Hello and welcome to the Delta Petroleum Corporation’s 2009 second quarter earnings conference and web cast. All participants will be in a listen-only mode. There will be an opportunity to ask questions at the end of today’s presentation. (Operator instructions) Now, I’d like to turn the call over to Broc Richardson, VP Corporate Development and Investor Relations. Mr. Richardson, please begin.

Thank you and good morning. Before we begin, I would like to remind you that we are conducting this call under Safe Harbor, and this 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 thereby. In that regard you will refer 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 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 should 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 ended December 31, 2008 as updated by subsequent periodic interim reports on Form 10-Q and 8-K respectively. Speakers on Delta are Dan Taylor, Chairman of the Board; John Wallace, President and Chief Operating Officer; and Kevin Nanke, Treasurer and Chief Financial Officer. With that I will turn the conference call over to our Chairman, Dan Taylor.

Thanks Broc. Good morning and thank you for joining us on this morning’s conference call. By way of introduction, I am an Executive of Tracinda Corporation, Delta’s largest shareholder. I have been a member of Delta’s Board of Directors since February of 2008 when Tracinda initially invested in the company and Chairman since late May. Since assuming responsibilities of Chairman I have worked closely with members of management and the business teams to become much more familiar with the company’s assets, employees and day-to-day operations. And from that process I have experienced two things I would like to share with you. First is the deepened understanding and confidence in the intrinsic value of the company’s assets, as well as its exceptional potential namely the Columbia River basin. John will be speaking in greater detail regarding the status and plans of the great well in the CRB in his remarks momentarily. Second is the appreciation of the high degree of talent and experience that our management team and our operations team possess. We are the team with an innate knowledge of how to operate our assets and to persevere in this commodity price environment and yet create value for our shareholders. The team we have has been in this cyclical industry long enough to avoid similar downturns and their experience has proved invaluable. This brings me to a similar topic which is the CEO vacancy. The CEO search has been suspended for the time being. This is due to the strength of the team in place and so the company can focus its efforts on execution and cost control. I also want to spend a moment on the strategy of Delta going forward. It is a three pronged strategy that is rather simple. First is to focus on the company’s two…

Thanks Dan. To begin I am pleased to discuss the current operations of our great well in the Colombia River Basin. I will address the current status and discuss the expected timeline of events. Before I provide the completion timeline, please allow me to clarify a few things. First, keep in mind that this is our first operating well in the basin and not our tenth well or twentieth well. Being such requires that we learn as much as possible from each individual zone as we complete them. While we planned on perforating the zones and then flowing them for a specific number of days, if a particular zone performs better or worse than we initially expected, the plans and timing will change accordingly. I need to emphasize this since we need to have latitude in understanding from our shareholders in regards to timing and information acquisition and disclosure as we go into this process. We are now at total depth and will begin perforating the lower most zones and working our way up the well bore. The perspective sands have porosity ranging from 12-17% with associated permeability ranging from 27-107 million RCs [ph]. Additionally, as stated in our press release, these zones are not in the Roslyn formation which was our primary target prior to joining. But rather in the Wenatchee formation which was our secondary target before drilling. But now based on the fact it appears to contain gas saturated sand it will be our primary target as well going forward. Each zone will be perforated followed by a short flow and pressure transient test. Stimulation will follow if required based on transient results in unstimulated flow potential. Subsequent to that will be a longer flow period and a longer transient pressure build up testing. These tests are…

