Welcome to the Delta Petroleum Corporation’s first quarter 2010 earnings conference call and web cast. (Operator instructions) I would now like to turn the conference over to Broc Richardson, VP Corporate Development and Investor Relations. Mr. Richardson, please go ahead.

Thank you and thank you for joining us for Delta’s first quarter 2010 financial and operating results conference call. Before we begin, I would like to remind you that we are conducting this call under Safe Harbor and this call will include projections within the meaning of the Federal Securities laws and are intended to be covered by the Safe Harbors as 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 for this call. Delta may use certain terms in this conference call that the SEC’s guidelines prohibit us from including in our 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, 2009 as updated by subsequent periodic interim reports on Forms 10-Q and 8-K respectively. Today’s speakers from 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 everyone. As we announced in march we have signed a letter of intent with Opon International to sell a 37.5% of working interest in our properties in the Vega area of the Piceance Basin along with warrants to purchase Delta Common stock for $400 million in total. We continue to work with Opon in their financing efforts and are working towards signing a definitive purchase and sale agreement. We cannot comment specifically on the details of the proposed transaction but we are pleased that the process is going well and will provide you further updates as expeditiously and prudently as possible. We cannot comment further so we ask you to be mindful of this in your questions during the Q&A portion of the call. During the quarter we completed 3 wells in the Vega area and thus far are pleased with the initial results which are better than we expected. John will discuss these completions in his comments. Our revolving credit facility borrowing base redetermination was announced at the end of April. We now have a borrowing base of $145 million with capital expenditure limitations in place for the second and third quarters this year. Kevin will address the redetermination in his comments shortly. I will now turn the call over to John Wallace, Delta’s President and Chief Operating Officer, for his comments on operations. John?

Thanks Dan. For the first quarter of 2010 Delta engaged in only minimal development activity primarily in the Vega area. To date our completion activity in Vega has showed very positive initial results. We completed three of the wells with the larger fracture stimulation design than we have previously used in the past. We will be using this frac design with all of our remaining completions and are optimistic about its impact to the field. As I am sure you are aware natural gas prices have pulled back since the beginning of the year. This pull back in gas prices is the primary reason for our decision to reduce completion activity in the Vega area. While the current gas prices and forward curve are more than adequate to provide solid returns on the completion capital we must be mindful of our liquidity position. We believe we are in a far better financial situation than we were a year ago and the preservation of our liquidity is essential to maintain and improve our balance sheet. Given the initial results to date there is nothing our operating team would rather be doing right now than to restart our completion activity. However, we are committed to maintaining our more disciplined fiscal approach to our capital expenditures with acute sensitivity to the current commodity prices and our liquidity. I understand many of you would like to receive some guidance on our capital expenditure for 2010 and we know that is overdue. As we have previously announce we intend to provide CapEx and production guidance once our strategic alternatives process is completed. I am sure you understand our expected capital expenditures and production for 2010 will be driven by the proposed transaction more than anything else. I will now turn the Kevin Nanke, our CFO, for a discussion on the first quarter’s financial results.

Thank you John. Good morning. On April 26th we completed our credit facility redetermination. Under the agreement our new borrowing base is $145 million and we are no longer required to maintain $20 million of availability. So in effect the borrowing base was reduced by $20 million. As of the end of the quarter our borrowings were $93 million with $52 million of availability based on the revised borrowing base and we had cash on hand of $10 million. We have a CapEx limitation for the second quarter which totals $20 million and a limitation of $15 million for the third quarter. Because the credit facility matures in January of 2011 the debt is classified as a current liability in the March 31, 2010 consolidated balance sheet. We are currently in discussions with our lead bank on a new facility post the Opon joint venture. On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper. Under the terms of the agreement DHS is required to reduce its principle balance by $20 million over the next year. Almost half of the required principle reduction was paid in Q2 and the remaining will come from current operations. DHS expects to have 10 rigs under contract by July 1. The DHS facility is non-recourse to Delta. For the first quarter we reported production of 5 Bcfe, a decrease of 20% when compared to the first quarter of 2009 and flat to last quarter. The production decrease from first quarter 2009 was mostly related to anticipated production declines in the Rockies that have not been offset by additional drilling. For the first quarter E&P revenue increased 55% to $34.5 million when compared with the first quarter of 2009. This was due to 125% increase in oil prices and an 87% increase in natural gas prices. EBITDAX increased by approximately $11 million over the prior year quarter and discretionary cash flow increased to $3.9 million. As John mentioned we will announce our capital expenditure budget and production guidance upon the conclusion of our strategic alternative process. With that we will open it up to questions.

