Hello and welcome to the Delta Petroleum second quarter earnings conference call. All participants will be in listen-only mode. (Operator Instructions) After today's presentation, there will be an opportunity to ask questions. (Operator Instructions) Please note this event is being recorded. I'd now like to turn the conference over to Broc Richardson. Mr. Richardson, please go ahead.

Thank you for joining us for Delta's second 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 that this call will include projections and forward-looking statements within the meaning of Federal Securities laws and are intended to be covered by the Safe Harbor protections. In that regard, you will refer 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 consider closely the oil and gas disclosures in Delta's Form 10-K for fiscal year end December 31, 2009, 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 CEO; and Kevin Nanke, Treasurer and CFO. With that, I will turn the conference call over to our Chairman, Dan Taylor.

Thanks, Broc. Good morning, everyone. As we announced last week, we have closed on the sale of non-core assets for cash consideration of $130 million to Wapiti Oil and Gas. We received approximately $112 million of the proceeds on July 30. The remaining $18 million is held in escrow, pending required consents, which we have no reason to believe, will not be received. As stated in the press release, the proceeds have been used to reduce borrowings under credit facility. While there were some assets sold in this transaction, we would have liked to have retained, the fact of the matter is that we simply did not have the adequate capital to develop those assets. Combining that with our need to address our near-term credit facility balance and maturity, the asset sale was necessary. Kevin will discuss further the senior credit facility in his comments. The asset sale was the result of a competitive process and part of the strategic alternative process previously announced and discussed. This process has now been concluded and the company will focus on creating value with its core assets through operations. The Board of Directors will, of course, re-evaluate the renewal of this process at a later date. During the quarter, we completed one well in the Vega area. The results of this well in addition to other wells completed in prior quarters have been very positive, in fact, better than expected. Carl will discuss these completions in greater detail in his comments. At the closing of the asset sale, the efforts of Management are now directed to refinancing our senior credit facility, which matures in January. As stated in our press release, our revolving credit facility borrowing base was re-determined downward to $35 million after the asset sale. It should be understood that our asset base supports a conforming borrowing base much larger than $35 million, but given the short duration until the maturity of the facility, we agreed that a lower number was acceptable. Kevin will discuss the status of our refinancing efforts in his comments. As was announced last month, the Board of Directors named Carl Lakey Delta's Chief Executive Officer. Carl was the clear and unanimous choice given his experience and the Board's desire to refocus Delta's efforts towards its operation. Carl is proven to be a very capable manager and leader not only during his tenure here at Delta, but also previously in his career when he managed operations and budgets much larger than those at Delta. We have full confidence in his ability to direct this company in a way that creates value from our asset base. With that, I'll turn the call over to Carl for his comments on operations. Carl?

Thank you, Dan. With the closing of the Wapiti transaction and the resulting improved liquidity created for Delta, the company will now focus its efforts on operational improvements of the company's core oil and gas assets. Before I describe the path forward for our focused Delta Petroleum, it should be pointed out that Delta will be reorganized in light of the new post Wapiti property portfolio to best position our intellectual talent to execute our plan. Part of that reorganization will result in a smaller workforce proportional to our remaining assets. Delta has already undertaken two prior reductions in workforce. Our current team is very talented and accomplished in their skills, making this part of the plan even more difficult. We expect that many of our field employees will transition to Wapiti to assist them with the continued efficient operations of those assets. Overall, Delta's salary and benefits costs are expected to be reduced by roughly one-third through the changes anticipated in this restructuring after the associated cost with severance. The need to pursue liquidity has limited the company to conducting only modest investment activity in recent quarters. However, the results of those modest investments are noteworthy in their significance to the company's future direction. Late in 2009 and early in 2010, the company began modification to its completion design in the Vega field. Three wells have been fully completed using this revised process and the results have been better than expected. The new stimulation procedure adds an incremental $500,000 of cost to the Vega well, but also improves its expected recovery to roughly 1.7 Bcfe. I will caution that these results are preliminary and were derived from only three wells, with the oldest having a production time of only nine months. With that said, Delta's immediate plans are to efficiently complete the remaining 15 inventory wells using this new process. As we gain a more significant statistical understanding of this recovery potential, we'll provide additional updates. Importantly, as Dan earlier mentioned, the company will also be focused on a parallel effort to the Vega activity to refinance our senior credit facility, which expires in January 2011. Progress has already been made in this effort and Kevin will provide additional information in his remarks. With that plan in mind and sufficient liquidity to execute that plan, we feel it's appropriate to provide production guidance for the remainder of 2010. As stated in the press release, our second quarter production was just under 4.7 Bcfe. We expect the third and fourth quarters’ production to total between 6.9 to 7.2 Bcfe. I'll now turn the call over Kevin Nanke, our CFO, for a discussion of second quarter financial results.