Thanks John. During the second quarter we took initial steps to strengthen our balance sheet. As mentioned, we raised $247 million net to the company in an equity offering and also received $49 million in net proceeds from a portion of our litigation with the Federal government. These proceeds were used to reduce debt and improve our working capital. Our borrowing base was reduced from $295 million to $225 million in accordance with the arrangement. We have paid down our credit facility to $83 million leaving a $141 million of remaining availability at June 30. In addition, we reduced our accounts payable by 43% during the quarter. Delta continues to have the support of its banking group and is confident that the September bank redetermination will not have a material impact on the company’s efforts to preserve liquidity. The decision to suspend completion activities is primarily due to the desire to preserve liquidity and timed expenditures to yield better return on investment. Accordingly production guidance for 2009 is being revised to 21 Bcfe. Base operating expenses have improved from a $1.56 per Mcfe in Q1 to $1.34 per Mcfe in Q2. These improvements include lower salt water disposal cost, field staff reductions, and purchasing compression facilities as opposed to leasing them. We expect further reductions in these operating expenses with additional cost cutting measures at the field level. Total G&A decreased 29% from Q1 and was comprised of $2.7 million in cash savings and $1 million in non-cash equity compensation savings. We have reduced our staff from a high of 160 to 85. Total annualized salary and benefit savings from the two reductions in force approximate $8.4 million. You can expect total G&A to stay consistent with 2Q as we recognize an equity comp benefit for all shares related to the most recent reduction in force during Q2. However, you can expect cash G&A to decrease to approximately $6.5 million to $7 million for the quarter for the rest of 2009 as cash savings for the June reduction in force was not recognized in the second quarter. EBITDAX after adjusted for one-time executive severance arrangement was $5.8 million for Q2, an increase of $6.2 million during the quarter. This increase almost solely can be attributed to the cost cutting measures previously mentioned. During the quarter, we recorded $107 million in non-cash impairments. These impairments were made to 100 properties, pipeline and gas plant, pipe inventory and spare drilling equipment. No proved oil and gas properties were impaired. These impairments were driven by sustained lower commodity prices, reduced lease grades, and delayed drilling plants. We recognize that although we made important strides during the quarter, we will continue to practice strict financial discipline on both capital and operating expenses. With that I will turn it over to Ryan for Q&A.

(Operator instructions) Our first question comes from John Freeman of Raymond James.

Good morning guys. The first question I have got on the Colombia River basin, you guys are raising the CapEx a little bit here despite the delaying of the completion activity in the Piceance. It is stated that it is because of the additional unexpected cost on the current Gray well on the next confirmation well you hope to drill. Can you say what the confirmation, what you are putting in the budget for that cost with AFB on it?

John, this is Kevin. I think, included on the CapEx is approximately $5 million to initiate activity on that well. The total AFB is probably somewhere in the order of $25 million dry hole cost.

Okay, great. On the Piceance, can you quantify if there is a certain price where you would restart the completion activities?

John, this is John. Based upon the CIG strip you get the 375 on the CIG minimum economic thresholds in the company has been met heading into the season. There is a lot of uncertainty in the pricing but we will be monitoring that. But it is pretty much where we believe it becomes economic for completion and drilling.

Okay and you mentioned there is probably about a 40% reduction in completion cost. Can you just estimate what you think that completed well cost could be in the Piceance?

I would say there is probably at least a 40% reduction in completed well cost and our completed well cost are running about 1.95 million at the end of 2008.

So, if you were to like restart the drilling program, drilling completed well, what would you estimate the cost in the Piceance?

You can assume $1.4 million. Once you start up this process and really begin getting hard bids I expect that number to come down from there. But that is an initial target.

And then last question and then turn it over to somebody else. On your acres that you have at the moment in the Hingeline or Paradox you kind of shelved for the moment, are there any lease expiration issues we need to worry about on those?

No, we have active negotiations on all those areas right now. We don’t have any lease expirations really throughout the company.

Sorry one more on the, if memory serves, the DHS any sort of compliance issues there? If memory serves that is non-recourse to Delta, is that correct?

Correct.

Thank you very much guys.

Our next question comes from Tom Gardner, Simmons & Company.

Just a follow up on that. Quick question about impairment specifically around acreage, were they related to lease expiration, the impairments or something else?

No, lease valuations. There has been kind of a wild ride for the last couple of years. From initial expectations, when gas was double digit to what gas prices are now and how that translates into lease bonuses and she is kind of coming in line with what our expectations of more reasonable lease bonus figures would be in today’s world.

