Good morning, and welcome to the Delta Petroleum First Quarter 2011 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Broc Richardson. Please go ahead, sir.

Thank you, everyone. And thank you for joining us for Delta's first quarter 2011 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 that this call will include projections and forward-looking statements within the meaning of the Federal Securities laws and are intended to be covered by the Safe Harbor protections. In that regard, you are referred to the cautionary statement displayed on Delta’s website, which is incorporated by reference with respect to the information provided for this call. Investors are urged to closely consider the oil and gas disclosures and the risk factors set forth in Delta’s Form 10-K for fiscal year ended December 31, 2010, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K, respectively. Today's speakers from Delta are Dan Taylor, Chairman of the Board; Carl Lakey, President and Chief Executive Officer; and Kevin Nanke, Treasurer and Chief Financial Officer. I will now turn the conference call over to our Chairman, Dan Taylor.

Thanks, Broc. Good morning, everyone and thank you for joining us. As I'm sure many of you have noted, over the past few months, there has been a renewed and increasing interest in the Piceance Basin driven by increasing recognition of the revenue from natural gas liquids and drilling success occurring in the deeper shale formations. In a recent report published last week, an analyst stated that the wells drilled by a nearby competitor rival Haynesville wells and provide indications that continued development of the Niobrara may dramatically change the economics of Piceance development. The analyst noted that the Niobrara is located at shallower depths in the Piceance than in the Haynesville and thus, the well cost is less, which combined with similar initial production rates equates to better economics. As Carl will discuss, the indications of our wells to date support this preliminary conclusion. We have initial production from the 2B well and expect higher rates from the 2C well, which is all of the pay of the 2B well plus an additional 2,800 feet of gross interval to complete. I believe our strategy to dedicate all our efforts in capital to the Vega Area was a correct one and is being validated with the results, not just from our wells, but from other operators as well. As mentioned in our press release, we have decided to market for sale our non-operated properties in Texas and the DJ Basin in order to raise capital to drill 2 additional wells in the Vega Area targeting the Mancos and Niobrara shales. These 2 additional wells to be drilled are wells that will hold leasehold so they will be accomplishing two objectives: First, to continue to quantify and confirm the reserves and economics of the shale formations; and second, to secure our…

Thank you, Dan. Good morning, everyone. Thank you for participating. Delta did have another strong quarter. The focus on our core assets is being validated in the numbers. The improvement is related to numerous items, which Kevin will share with other financial metrics shortly. As proud as I am of these financial results, I really want to share why we are so excited about our shale wells. As we've announced previously, the information we have gathered to date continues to raise our expectations on the resource that exists in the shales of the Williams Fork. In fact, we believe the resource will exceed that of the Williams Fork and our field, and based on our findings and other published information, perhaps across much of the Piceance Basin. The 2B wells drilled through a portion of the Mancos formation have reached a total depth of 10,700 feet. We've completed roughly 1,200 feet of gross pay in the upper Mancos and Corcoran formations only. This represents only 33% of the shale play identified in the 2C well. Gas production began in April 24, and the well was flowing 3.3 million cubic feet a day by April 29. Through May 9, sales of average 1.8 million cubic feet per day. It is early in the clean-up process as well recovery from the frac stimulation is only 27%. The well has had the opportunity to produce up to be for only the last 4 days. The Williams Fork section in this well will not be completed until more production information is gathered from the Mancos and Corcoran formations. While still very early in the life of this well, it seems clear that Delta has a discovery in the upper shales. With respect to the rest of the shales, the well drilled on path 2C…

Thank you, Carl. Good morning. EBITDAX from continuing operations increased to $8.8 million, an increase of 19% from Q4 2010. After adjusting for the one-time benefits of $1.2 million in Q4 related to a production tax true-up and transition fees earned on the sale of properties. The EBITDAX increase is primarily a result of higher commodity prices, increased production and a continued focus on maintaining cost control on our core asset. For the first quarter, we reported production from continuing operations to of 3.5 Bcfe, an increase of 4% to Q4, but slightly under what we expected. During the quarter, we completed 3 of our 5 remaining Williams Fork inventoried wells. We anticipated completing all 5 however, with limited frac crews and a focus on the shales, we decided to leave the 2 completions for a later date. Our natural gas liquids currently represent approximately 1/3 of our revenue from the Vega Area. To put this number in context, the extraction of the NGLs from our gas stream only reduced our MMBTu content by approximately 15% and the current prices of the NGLs are far in excess of what the revenue would be if capital is in the gas production. This is evidenced by our realized price per Mcfe. In the first quarter, our total realized revenue before hedges for the Vega Area was $5.55 per Mcfe whereas the average Henry Hub spot gas price for the quarter was only $4.18. Moreover, our realized price was reduced by the differential of the Henry Hub to Colorado Interstate Gas or CIG of a negative $0.17 for the quarter. In essence, our liquids and condensate combined to provide us an equivalent price for a production that is roughly 38% over the CIG benchmark for the quarter. Our lease operating expenses per Mcfe…

[Operator Instructions] The first question is from Joe Allman of JPMorgan.