Thank you, Carl. Good morning. I'll take a few minutes and walk through the Wapiti transaction and how the sale impacted our quarter. The accounting for the Wapiti transaction was a little unusual. At June 30, the assets sold to Wapiti qualified as assets held for sale. Assets held for sale are required to be recorded at the lower of their net book value or fair value on a field-by-field basis. This resulted in an impairment of approximately $96 million in the quarter. Gain contingencies, however, are required to be recorded when certain or at closing with this transaction. As such, we will report a gain on the sale of assets of approximately $29 million in the third quarter. Combined, the transaction will result in a net loss of $67 million. The results for the assets in the Wapiti transaction in which we sold 100% of our interest have been recorded in discontinued operations, while the results for the assets in which we sold less than 100% of our interest remain as a component of continuing operations. We've included a summary reconciliation for production in the back of the press release. For the second quarter, we reported production of 4.7 Bcfe, of which 1.3 Bcfe was attributed to the assets sold in the Wapiti transaction. EBITAX for the quarter was approximately $7 million. The increase in cash G&A for the second quarter is primarily due to costs associated with the strategic alternative process. As Carl mentioned, we expect cash G&A to decrease once the transitional period is finalized with the asset sale. In conjunction with the asset sale, we amended our credit facility. Our borrowing base is now $35 million and we will have no redeterminations through the facility's maturity in January of 2011. Our capital expenditure limitation of $28 million for the remainder of the year is sufficient to complete the planned completion activity Carl described earlier. We were in covenant compliance at the end of the quarter and are projecting to be in full compliance for the remainder of the year. As Dan mentioned, we are seeking a new senior credit facility that would replace our current facility and provide us the flexibility to renew our drilling program. We are in discussions with multiple prospective lenders and believe we will reach an agreement and closing by the end of the third quarter. As a result of the Wapiti transaction, we will be overhedged on our oil hedges for the remainder of 2010. The effect of the overhedge position materially impacts our EBITAX and cash flow. This exposure will be addressed in the new facility or soon. With that, we will open up to some questions. Thank you.

(Operator Instructions). The first question comes from Andrew Shapiro from Lawndale Capital Management.

Hi. Two questions if I could. Your press release and your comments today opened up with the concept that your strategic alternatives process is now complete and you're going to focus on your operations. So I had a question or two here about what does that mean with respect to a few items. First, with respect to the current Q3 and Q4 G&A expenses, you've said in the press release today that your Q2, you current quarter G&A expenses were up $2.6 million higher than last year. And the $9 million rate you had been at primarily due to the alternatives process itself. So I'm trying to get a feel for how much G&A expense might fall out from the current run rate and then evaluating your description here that about – is it one-third of your current G&A would further get cut as a result of downsizing post Wapiti sale? Does that question make sense for you?

Yeah. Let me see if I can try to answer that. I think what we're projecting is our reduction in salary, after you've paid all of the severance payments that we'll be obligated to do in the downsizing our cash, salary and benefits should be reduced somewhere in the order of about $4 million. Additionally, what you have in the second quarter or over the first and second quarter is approximately $2 million in what I'll call non-recurring strategic alternative costs.