Okay, I got you. With respect to your assets monetization plan, you mentioned that you have to attain $70 million in additional liquidity. Is this figure net of any borrowing base determination that may come about with the associated property sales?

Yes.

It is net?

It would be net to the company.

Approximately how much in the way of properties you plan to monetize?

Probably around $90-100 million with borrowing base reduction somewhere in the order of $20 million. We are focusing non-producing assets, a lot of that will be non-producing, non-core assets.

Tom what we are really focusing in the non-producing assets, things like pipelines and laying units, ranches and things like that. That is what we are really focused on.

Any specific region, or it is kind of spread out?

No, it is spread throughout the company and would obviously be pipe inventory spread, through different yards, through Rockies and even South Texas. The ranches would be acquired in the Vega area for the purposes of not being able to negotiate acceptable surface use agreements. Now that we own the ranches we can put surface use agreements on those lands and then we market them. Pipelines would be – our interest that we own in some of the Vega pipelines as well as that we own the Paradox basin. So it is spread around where our core assets are, but that will not affect the economics of our or future development of our core assets.

Thank you for that and one last. I appreciate your comments on your plans on the Gray well, the 31-23. Will you be releasing interim updates or is there – do the well watchers have their leg up on testing?

Unfortunately for scaling the well. In this part of the world there is not a tree within miles and county roads. So we really can’t restrict scaling of the well. Having said that it is our intention to comment on the well when it is fully completed. There could be misconceptions even within Delta as far as a particular overall success of the well and portraying those results on zones yet to be completed is probably not prudent given the exploration well. So, we will comment when the well has been fully completed. We are moving on this fairly quick. One of the things I want to allude to is there is some uncertainty in the completion of these zones. There is likelihood these zones will not require fracing. But we are modeling that they might. So, you can see that there is uncertainty knowing the exact timing. Having said that we also have results within the company and results that we think probably material to the company here within say eight weeks.

Did you say eight weeks?

Eight weeks, yes.

There is no pipeline currently, so you will be flaring the gas as you do test.

Correct. Burning it.

One last question, in a continuous program, just sort of modeling it out. What do you hope to achieve on a well cost basis in the basin?

Any exploration that moves towards development you see pretty significant cost savings at least for the first five or six, seven wells. Other plays around the US especially Rocky Mountains experiences as much as 15% capital reduction from well to well for several wells. Given the fact that our challenge here is drilling through basalt, there is not a readily available learning curve for Delta. And having said that we think that we have really improved our procedure for drilling the basalt and we are pretty excited about things that we have learnt subsequent to actually drilling the basalt section and that will be the big area of major cost savings that we can see going forward. So, I would say we are to at least achieve something like double digit decrease well by well for the first five wells.

Thank you very much John.

Our next question comes from Joe Magner of Tristone Capital.

Have you released the actual MTD was on the Gray well or can you provide that information?

No, at this time we are not giving any specifics on the well. You understand that we have surrounding the well. So, it is fairly well, scouted well. There is a lot of information on it but we are currently not commenting on the specific parameters on the well.

One parameter that you did provide was the 27 to 117 million was that measured at the surface or was that measured some how down hole?

That is permeability, and we use that more of a common denominator when you talk about permeability of the sands.

You have any estimate or have you run any test to calculate or calculations on what that might be in future?

We have studied this rock like you can’t believe and unfortunately I can’t comment on it. A lot of professionals and very seasoned veterans working on this, both Delta and with our partner.

And I guess one asset that has been talked about all the time of an on, JV or outright sale of Piceance assets. Can you provide us an update on those plans?

We continue to discuss any and all alternatives here at the company. It is a core asset and it is the one that we think underpins the value of the company now and going forward. And having said that, we are now in conversations with various different entities concerning all the assets that’s not the one that we want to lose because we know the value that asset has so dramatically increased in a more normal gas pricing environment, but having said that we are focused on any and all funding alternatives.