(Operator Instructions) The first question comes from the line of Michael Pinna – Simmons & Company.

With respect to the Piceance can we get a current cost estimate for completions since you have about 16 wells to complete there?

Cost estimates are moving around a little bit as you do these completions on a one-off basis and we are experimenting with design. I don’t think our current past quarter cost estimates are realistic for estimates in the future. When we begin drilling hopefully subsequent to a joint venture we believe this additional frac completion cost is going to be about $500,000 to $750,000.

Any sense as to how that could either stabilize production or increase production throughout the year with the remaining uncompleted wells?

Depending on the timing of our completion efforts of the 16 wells and when we really complete those wells. Having said that we are very, very encouraged by what we are seeing in the field and the sooner those wells are completed the more meaningful impact they will have on production. Subsequent to the finalization and closing of the joint venture that would be the first order of business to complete those wells so that would have a meaningful impact. That is a little bit why we are not commenting on CapEx and production guidance because it is going to be very much related to the timing of the joint venture closure. Then we will have a better indication.

The issue with LOE, trying to get a feel for what the cost savings could be. I think you highlighted it could be $0.27 per Mcfe for the installation of water disposal infrastructure. Do you have kind of a timing as to when we could start to see that roll through?

The water disposal costs are directly related to drilling and completion activity; that is when we are completing wells we actually use produced water in the completion process and have very little, if any, [water] disposal costs. So unfortunately that is also tied to our CapEx and production forecast which have not been finalized yet. Having said that, the cost savings is real when we are in active completion process.

We actually brought down our cost per M to approximately $0.86 when we were under a full four-rig drilling program in 2008.

A question on G&A, how much of the $8 million in cash G&A for the quarter was recurring G&A and how much of it was related to the strategic alternatives?

I think we had a 7% increase over our previous quarter. I don’t have an exact figure on how much relates to the strategic alternative but I would say almost the entire 8% increase was related to that.

Then any means to further reduce G&A? I know you may be ramping up CapEx to maybe $75 million soon but just any thoughts on that?

As far as G&A, especially personnel here at the company we have all available people we need to initiate and execute on this joint venture. That should not have a meaningful effect on G&A.

The next question comes from the line of Andrew Shapiro – Lawndale Capital Management.

I am trying to get a handle here on your approach to risk taking and how you approach things. Presently you have a bunch of derivatives that locked in the price. I believe most, but I am trying to understand if all of it, is tied to what is mandated by the lenders and what is management’s philosophy and approach to forwards and locking things is or would be absent the lender mandate?

That is a good question and one worth noting because the Piceance Basin and our Vega assets are very price sensitive in their development. Management has a long-term view that natural gas hedging will be a very meaningful portion of our risk analysis going forward and we will look to do probably longer-term hedges than we have done in the past. In the past we, I don’t know how familiar you are with the company or your history with it, normally 12-18 months and we will probably look for a longer time period, three years plus. The reason being, guaranteeing the economics and getting these wells through a payout process is very important to understand the execution risk of a development program like we are contemplating right now. I don’t know if that answers your question but I would like for you to be thinking along the lines of 60-75% hedged for long-term contracts. I can’t tell you for sure because it changes from time to time if we will hedge that on the NYMEX forward curve or the CIG forward curve. It is all dependent upon what we believe and our perception is for the Rocky Mountain differential aspect. Currently the Rocky Mountain differential has shrunk to I believe currently around $0.30 and long-term contracts can be secured for numbers just in excess of that. So that would lead me to believe we ought to consider the CIG basis curve as something we look to lock in the future. Having said that, if we do any firm commitments with volumes on specific pipelines, we have a lot of options right now with all of these new pipelines coming on out of the Piceance Basin and new ones are planned, we would then probably look to hedge against the NYMEX forward curve.