Okay. And then there's an expense of about how much that was in the non-cash – I would think is that non-recurring or is that the amortizing stock expense?

Well, the non-cash is – a portion of that will also be non-recurring relating to the individuals that will not be here in the future. However, there will be some component that will probably be adjusted for the – within their severance agreement.

And will the severance charges that you speak of when we say okay, there's about $4 million SG&A going forward post the severance. Is that all going to be taken as a third quarter event or is it third, fourth, or spread out even longer?

Well, I would presume that would all be done within the third quarter.

Okay. So then like starting Q4 could be doing around a $4 million G&A run rate?

We should have a clean fourth quarter, assuming the transitional period ends with Wapiti, which is scheduled during the third quarter, yes.

And now does the Wapiti sale complete the sale of all assets that you deem to be non-core or are there other assets your process identified that are non-core that are still being marketed for sale?

Well, we're not marketing any properties at this time. I would probably say that the remainder, the 50% remainder of our Gulf Coast assets would still be considered non-core going forward.

Okay. And when you say the Gulf Coast assets, is that Newton and Midway Loop?

Primarily, yes.

Okay. And so did you only desire to sell a portion of them and can you explain what goes into your strategic process thoughts at retaining the other half or was that all that Wapiti wanted and you desire as you called it non-core to possibly sell the rest?

Andrew, this is Carl Lakey. As we looked at our strategic alternatives, the properties in the Gulf Coast, particularly Newton and Midway Loop, were a more oily component of our production stream. And we wanted to retain exposure to that oil price and the cash flow generated by those oil properties and that's why we wanted to retain half of those properties going forward.

Okay. But they may be longer term non-core for a variety of other reasons?

That is correct.

Okay. But otherwise, the sale to Wapiti completes it all as you or the CFO just mentioned. But are the Vega assets that previously were to be sold to Opon, are they being remarketed to the runners up or other parties or it was just that the price was so good that this was a prime asset you were willing to part with because of the pricing, but otherwise you're keeping 100% of Vega?

Maybe the way to say that is we have viewed and continue to view Vega as a core asset for the company. The previously contemplated joint venture agreement was a way to accelerate development of that asset and that's why that was being contemplated. The strategic process we just went through with Wapiti was a monetizing event to solve near term liquidity.

Got it. I'll get out of the queue. I do have a few more questions. So hopefully you can let us back near the end.

Thank you. The next question comes from Jim Liu [ph] from J.P. Morgan.

Hi, this is Joe Allman.

Hi, Joe.

Hi. Just a couple questions, I apologize if you’ve covered this already. CapEx for the second quarter, what was capital spending for the second quarter and then what's your plans for CapEx for the rest of the year including the completions of the wells that you plan to complete?

I'll answer the first, the first part, we spent around $10.5 million in CapEx in Q2.

And in terms of Q3 and Q4, currently we've got covenant in terms of CapEx spending with the current borrower for $28 million for the second – for the third and fourth quarters and we expect to be able to live within that.

Okay. But you do expect to spend roughly $28 million?

Not necessarily. That's going to be opportunity dependent.

Got you. And then the CapEx of $10.5 million, if I'm not mistaken, I think you completed one well in the second quarter. So how did you spend that $10.5 million?

There were spends in other areas. We finished the water treatment plant in the Vega area or at least substantively finished the water treatment plant in the Vega area, that consumed some of our capital. We drilled and completed a well in the DJ, actually the completion, I think, only was second quarter, the drilling was first quarter.

Yeah. We brought on another well in the Garden Gulch asset and had some additional CapEx through Berry and the Garden Gulch asset, about $4.5 million was spent there during the quarter.

Okay. And then how many wells would you expect to complete at Vega in the second half of the year?

We have got 15 wells in inventory. And ideally, we would like to complete all 15. With that said, we've seen tightening in the fracture stimulation market of service availability and that service availability may impact the timing of those completions.

Okay. Great. And then the new completion technique, could you just describe that fully for us? What is the change?