In terms of the gas production trajectory, it looks like 18% decline sequentially, is that indicative of what you are going to expect going forward? If not can you provide sort of --?

It depends on future drilling and hyperbolic decline initially and then they flatten out with time. Time goes on the decline arrests itself and flattens to a fairly shallow decline ultimately. When you have normal ongoing development it feels like the Vega new wells continually bringing on new wells masks individual wells initial decline for the first several months. We saw that in first, second quarter because not only we quit drilling, we quit completing. But having said that in the normal situation with ongoing drilling program we actually have increasing production and then at some point when you are done developing this asset several years from now it will experience initial steep decline for the first few months and then it will flatten out over time. I think that answers your question but I guess what you are alluding to is the decline we saw in the first, second quarter is that normal and then answer is no. It will get shallower and shallower with time.

Have you seen that rest itself during the quarter and do you have any sort of July volumes that might provide some indication of --?

I don’t have that really available in my fingertips. But I will tell you though we have modeled every well in this field and they have a very predictable production profile. And there should be no variation whatsoever from that production profile with years of history and they all have exactly the same shape, a very similar shape. The only difference in reserves is more of a difference in initial starting rate and the case thickness.

Production --? Call me when you talk about the last line, I will walk you through the production profile.

We built it internally I was just trying to get a handle –

There is a ton of research on Piceance basin and its production profile in all the different fields. And they really don’t change much. The Vega area is one of the thicker pay counts, so it behaves like some of the fields in the North like Rouseau and they have more history. So, there is a lot out there.

Okay, we’ll follow it offline. Any sort of additional information you can provide on the sort of timing of the second California settlement? Where that stands and what he hurdles are going forward to getting that completed.

I am going to put Ted on the line. Ted Freedman our Corporate Counsel so that he can answer that question.

Now that we have a judgment with the Federal government for $91.4 million. The Federal government has filed a notice with PIL with the judgment but it has not yet filed its opening brief. Its briefing schedule – briefing to be completed in November. It is possible we will have our arguments as early as December, but I am expecting it in January with the decision likely in the Spring of 2010.

Is that kind of the final appeal option that you have similar to the first one or --?

It is exactly the same as the first one. They would have the option to file with the United States Supreme Court. But then they didn’t do it last time.

And then Dan or Kevin, you mentioned based on the outlook you might not be able to combine the bank covenant at the end of the year. Looks like at the end of the second quarter your borrowings were well below at least confirming base as it stands even with the reduction in property sales of 20 to 30 million flexibility. Can you just sort of lay out what the limits on covenants will be or could be that you are insisting?

Sure. The leverage ratio takes into consideration the last four quarters of our EBITDAX and as you recall last quarter it was negative. Though what we are talking to the banks is giving us some relief over these next couple of quarters and then having them more than an annualized calculation on leverage ratio going forward most likely in the second quarter. So, what we would do is take our EBITDAX for the second quarter times four and with that we anticipate being in compliance with the covenant going forward.

And keep in mind the challenges that we are facing on bank covenants is not a liquidity issue but merely a covenant issue. That also makes it easier for us to have discussions with the banks.

That’s all I have for now. Thanks.

Next question comes from Joe Allman of J.P. Morgan.

Thank you. Hi everybody.

Good morning.

Good morning. John, what are the implications of that secondary target the Wenatchee, maybe becoming the primary target and if that is the case Wenatchee less expensive than the Roslyn. Can you talk about what the implications might be?

I will try and touch on it without kind of revealing too many facts adhering to our agreement. But by the way you said it correctly nobody around here can pronounce it right. Wenatchee formation is an uphill formation that generally is thought to be secondary target in the basin because it appeared to be porous impermeable but it also contains water in different parts of the basin. We are lucky we are here to have a higher than previously seen gas column. Now you have the sands in a different environment in what could be a gas charged environment and it appears to be, further testing will validate them. As far as how big an area it covers, again this is the first well it looks like this but I will tell you those sands are persistent throughout the Colombia River Basin. You can find those sands in all wells.

