note this conference is being recorded. Now, I would like to turn the conference over to Broc Richardson, Vice President Corporate Development and Investor Relations. Mr. Richardson, please go ahead.

Before we begin, I would like to remind you that we are conducting this call under Safe Harbor and 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 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 proved reserves that the company has demonstrated by actual production or conclusive formation tests to be economically and 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, 2008 as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively. Today’s participants 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, and Ted Freedman our General Counsel. With that, I’ll turn the conference call over to Mr. Parker.

Yesterday, Delta Petroleum reported its 2008 financial and operating results. Operationally 2008 proved to be a year of significant reserve and production growth, as well as record revenue in EBITDAX. We reported proved reserves of over 884 bcf equivalent up 135% from year end 2007 and up 35% from the unaudited proved reserves reported as recently as September 30, 2008. Equally impressive is that we were able to grow our proved reserves with an all in finding and development cost of only $1.37 per Mcfe, a drill bit finding in development cost of $1.55 per Mcfe, and in spite of declining commodity prices, we also reported revenue of $221 million and EBITDAX of $156 million, which represent increases of 79% and 86% respectively over 2007 levels. Production also increased significantly by 48% averaging 68 million cubic feet equivalent per day for the year. While I think 2008 certainly was a year of accomplishments for Delta, it also ended with significant challenges relating to the precipitous drop in commodity prices. Along with the filing of our 2008 10-K and related press release yesterday, we issued an S-3 registration statement and a Rule 134 press release in conjunction with an expected shareholder rights offering of $175 million of convertible preferred stock. Additionally, the company has signed an agreement with the lenders in our senior credit facility that provides for covenant relief for 2009 and 2010. The combination of this offering and the forbearance from our banking group will provide the company with sufficient liquidity and flexibility to endure a prolonged downturn until commodity prices recover. Additionally, as part of our go forward plan, we will also be hedging to take advantage of the Contango and gas price strip. We will also be paying attention to meaningful cost reduction. Our general and administrative…

(Operator Instructions) Your first question comes from Tom Gardner – Simmons & Company.

Roger, can you walk us through the timeline of getting this shelf approved, and you've laid out some of the structural terms but just want to get an idea of what needs to occur to get that going?

Tom, we have filed a registration statement and timing is up to the SEC. It's impossible for us to predict whether or not it will include review or not.

Your next question comes from Joe Magner – Tristone Capital.

Just wondering if you could walk through the reserve bookings, if I go through this based on some of the math I was looking at adjusting for the acquisitions, it looks like you booked on average 4 to 4.5 offsets per approved developed location and that would be up from 1.5 to 2 offsets from year end '07. Can you I guess comment on that and then just comment on what changed throughout 2008 that allowed you to I guess increase those bookings?

Joe, you're correct the overall total is approximately a 4 to 1 booking and is primarily related to 10-acre booking in the Piceance Basin. We have indicated to others before in previous calls and especially at the end of 2007, that like many others in the Piceance Basin, Delta's properties qualified for 10-acre development, and that we had received approvals as such. There was a significant amount of work and effort done to establish 10-acre spacing as the correct spacing for booking purposes in the Piceance Basin, and that is how we have ended up with the increase in proved reserves that you point out.

Okay. In the release and in your K you talk about some possible divestitures and asset sales as part of your need to raise proceeds. Can you talk about, in addition to the Piceance Basin JV, and the Haynesville JV that were mentioned specifically, what other properties could be on the block?

We have numerous non-producing assets at this point in time that have a reasonable value associated with them, even with taking into consideration the current economic environment. We're working on many different fronts to do things. We've referred to joint ventures related to the Haynesville and the Piceance Basin effort, but I think it's also fair to say that we are essentially looking at that type of a situation on virtually every area of ownership that the company has. As an example, I will refer you to the comments that were made in the Paradox Basin section. There is additional drilling activity going on immediately adjacent to us as we speak. There is, and we believe that there is additional production that is desirous of getting into the pipeline and processing facility that we own, and we think that there may be opportunities related to that type of a thing as well. So without getting into the detail of all of these things, I guess I would say in a very general sense that we think that there is on the order of $100 million worth of potential liquidity-type activity that would be related to joint venture and/or sales efforts.