I think the biggest change is when we've looked at Vega in the past, it's a stack sand in the Williams Fork. And we've always looked at those sands with traditional log cutoffs, 6% to 8% porosity and so on and so forth. And I think what we're learning in the Piceance Basin is some of what's been learned in other parts of the shale plays around the country, that there are other rocks that don't meet conventional log cutoffs that also contain hydrocarbon product. Specifically I'm talking about shale, silts, and coal. They don't calculate as pay, but they certainly hold hydrocarbon and they certainly contribute to pay. And I think what you're seeing now in our revised completion technique is a much more aggressive inclusion of these non-traditional reservoir rocks in our Williams Fork completions.

Okay. So it's inclusion of other zones or formations?

Well, it's inclusion of other rock that we had previously deemed as non-pay.

Okay.

Because it didn't meet conventional log cutoffs and now we're looking at that rock as just part of the entire gross pay section.

And you extract the gas from there by just more intense fracs?

Essentially, more fracs over the same interval.

Okay. Thanks. Okay, great. And so then that bumped up the EUR up to 1.7, just the inclusion of those additional rocks?

That's fair.

Okay. Got you. Great. Thank you very much.

Thank you.

Thank you. The next question comes from Gregg Brody from J.P. Morgan.

Good afternoon guys.

Hi, Gregg.

I wanted to touch on the revolver. You mentioned that the current size is smaller than your actual potential borrowing base. Could you give us a ballpark idea of where you think that is today, the borrowing base based on the price decks the banks are showing to you?

Yeah. Well I think – I'll come at it a little different way. With the new lending group, we're looking at putting a facility in place somewhere in the order of $50 million to $75 million and I think that's somewhere in the ballpark of where it should fall out.

Okay. Are you contemplating additional financing to potentially address the convert as well?

In due time we absolutely understand the timeframe that we're under and we'll address that probably shortly after we put the new facility in place.

So your lenders are comfortable lending you money, providing you a revolver that matures after the potential putting of the convert?

No. What I would say is most likely, the new credit facility would have some type of like accordion feature that would have a maturity prior to the converts and if, once we solved for that convert it will spring and allow additional time afterwards.

Okay. And just bigger picture, how do you think, what do you think will address the converts?

We will not probably address that at this time on the call.

Okay. Just you mentioned on the capital costs for the new drilling method, you mentioned it was $0.5 million additional for costs. What's the cost to complete each well?

Give or take, a little over $1 million.

$1 million, in today's environment what would you think – what would estimate that would cause you to drill and complete a well?

I'll give you two numbers. I think, if we were in a program drilling mode and to get some of the efficiencies of continuous activity, $2.1 million seems attainable. If we're drilling one-off wells to hold acreage, we’d contemplate numbers on the order of $2.4 million.

That's very helpful. And just, you – what was your asset rate from the quarter production-wise and could you give us a sense of the mix of gas and crude?

Exit rate for the prior 30 days was roughly 42 million cubic feet a day of which, let me work that out, I want to check that in a minute. We'll have that for you, if you want to go to the next question.

Sure. I think that is it for me for now, but I'll come back if I think of anything else.

(Operator Instructions) Our next question comes from Evan Templeton with Jefferies.

Hi. Just two questions, I guess, just first, can you just give us an idea of what the current reserve profile is in terms of proved development component, proved undeveloped percent natural gas?

Say that again?

Just the breakdown of reserves, what the PUD component is currently, pro forma for the sale?

We will not give reserves on a quarterly call at this time. However, I will tell you that the PUD reserves in the Vega, assuming you have adequate capital, will run.

I'm sorry. I think something cut out. They will run?

They will be included in proved reserves at the current commodity price environment, yes.

Okay. Got you. And then, I guess, just a second question is, what's the maximum amount of secured debt that the company is allowed currently under the nature, I guess in the sovereigns, is it $125 million?

I believe, yes, its $125 million.

Okay. Thank you. That's it.