Okay that is helpful thanks.

That the Roslyn was the primary target prior to drilling. Everything that we learned about the uphold formation excites us about Roslyn’s potential knowing that the gas source is actually in the Roslyn. So, Roslyn will not be moved to the secondary target. We’ve got primary targets.

Thanks that is helpful. And moving over to Piceance, if I remember correctly at the beginning of the year you had thirty wells drilled but not completed and now you have got inventory I think you said 23. So does that mean you have completed seven wells and if that is the case whatever the number is how much should that cost so far this year?

We had 31 wells at the start of the year. We completed eight of them and we have 23 remaining to be completed at some point in the future and Kevin speaks about it as well.

We spent approximately $3 million to complete those eight wells. All of that included in the second quarter CapEx number.

Okay. So the rest of the spending this year mostly has been in the Colombia River Basin.

Yes.

Yes.

Okay that was helpful and Kevin, regarding the borrowing base determination, you think may be you will get a reduction of about $20 million. What gives you the confidence on that? Could you talk about --?

No. That’s not what we said. I think if we sell assets we will be required to pay down $20 million. We are in discussions with the banks right now on predetermination and we really haven’t come out with potential pay down and that being very immaterial for the quarter, but will happen over the next month or so.

I got it now. So when you term it asset sale you were just linking that borrowing base reduction with those particular.

Correct.

I guess in terms of reserve it would appear that you probably did not add reserves this year. Is that correct? When it becomes time for base determination the reserve number probably will be lower than what it was last time you had the determination. And then I guess are the banks signaling that the gas prices are going to be lower too than they are?

Well from a PDP standpoint I think we pretty much preserved our reserves and that is kind of going through those numbers right now and will be sending our initial reserve reports to them. Price tag had been floating up and down but for it we were a little too aggressive on their price tag we were running numbers and helped to maintain same PDP as we had before.

You should keep in mind from a strategic standpoint the banks had been working very closely with us. We have done everything that they have asked us to do under our agreement including raising equity, lowering cost to selling assets and continuing to look at selling assets. In addition to that the borrowing base discussion is only one part of the overall discussion of the loan capacity with the banks. And we are working – they are working very closely with us, and we are expecting a positive outcome.

That’s helpful. The cost savings, over the year you have highlighted some cost savings targeted. Are those on track, are they moving slower than expected or better than expected both from capital expenses and operating expenses?

In general they are better than expected. Really going in or bidding out or sitting down with our particular vendors in various different accounts and convincing them that this is the right thing to do for Delta’s viability and Delta’s liability, ultimately pays the bill. I am very pleased with the efforts of the guys at the fore. It is obviously a little bit harder when you have a payable issue that we had earlier in the year. So, we have made it even more challenging but we’ve overcome that.

That’s helpful John. And then back to the asset impairment issue, I think the impairment was $117 million. How much of that is related to leasehold? Does that mean you wrote that down entirely or you just think you are carrying that too high a value?

We thought we are just carrying a high value. The Q is going to be coming out here in a couple of hours and it is well detailed on the impairment buy area. Not exactly sure the number I am thinking was approximately $20 million in the Haynesville area. Yes. $26 million in the Haynesville and we still believe in the Haynesville acreage position. It is just that leased rates around some of it substantially reduced from where we purchased it.

There is a lot of renewed interest around one of our biggest blocks in particular. But having said that there is a perception that the overall lease bonuses is coming down dramatically even with some of the VIP’s that have been reported at close spot.

And then last one, in terms of asset sales could you just highlight where are you in the process? Like are you close to agreeing on some of the asset sales or can you give us some details on that.