In terms of the deeper wells, the B and the C, could you give us the cost of those wells and what's your expected costs going forward?

On the 2C well, we're expecting still around $10.5 million. The 2B well is -- A or B, they're just under $5 million. We believe in subsequent attempts, including this well, we're about to spread in the Sheep Creek Unit that will go all the way to the depths experienced in the 2C well that we can see that A and B come in around $8 million is what we're targeting.

Okay, that's helpful. And then In terms of the feet of pay you're seeing, I know you gave gross feet. I think could you give us a net on the 2B and then on the 2C? I know you only drilled some of that, but of what you drilled, what's the net to gross there?

Really, when you look at these shales on the logs, the entire section is hydrocarbon-bearing and really, the net to gross is just almost 1:1. I mean we're not high grading the shales to any material degree based on log signature. All of it seems to have hydrocarbon in it, all of it seems to be attractive. Some of it has better rock mechanics properties and others. But all of it seems to be hydrocarbon-bearing So when we go to stimulate, we're intending to basically stimulate the entire section.

Okay, that's helpful. And then In terms of EUR per well, what your expectations there with what you drilled already and going forward?

Still too early to say. Obviously, once we've established the decline curve off these wells, we'll have a much better indication of what that looks like. But it's a little premature to say. There is some public data out there on other wells that competitors have drilled on the basin where EURs can be established from that. And I'm not prepared to talk about their wells here. But suffice to say, we think they're encouraging.

And then just what would you consider the main differences between sort of the geology where you are versus nearby industry activity?

Well, to be fair, as we look at our intervals, we just have not been able to see any place else in the basin where the section is overpressured and hydrocarbon-saturated from the top of the Mancos all the way to the bottom of the Niobrara. And so we think we just have more pay than any place else we've been able to identify. We have seen some logs in other areas and other portions of the basin that suggest a little lower pressures or hydrocarbons that are more productive or more suggestive of production in the deeper parts of the Niobrara, but not across the entire section like we have.

Okay, all right. Very helpful.

The next question is from Gregg Brody of JPMorgan.

You may mentioned that the borrowing base would potentially decrease if the asset sale is completed, can you give us a sense of how much of the borrowing base those assets represent?

Gregg, we don't have that information yet. We're still working with Macquarie and we'll identify that here once we move down the path with the transaction.

The one thing we'll point out is obviously we believe we will improve our liquidity as a result of the transaction based on our estimates of borrowing base impact.

Okay, that's helpful. Do you happen to have a production or reserves for those assets?

No. Year end, roughly around 11 Bcf, and current production, we had about 0.5 Bcf produced for the quarter.

Okay. Is that mostly gas?

No, that's mostly oil in the Gulf Coast. Probably on the order of 70%, maybe a little higher than that. That's oil.

That's very helpful. And then just one follow-up question, I guess the acreage that you've identified, that's perspective for the deeper zones, how much acreage do you think kind of fits that potential?

Well, our Vega acreage position in its aggregate is about 22,000 net acres and we believe all of it is perspective for the deeper shales. In fact, those 4 wells that I mentioned earlier in the call will basically stitch across section demonstrating productive shales east to west across our entire acreage position. We feel confident that we could do the same thing north to south it just so happens that acreage holding dictates that we'll drill on an east west orientation first to secure our acreage position.

The next question is from Andrew Shapiro of Lawndale Capital Management.

A few follow-up questions off your script and just prior question there. First off, should we expect further reductions in stand-alone test G&A from Q1's levels or are we at a stabilized phase or should we expect increases?

Andrew, I believe the second half of 2011, you can see some decreases in our G&A. I think for second quarter, we'll still come in at below $4.5 million for the quarter. But hopefully, we can make some improvements on the latter half of the year.

Okay. And then regarding the newly announced sale of properties in Texas and you call it the DJ Basin, where is this asset by the way? Would these assets be sold together with the Texas assets?

Okay, there's actually three distinct properties that are part of the package, two of them are in Texas, one called Midway Loop in Polk County. The second is the Newton Field in Newton County, that's a Wilcox oilfield. And then finally, a smaller property we call Golden Prairie in the DJ Basin in southeastern Wyoming.

Okay. So that's far enough away that may not go in the same sale.

We expect it probably will, but certainly we'll let the bidding process and offers dictate how that goes.