Thank you. And we have a follow-up question from Andrew Shapiro from Lawndale Capital Management.

Yes. While the Wapiti sale closed on August 2nd, according to our reading of that purchase and sale agreement, the effective date was quite different, whereby it looked like Wapiti received the net business in assets acquired way back to May 1st. Can you confirm this and how does this play out into your Q2 income statements and balance sheets?

That is correct. The effective date was May 1st and all of the activity from in essence May 1st through July 31st will be recorded as a purchase price adjustment, so it will run through your balance sheet. I will tell you that the net effect of that activity along with the cash calls prepaid in effect at that particular time was basically a wash.

Okay. And then in Q2 and press release for your metrics that you gave out, does your production numbers include any of the Wapiti assets? Does it include the Wapiti asset productions up through May 1st or through the whole quarter? How does that work out?

Yeah. That’s – you're required to record all of the revenue within the quarter until you actually close. So if you go look at the back of the press release, we breakout the production that was associated not only in discontinued operations but the component also in continuing operations.

Right.

That amount was 1.3 Bcf, which is in essence Wapiti's share of the production during the second quarter.

Right. Which puts you at net of 3.4 Bcf for the quarter on the assets that are ongoing, right?

Yes.

Okay. So when it says 3.9 later on, in the total production continuing ops in your table, I'm just trying to reconcile that.

Isn't that a six-month number?

Second quarter production volumes, unit prices and costs, three months ended June.

Okay. The 3.9…

Yeah.

… would be the net equivalent…

Grossing up for the oil?

That is our net equivalent of Delta going forward.

Okay.

Actually, the 3.3 is the net Delta going forward production.

You mean 3.4?

Bottom line, yeah.

Okay. Now, do you expect to announce an 8-K when the escrowed monies are finalized and received or that's considered material enough?

Probably not.

And how long does the escrow or consent process then expect it to take? You expect you're going to close and everything will be fine and you aren't going to announce your 8-K yet?

Well, the dollars have been collected but they're held in escrow and the consents cannot be reasonably withheld. So we expect to have those by the end of August or shortly thereafter.

Okay. The balance on the three and three quarter notes on the balance sheet is rising. Shouldn't it be flat or is that for accreted interest, what is that?

It's accreted interest, yes.

Okay. Now, can you help us reconcile the drop in proved oil and gas properties from $1.3 billion in Q1 to $944 million in Q2 as to what relates to the Wapiti sale or reclassification to assets held for sale and what relates to impairments, and is there any third or fourth other major adjustment that brings that balance down?

Can you repeat that question? I think it would probably be a better question for an offline conversation with myself or Broc.

Okay. I'm trying to reconcile your drop from Q1 to Q2 in your proved oil and gas properties from $1.3 billion down to $944 million.

Well, in general, the impairment will be the largest component of that that we were required to take during the quarter.

Okay. And can you discuss what this over hedge issue means and its benefits and/or risks and is it only risk?

Well, it clearly goes both ways with the fluctuation of oil and gas prices. I guess from Delta's standpoint, the risk of a downside is probably too great for us to keep that exposure and therefore it will be addressed in the new credit facility. As commodity prices increase, it will lead up our cash flow.

So, we are right now committed to provide more oil and gas than we have the capability of providing, is that it?

That's correct. Yes. Because we sold it to Wapiti.

Right. But when we sold them forward, we sold this forward we sold it forward at favorable rates up in the 5s, right?

Well, that's the gas component.

Yeah.

We're more worried about the oil component under this scenario.

Okay. Great. Thank you.

Thank you.

The next question comes from Kevin Cabla from Raymond James.

Good morning, guys. I only have a couple of questions just some clarifications. With the production guidance you have for the second half of the year, does that includes the assumption that you complete all 15 wells?

I think actually that number was go with 13 of the 15 being done…

Okay.

… at the end of the year.

And reading through your 10-Q, I saw something about may initiate a drilling program at the very end of the year, is that something that was just kind of thrown up in the air or what is the status on that?