And just one thing to circle back on the previous question about the rights offering timeline, there's a two-week period the SEC has time to decide whether they're going to review it, if they decide to review it. Can you walk through what the timeline could look like, whether they do, whether they don't review?

Joe, just a moment, we're discussing offline here for a second. Joe, with regard to the SEC, it's typical that they will let us know one way or another within a few weeks. But we're really not in a position to make comments with regard to the timing that the SEC will take to do something or not do something.

Okay. Just one last one, it looks like you'll be required to hedge some of your production this and next year. Have you hedged anything yet, if so, at what prices? And do you have a sense as to what the basis will look like on those positions, either for the tail end of '09 or 2010?

Yes. We have not as of this moment hedged, although we will be looking to do so here in the very near-term over the course probably of the next week or two. And with regard to differentials and everything else we all see the same thing as to what is out there at this point.

The next question comes from Crystal Choi – Raymond James.

I was wondering if you [inaudible].

I'm sorry, Crystal. Can you repeat that, we can barely hear you?

If you could move the voice tube a little bit closer Ms. Choi that might help.

Is this better?

That is better, yes.

The $52 million, I was wondering what kind of activity that assumes now?

Well, in a very general sense what that allows for, we tried to set it out in the earnings release, but the $52 million essentially allows for obtaining all of the necessary information, including completion and testing information at the Columbia River Base, Grave 31-23 well that we're drilling, and then also what will be a very measured and consistent effort of completion activity on our drilled but not yet completed wells in the Piceance Basin. And the combination of those two things makes up the majority of the $52 million.

Okay. So the timeline on activity in the Piceance meeting bringing the wells online, do you have any kind of expectations of when they'll be tied in?

Yes. The intention is to do it as mentioned in a very measured way so that we can keep production as close to flat as possible and that is the intention behind the completion effort in the Piceance.

Okay. And what is your internal rate of return in the Piceance [inaudible]?

Well, I'm going to refer back to some of the opening comments that I made here related to our approved reserved bookings. I think at this stage of the game it is not appropriate to use capital cost pricing from 2008 when you look at a commodity price deck that we're currently experiencing right now. We would note again that numerous contractors not only with Delta I'm sure but with others in the industry as well have proposed significant cost reductions, and if you were to assume that the significant cost reductions will take place, then in a very general sense the rates of return, even at a lower commodity price deck, will be very good. And I would further comment that if you turn the clock back to the 2001 to 2005 timeframe, you had a commodity price scenario that was somewhat similar to where we are today, and there were numerous companies that were able to grow and experience very reasonable rates of return out of the Piceance Basin with lower commodity prices. They were able to do so because capital costs at that point in time were significantly lower than where they are today, all of which speaks to the idea that as we go forward here, if commodity prices do not change from their current levels, I think it is very safe to assume that capital costs are going to come way down, substantially down.

Stepping to the CRB on the Gray well, do you have any kind of estimate on how much the completed cost will be or can you tell me how much has been spent so far?

No. And in fact the comments that we have made in the press release are typically a little bit more than we would make at this stage of the game and with a well that is still drilling, but given the overall situation here, we felt if necessary to go ahead and come forth with the information that we did. So we put quite a bit in there but that will be the extent of that we will comment on the Columbia River Basin at this point.

The next question comes from Jin Lu – JP Morgan.

A couple of questions for you [inaudible] asset I think that you moved all assets for sale category is that a viable option to sell the assets.

We have received proposals related to the asset as of this point in time, but also as of this point in time we have not made any definitive decisions as to what to do with the property, and that’s the reason for moving the property out of the current asset category, or out of the category as being listed for as an asset held for sale.

Okay. Is the offer received above the book value you had in the end of third quarter?

We can’t speak to that.

Okay. Then looking at your fourth quarter severance tax it seems a little bit low, should we expect to the same run rate into 2009 or is there a one-time item?

I’m sorry what was low? Which item?

The severance tax.