This amount sounds like it is above and beyond what would be mandated by your lenders. Is there an estimate or a timing as to when you would start looking to do these more lengthier locks in the future?

It is going to be a little while. Subject to the joint venture we need the bank mandated hedges to roll off. So you are really talking about from 2011 and on.

Understanding we can’t get an estimate really of what kind of new production goes into place from your CapEx yet because that is not out just assuming we are at the current non-activity and looking at the recent historical activity are oil and gas quantities for you for Q2 and going forward somewhat predictable based on certain elements of your current Q1 financials? Is there a basic formula of runoff half-life type of situation from your particular sources of oil and gas?

One of the unique and appealing aspects of the Piceance Basin is these gas wells perform very predictable on type curves. Based upon our current production of how we used to complete wells that was very, very, very predictable. What we are doing now in the field with our new completion technology is far in excess of what we have seen in the past and I can’t tell you for sure what the curve shape is going to look like exactly. Having said that, it ought to behave very similar to the type curves that are well established. It will just be at a higher rate and hopefully at higher reserve figures. I am not trying to be elusive to your question. As far as what we are producing now, that most all of the wells have been completed with older frac technology, it is very predictable. Our margin for error if you will is nominal.

We could talk offline about how that works? Obviously we are new to this investment.

Sure.

You have taken a lot of money on a liability associated with the off-shore litigation receipt of money you had. Can you explain the basis of that liability? Who it was payable to and why? Again, we are new to the investment and want to understand all the instances of money going out and obviously that was one we couldn’t explain or understand.

Let me try to walk you through that. We paid a significant amount to the platform owners where we own the leases out there. That was required to be paid to in essence keep the leases in place during the litigation. We also paid some royalties to a number of investors that loaned the company money more than 8-10 years ago. They took an override underneath that arrangement. Those were primarily related to a couple of former executive officers and a couple of outside investors.

Then that liability and those payments have been fully paid off now?

They sure have.

Can you explain the difference, in calculating your total shares outstanding it would look at your balance sheet and 10-Q and I see $275 million but then the weighted average shares outstanding we are dealing with 282 million. So there is a decent amount in there. Do we have options given our lower stock price…do you have options and other dilutive instruments that were issued while things were even lower?

No.

Not at this stock price.

There were no options. We haven’t granted options over a number of years. The weighted average is just based on the length of shares issued later in the quarter would have a larger effect on the weighted average calculation.

In Q1 there was an issuance then?

There was an issuance at the end of December that was material.

[inaudible] to 275. We will go through that with Broc.

There were some grants to the directors at the beginning of Q1.

I don’t think that explains it. How do we best understand your short-term and long-term restricted deposits and why each remains at $100 million on your balance sheet as such? What are those for?

We are required to make a $100 million payment relating to an acquisition we did with Encana and each November 1 we are required to pay $100 million. So as we make that payment in November you will float from a long-term liability to a short-term liability. So the total obligation is still $200 million of which $100 million is due November 1, 2010 and the remaining payment is due on November 1, 2011.

That had a four-year term on it and it is about half way through. Pushing the third year.

You are limited on what you can say but you did say the process on the big sale here is going well. Can you at least explain why you feel and say the process is going well?

No. At this point in time, you will have to appreciate our sensitivity until this thing is closed but we really think it is prudent that we not comment at all.