How long of a process do you envision for this asset sale? I mean, are these complex thus requiring a lot of time to sell?

Yes, just before the end of June is what we're targeting.

Okay. And then regarding the DHS sale, as a 49% shareholder, to what extent are you involved in the acceptance of the price that they choose to monetize it in? And based on last quarter's call, the process started March 1 or earlier, where does that process stand and what are the bidding milestones left and expected timing of determining the winning bidder is on the DHS sale?

Andrew, this is Dan. I'm going to address your global question first and then Kevin can talk about the specifics of DHS. It was only recently that we actively moved forward on this process and there have been a number of different structures that we have considered. As Kevin mentioned during his comments, it was a multi-rig bid as well as a full company asset profile bid. Those have evolved and we've got people looking at these assets. And we also have to deal with our lender in connection with these assets as well because as you know, we have a forbearance agreement in place on our loan. So the goal here is to now finish the process in a rather efficient manner. We think we've seen all the opportunities and our lender is working with us on this.

Yes, Andrew, the process, the due diligence process is underway. We have spent some time out in the field looking at all the rigs. We're going through that process right now. I think they'll come back to us over the next couple of weeks and give us their final assessment. If they move down a smaller rig package, we do have other groups that are interested in the remaining rigs. And like Dan said, we are working with our lenders during this process.

Okay. And a final question, you've talked about a little bit of this last quarter as well, but you can maybe give us an update and also if these new deeper wells have any implication. What's the status of your water disposal permitting activity and your water disposal capacity as you were starting to, I guess, put the water in used-up wells and such?

Sure, Andrew this is Carl. We've got 2 wells taking water right now at about 3,500 barrels a day, that's against our total water production of about 4,200. So we're essentially at breakeven right now. We expect 2 additional wells for conversion to be permitted by the end of the second quarter and we'll bring those online, which is over the top to be able to handle all of our produced water to injection of our inventory wells.

And does your demand for this activity increase with the new deeper well drilling you're doing?

No, it does not. In fact it goes down. What we're seeing on the shales, is that the shales relative to Williams Fork are very dry in terms of produced water from the formations. So we'll expect to see less water production going forward as our Williams Fork wells that were completed in the fourth quarter and the first quarter produce some of their load back. They're still having residual load and that water production will decrease as we go forward.

Great.

Next is another question from Joe Allman of JPMorgan.

Just in the Vega Area, your lease expiration, can you just describe the acreage that you got held already. And how much is not held and what's the timetable of the expiration for that?

Clearly, we've got out of the 22,000 acres, we've got 2 blocks that we're considering holding together this year that are material. The first is we formed the federal unit called the Sheep Creek Unit late last year on the northeastern flank of the acreage, that's about 3,700 acres. And the BLM has agreed with us that if we spread a well in May, that will hold that acreage together. So that's first and foremost, we'll begin spreading that well next week. So that's well in progress. The second piece of acreage that we have that's at risk of expiry this year is in that Section 17 area kind of in the West Central portion of the field and it's not nearly as much I want to say it's about 480 acres, something in that neighborhood. So it's not nearly as substantive an acreage position and its expiration would be in September of this year. And so we're targeting potentially spreading that fourth shale well in August.

And then what's the status with the expiration of the other acreage?

Most of the other acreage is really not too bad. We're going to be in good shape. By the time we get done with the Sheep Creek unit, 93% of that acreage position will be held by production or held by unit. And it strings out over the next several years for the remaining bits and pieces.

Okay, that's helpful. And then in terms of infrastructure, so if you do produce oil or condensate here, do you have the infrastructure in place to handle that? And if not, what do you need to do to provide that?

No, we're well positioned. In fact, one of the nice things about the shale play is the infrastructure was already laid in place for the Williams Fork, and by using that infrastructure to move the gas, we're well positioned to handle it. So from an infrastructure standpoint, it's almost the build up.

And including the higher pressures that you might be seeing from the deeper?

The higher pressures are handled well-head equipment and separators and chokes, very near the well head. That's not the largest part of the infrastructure piece. In fact, it's a relatively modest piece.

That's helpful. And then just on the prior question, what's the timetable on those two new water disposal wells?

We'll certainly have one of them going in the second quarter and then the next one is kind of we expect to have a permit back whether the well will be injecting in the second quarter remains to be seen, but certainly on or about the end of the quarter, we'll have the second one on line.

Okay. All right. Very helpful.

[Audio Gap] This concludes our question-and-answer session. I would like to turn the conference back over to Broc Richardson for any closing remarks.

I'll turn the conference over to Carl for closing remarks please.

Thank you so much for attending our first quarter conference call. You can see why we're excited and we're very pleased with our performance and we look forward to sharing more with you in the future. Thank you.

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