Just a moment.

Or the production taxes.

Yes. We did receive severance tax credits back for some of our properties in South Texas so there was essentially a one-time reduction that would be non-recurring, and as a result the third quarter numbers are probably more representative as to what to expect on a go forward basis on a cost per unit basis.

The next question comes from David Tameron – Wachovia.

Couple questions DD&A rates, can you give us an indication given the reserve bookings and the impairment charges, do you have a number for that, Kevin or Roger, going forward for 2009?

David, we think that the fourth quarter Mcf numbers are representative of what’s going to go forward so you can use that number.

Its basin would actually be slightly lower on average than fourth quarter.

I think it was right around 380, something like that.

No. It was lower than that. Okay I’m sorry, David, go ahead.

No that’s fine and the cost reductions in the Piceance, what magnitude are you looking for? Obviously it depends on prices but let’s say prices say if prices stay where they’re at, what magnitude would you need and what are you seeing down the field?

David, all I can do is tell you some of the things that have been proposed without detailed negotiation thus far. We’ve had proposals on the order of 25% to 35% cost reductions depending upon which contractors you’re talking to. And I think it is widely assumed and expected across the service industry that if they’re not coming forth with those types of reductions, they’re certainly going to see a continuing reduction in activity, not only from this company, but from all others as well. So those are initial indications, but one of the things I think that have been very helpful is we’re in an environment right now where there have been a number of companies, especially the bigger ones that work for us out in the field that have approached it from the standpoint of where all in this together. So we’re going got come to the appropriate amounts that will allow for an economic viable program going forward. And if costs have to come down that much or even more, then there is probably going to be a concerted effort to try and allow that to happen.

But at $4 gas if you get 25%, 30% reduction in service cost then Piceance works I take it?

If you put a 30% cost reduction on your program out there your rates of return jump back up to very appealing numbers.

And before we leave the Piceance the JV with EnCana I mean you’ve got 100 million in November payment but that looks like you still have that cash on the other side of the restricted deposit.

That’s important to point out. We have $300 million in restricted cash on our balance sheet. And that cash has been set aside for a letter of credit that was issued by JP Morgan to EnCana specifically for the payment of the EnCana transaction that we entered into a year ago. So those payments are already set aside and do not affect our go forward plan.

Okay. And my question was going to be you talked about Piceance JV’s, what restrictions do you have surrounding EnCana agreement that would prohibit you from selling it?

We have no restrictions related to our EnCana agreement it was a straight acquisition.

I think if you were to sell that asset or JV that asset that you’d still owe that restricted deposit to EnCana correct?

Yes. Essentially, yes, take the cash and set it aside and consider the agreement with EnCana fully paid.

Okay. Let me look out six months assuming you get this offering done, in the 10-K it still talks about the conforming basis 185 so I assume you’d have to make that whole at some point plus you have the accounts payable. Come June 1 how do you see your financial situation? Can you give us a snapshot of what that looks like, how much cash flow you think you’ll be generating? And is there a need to do additional equity after that?

No. The intention behind this effort is to insure that the borrowing base reductions that will be required to occur are covered and that all other items necessary are covered, and that we also have sufficient liquidity that will allow us to go forward in the current commodity price environment. That was, as you might expect, important to both the combination of our banks and our larger shareholders. Both of whom continue to support the effort and the assets that the company owns at this point.

Okay. If I just look at my model, Roger, I show a deficient this year relative to that $50 million CapEx. What kind of numbers you guys expect for cash flow and where do you guys show it internally?

The one thing I guess I would bring up at this point David is that I think that we probably are going to be more aggressive in our expectations than you are with regard to cost reduction. As mentioned earlier in the call, we’re looking very hard at G&A cost reduction of levels that will be on the order of 50% of what they were in 2008. And behind that and related to the other comments we made about capital cost reduction, that will flow through to your lease operating expense as well. So we do not have a deficit in our models for 2008, excuse me I’m sorry 2009.

So you show yourself generating $50 million of free cash flow excluding the rights offering?

For the CapEx.

Your model shows your generating cash flow equal to CapEx for ’09?