Alright because you put the little spin on it that it was positive so I was trying to get support for that. Lastly, this big transaction is part of the strategic alternatives process. You had mentioned the new debt facility would be resolved after the joint venture deal was resolved. That is understandable. But there are costs associated with the strategic alternatives process. Other than this joint venture and the refinancing there are other things the alternatives process is looking to do. You have other assets. Do you have a handle or an estimate as to I guess milestones and the timing of the conclusion of the strategic alternatives process and its costs as well as when other items get presented to the board? For example, when does the board next meet or when is the next strategic alternatives process presentation?

As we already commented we can’t go further into the strategic alternative process. Obviously it continues to move forward. We are looking to get successfully to a close but in terms of timing and specifics we cannot comment further.

The next question comes from the line of Gregg Brody – JP Morgan.

On the revolver, the redetermination at the end of the quarter what is driving that? Is that the process of the strategic review? Is there something else there?

No that is pretty much it. They obviously want to look at our facility post the joint venture with Opon and just want another look at it at that time.

Operationally, from the rig business and just in general what are you seeing in terms of drilling costs and in terms of price pressures across the different aspects of drilling?

Well in the Vega area because we are not drilling we don’t fully understand that. Having said that, the Rockies in general are not seeing the increase of drilling activity that some of the other shale plays have seen. I think there has been a further reduction in third-party service costs the last 6-9 months. I don’t think it is as meaningful as we saw in 2009. If you are asking are we expecting oil costs to increase the answer is no. We expect because the shale plays are generally requiring specific types of drilling rigs and specific types of third-party services those that are remaining in the Rockies are basically pretty hungry and looking for work. So we think it is a good environment for drilling. Having said that we are not monitoring other parts of our asset base because that is the only focus we have right now; drilling and developing the Vega asset.

Does the DHS, you said you are up to 10 rigs,. Are you on the verge of selling any more rigs there? Or are you relocating any?

We will be up to 10 by July 1 is what I said. We have had a pretty good run here over the last couple of weeks on getting some things under contract. We continue to look at selling a number of our rigs to pay down our debt but really we haven’t been very successful in that yet.

The next question comes from the line of Evan Templeton – Jefferies.

Looking through capital expenditures for the period that was about $10 million on oil and gas properties. It sounds as if your actual completion activity was pretty limited. Can you give me a breakdown of where that spending was allocated?

Well we had roughly 1/3 of that in the Garden Gulch deal which is operated by [inaudible] in the Piceance Basin. Very similar to Vega in its makeup. Then about 1/3 of it was spent on the completions and another 1/3 of that was spent in infrastructure costs in the Vega area in preparation for the joint venture.

Based on current pricing what sort of returns are you seeing out of those Vega wells you drilled? What do you anticipate?

You mean flat price basis?

Yes. Actually both. If you have a comment on both that would be helpful.

I could have a generic comment. I can tell you it is not as price sensitive as you might think given the Rocky Mountain differential has decreased so far. But having said that $4 NYMEX or $3.75 CIG is profitable but relatively tough but we can make money at it. The forward curve and the forward CIG curve has fairly robust economics over time. Because of our new contract renegotiation and now we have a large portion of our liquids we retain out of our marketing contract in the Vega area that has significantly increased our profitability and actually we have seen revenue that equates to the CIG curve for all-in costs. So the forward curve looks great. Current prices are fair.

It sounds like you are being helped by then the additional liquids recovery giving you a little bit of a return?

Yes the contract is extremely profitable for us right now.

This concludes today’s question and answer session. I would like to turn the conference back over to management for any closing remarks.

Thank you for listening in on the call. Obviously we are hopeful we will have more meaningful news concerning the joint venture process in the near future. Hopefully at some point in the future we will be able to comment more on the completion activity and the results there from in our Vega completions in the future. Thanks for joining us. Have a good day.

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