Various different stages. Some are easier to sell than others. Pipe inventory may be a little easier to sell say a ranch in the Vega area. But having said that we have people assigned to each one of these assets and they are all ongoing. We have had data rooms set up and we have numerous different people in here. I think that there is a perception in the industry at least here at Delta that for the past three or four months it was all not that easy to sell any asset in the oil and gas sector. There seems to begin referring up a little bit. So, we have spud focal and it is very concentrated in its effort whether it is non-producing or producing. The expected timing is in the next several months.

I can’t exactly comment when we are going to sell the ranch. But I do expect to have a lot of buyers in. Internally the assets to be sold or considered have been presented to the Board along with proposed time line for those assets. We do currently have in house bids. Some assets are more easier to market, more liquid type assets. We also have some assets out to some specific potential buyers. So progress is being made and the Board is watching this project carefully.

On a gross basis, what kind of growth are we talking about?

90 million.

90 million. All and everything you have got marketing right now?

Well, yes less than land. That really contemplates what we reasonably expect to accomplish over the next six months.

Dan is right our expectations are a portion of what we have for sale or what we actually sell.

Okay, very helpful. Thank you.

Our next question comes from Evan Templeton of Jefferies.

Two detailed questions on the income statement. First of all, interest income seemed higher than a model calculation. Is there one time event or charges running through that?

We do take a one time write off our deferred amortization cost for DHS. At this time we do not have an agreement with the Lehman Commercial Paper Group and when you do not have an agreement in place you are required to write off all of your cost and that was in excess of $0.5 million.

Okay, is there anything else running through that or is that pretty much it?

No that is pretty much it. It is probably the timing of our pay down of our debt which happened at the end of the quarter.

And then also just similar question as far as G&A, what was the non cash comp on it?

The non cash comp for the quarter was 1.8 million. Also will be detailed in the Q. That is probably a million dollar less than your run rate going forward.

Perfect. Thank you very much.

Our next question comes from David Tameron with Wachovia.

Most of my questions had been answered. But one quick question. Piceance, does this have an impact on the kind of JV or what do you say on that agreement? No. You mean the completions in drilling. It doesn’t currently have any impact on the joint venture.

The relationship is purely a financial relationship.

My understanding is that you have to complete certain well at certain date. Is that correct?

That is the old agreement in which we took out with out last –

Okay thanks.

(Operator instructions) Our next question comes from Jack Aydin of Keybanc Capital Markets.

Regarding the asset sales, is the Paradox and the Haynesville assets are on the block? On the asset sales package?

Paradox assets we still have quite a bit of hope for them. We are looking for a more joint venture participation in the Paradox assets. There is just too much real mess left with that particular asset. In the Hingeline play were it is a combination of the two, leases or joint venture participation. It might even be a hybrid of that.

I remember asking you about Haynesville acreage?

The same either out right sale or potential joint venture participation.

Is that in the CRB? It will cost a dry hole in essence $25 million. Within the spreading risk more advisable get a joint venture partner, I mean $25 million dry hole cost for a company of your size is large. I know it is not all yours. Are you in the process or --?

We have a partner, so we have made public we have only half interest in the well. All these decisions can be made a lot more concrete once we have completion results from the well.

We talked about any and all scenarios around here but right now what we need to hear are concrete results on the well and that’s what we are focused on getting.

We have plenty of quality in-house today to drill our proportionate share of the CRB well. It is 12.5 million of our proportionate share.

What will you need in terms of EUR to make it economical for that kind of house for a full cycle development phase?

It is too hard to tell Jack. We have to see what the production profile looks like; get a better handle of marketing and timing. When we get some results from the well we will be able to comment on the economic viability of it.

Thanks a lot.

Our final question comes from Joe Magner from Tristone Capital

Follow-up question regarding the completion most likely in the second quarter. Can you throw a little more detail on the timing of when those may have come on?

Mostly in the first quarter I believe still at the end of the second quarter. I think February, March, April timeframe. Little bit in May.

Thanks.

That does conclude our conference call.

With that the questions being over, we appreciate very much you being on the call. We look forward to talking with you in the future with some meaningful results. Stay tuned and thanks for tuning in.