Essentially, yes.

Okay. One more question I promise last one. Acreage, you mentioned somewhere in the K that some leases have to be drilled I believe by June, is that the Haynesville well. Can you correct me is that the right timing on that?

To July 1 for one Haynesville lease.

One Haynesville lease, so you just have to drill one well. What’s the drilling obligation associated with that?

Sorry, David, can you repeat that please?

What’s the drilling obligation? You have one lease that expires, is it one well on that lease or do you have a drilling obligation? What’s your obligation?

We have a drilling obligation to the extent that we don’t begin drilling activity. We will either need to negotiate an extension, which we think is very possible, or alternatively allow the lease to expire.

The next question comes from Shannon Nome – Deutsche Bank.

A couple reserve related questions. Did the 10-acre down spacing reserve ads show up in the revisions or was that, which category did that show up in?

That’s in revisions, Shannon. Let me make another comment in that regard as well. We would note on your 10-acre spacing there that we now have 158 producing wells and with that we have been able to prepare extensive petrophysical and geological information that confirm similarity of rock in our entire leasehold, but in reality across a very good portion of the basin center in the Piceance Basin. So in any case, I think that’s worthy of note related to the 10 acres.

I’m presuming that given the increase in your future development costs that the gross upward revision was quite a bit higher than whatever [166Bs] that you showed? Can you disaggregate what the gross upward revision was and what the net downward presumably revision was for pricing, the components of that?

Yes, hold on just a moment. Shannon, the upward revision, as mentioned, was essentially all related to 10-acre spacing. There were downward revisions of approximately 35 Bcfe, and then the 35 Bcfe equivalent extended across a number of properties but primarily South Texas.

Okay. And then were the upward revisions 100% PUD category?

Virtually all, yes.

Okay. And then which geographical areas were the extensions and discoveries booked? Then you had a pretty healthy booking there too.

Yes. That was also primarily Piceance Basin. You know we did have four rigs running virtually the entire year last year, so all of which was a 100% successful program so that’s where that comes from.

Then the other question, I guess going back to one of your opening comments that you PDP or total PV-10 is actually less than the PDP PV-10 and I guess just to clarify what the booking rules are. How can you book reserves for a location that has a negative PV-10? Is that allowed under the booking rules or do those not have to square up or how does that work?

No. It is allowed and it’s not a negative PV, it’s a negative PV-10. So and I’m sorry but I’m speaking off the top of my head at the moment, I think you had the equivalent of approximately a PV-8 for most of your PUDs, which gives you the negative PV-10 but certainly a positive PV. The requirement is that you have positive PV.

I see and you’re using 8% as a cost to capital or what’s the eight? Or why use something other than ten, I guess?

We’re not using something other than ten. I’m telling you that’s what the calculation came out to. The SEC rules are to book a PV-10, well the rules are that you need to report related to SEC PV-10 and because the PUDs did not quality for PV-10, they actually show up as a negative number in spite of the fact that they have a positive PV. And the positive PV, I believe, is on the order of PV-8 for the PUDs, using year end pricing and historical costs. That’s why I made the comment that if you were to run these same reports based on the current strip, all categories would have a positive PV-10, and the PV-10, total proved PV-10 would be substantially higher than it is as reported in the 10-K.

Although it seems the year end pricing, gas prices have actually dropped, but you’re saying because the curve is upwardly sloped that you would actually get a higher number now?

That’s correct.

Then do you think, since you’re spending 52 million trying to keep production flat, is that a decent go forward estimate for where you think your maintenance CapEx is?

Well, for 2009, yes, but you have to take into consideration that we do have an inventory currently of 35 wells that have been drilled and not yet completed, so additional wells for future years will need to be drilled.

So those 35 wells ostensibly will be exhausted by year end then?

That’s correct.

Final question, you disclosed I think your gross acreage in Haynesville, what’s the net number?

The net number is approximately 11,000 acres at this point. It’s 11,000 with conditional agreements that would allow that number to grow to 17,000, if we were able to drill in the latter part of 2009, which is not currently in our CapEx budget.

And the lease that expires in July, how large is that can you say?

It’s approximately 4,000 acres.

The next question comes from Greg Brody – JP Morgan.

I was curious for the cash flow expectation that you’re forecasting, what’s the pricing you’re using in differentials you’re assuming?

Current differentials and current NYMEX strip. I think at last look the CIG differential at this point is probably an average of about $1.60 for the remainder of 2009 and lower than that for ’10.

With DHS, how many rigs are currently operating?

DHS is kind of fluctuating between three and five rigs running full time at this point.

Do you foresee anymore coming down over the next several months or?

I think they are reasonably confident they’ll be able to keep that level in operation. There was obviously a dramatic and swift decline from between the beginning of December and the end of January. Virtually all the rigs were running through the end of November, which was 20 rigs and by the end of January, they were down to a level of four or five.

And my final question, if you wouldn’t mind just providing some color as to how you think the basis will play out over the next year, if you see any indications of improvement, reduce supply, etc.?

The gas price basis differential?

Yes.

Yes. We are of the opinion that as the Rockies Express eastern leg becomes operational, you’re going to have a reduction in differential in the Rocky Mountain and that in combination with El Paso’s announced and recently reconfirmed intent to go forward with the Ruby pipeline to the West Coast, is going to bring down Rocky Mountain differentials in a pretty significant way over the course of the next two years. So, the expectation is that we can get into a much better differential environment over the course of the next 12 to 24 months.

Is your expectation is that Ruby will still be online in 2011?

We can only go off of El Paso’s public comments, which were released and reconfirmed only a few weeks ago, and I believe that that’s what they said.

The next question comes from David Tameron – Wachovia.

Quick question to Piceance the 10-acre spacing, what reserves were those booked at compared to the 20s as far as EURs?

Dave, we’re getting the answer for you right now but let me also make a comment with regard to the properties that Delta has out there, which I think is reasonable to point out and discuss at this point. We have a thickening gas column across the leasehold that Delta owns substantiated by already drilled wells. Most of the wells that have been drilled on the property and are in production today are on the southern half of our leasehold, which is the thinner gas column portion of our leasehold. And the expectation is as a result that, as you move forward and drill the northern part of the property more than the southern part of the property, your average per well reserve recoveries are coming up pretty significantly over what has been experienced thus far. Now having said that and for reserve booking purposes, what you’ve got is essentially a blended average, if you will, but most of the unbooked reserves that the company has are going to be in the thicker gas column portion of our leasehold ownership. So that’ll give you some indication of what we expect on a go forward basis.

Your next question comes from Joseph Magner – Tristone Capital.

Question about the current borrowing base and the conforming borrowing base being lower, assuming you move ahead with Piceance JV, what could be the impact to the calculation of that borrowing base?

If you were to assume that you did a transaction where you sold off a portion of your PDP reserves as part of the transaction on a JV situation, then undoubtedly you would have a further reduction of your borrowing base related to that, but I guess I would respond to that by saying in the event that that were to occur, theoretically you will get a valuation that will be significantly in excess of what you would need to do to reduce your borrowing base further.

If those are proceeds you generate you would be…

Yes. Exactly, you would clearly there’s no reason to do it unless you were in that position where you could pay your borrowing base down further.

Assuming the majority of the $35 to $40 million you plan to spend in the Piceance is used on completion work, what are your thoughts about being able to convert PUDs or how your reserve mix may shift between the end of ’08 and end of ’09.

On a percentage basis, I’m not sure that I’ve got enough information to give you that right now. Certainly, we’ll probably have some increase I the PDP percentage simply because we’re completing wells that would have been in the PUD category at the end of the year. But I guess the one thing I would do is say we’ve got 35 wells to complete and I believe that we had approximately 150 wells producing at year end in the Piceance basin area. So while it’s probably not a direct correlation, it’ll give you some sense of what you might get in terms of PUD conversion to PDP.

I would like to turn the conference back over to Roger parker, CEO for any closing remarks.

Thank you all for joining us today and we’ll talk to you at the next earnings conference call. Thank you very much.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.