No. Here is the issue with that. Over the next 18 months, Delta has roughly 10% of its lease hold in the Vega area that will exit primary term of the leases, okay. And so we're faced with the prospect of seven wells will hold essentially 90% of the lease block. We can either do limited drilling to hold that acreage position together or we can renegotiate some leases.

Okay.

And so we're allowing for the possibility of either scenario to play out.

And that doesn't come into play until early to middle 2011.

Okay. And I just want to make sure I understand this correctly. Pro forma for the sale, you guys have $40 million in liquidity between now and January 15th, you can spend a total of $30 million. So are you guys projecting to have sufficient cash flow after implementing your CapEx to pay down the rest of the credit facility?

Well, we actually anticipate having a new facility in place.

Okay. That's what I was trying to get at.

You'll have cash flow to help offset that, but yes, we will either reduce CapEx or have a new facility in place.

Okay, okay. That's all I got. Thanks guys.

With that being said though, on a pro forma basis if we receive the remaining $18 million from escrow, we’d be substantially paid down today.

Right. Okay. Thanks guys.

Thank you. We have a follow-up question from Gregg Brody with J.P. Morgan.

Hi, guys. Just on the all lease side, what's a good run rate going forward and does the water handling cost, is that something you expect to continue?

No. That's one of the ancillary benefits of resuming completion at the Vega. We've got some temporary storage water handling facilities out in the field and those as we resume our CapEx program will be fulfilled into the completion cost of the wells rather than a run rate on LOE. So we do expect some improvement in the LOE simply from resuming completion of the wells.

Can you give us little color as to what we should look for LOE or should we take from that?

To be fair, we've seen run rates in LOE in the $1.10, $1.15 range during the periods we've been completing and just under $2 for periods when we're not, and that's specific to the Vega area.

Okay. That's a range there. That's helpful. Could you happen to get that oil percentage number?

I didn't. I'm sorry.

Okay. I'll follow-up with Broc.

Okay.

And then just two more quick ones for you. The capital spending through from June to July, how much CapEx did you spend and what I'm trying to get to is does your revolver balance have some spending on it? I'm just trying to figure out how much additional CapEx you have to spend for the rest of the year, of the potential $28 million?

This facility.

Yes. I would say we've incurred to date somewhere south of $5 million and primarily that related to our new facility work in 2012 [ph] project.

Okay. And then just on the new completion process. Is there a change in the decline rate when you do that, that new completion process?

No. Really what we've seen in the wells and again, one of the wells has got eight plus months on it now. It looks like the decline rate in the shape of the curve is substantively the same as the other wells but with a higher initial IP rate.

And what's your expectation for the current one-year decline rate?

Well, it's a hyperbolic decline rate, so of course it's changing quite literally daily. It starts off very steep and flattens overtime, so.

I think the hyperbolic curve is fairly similar to what it was prior. It's just coming on at a lot higher rate.

Yeah.

Okay. Thank you, guys.

Thank you. And we have a follow-up from Evan Templeton of Jefferies.

Kevin, just a question on the new credit facility that you will be hopefully putting in place. Will that be structured as a revolver or is that a term piece with the full amount drawn?

Well, we’re looking at a number of possibilities, which include both of those.

Okay. Great. That's it. Thank you.

And we have a follow-up from Jim Lu at J.P. Morgan.

Yes. Hi. Joe Allman, again. So, Kevin, when you were talking about LOEs, you were using, you're saying $1.10 and $1.15 when you were in completion mode and just under $2 when you aren't in completion mode, specifically with Vega. So, I guess, two questions. One, so could you just talk about LOE just company-wide, so including the assets outside of Vega. And then also talk about transportation costs – it looks like there was a jump up in the second quarter. Talk about that and what's a good run rate going forward for transportation?

Well, your transportation increase was related to the new marketing arrangement that we discussed in the previous couple quarters and really that's just offset by realized gas prices in our revenues, so there's really not a major change in transportation and that should be consistent this quarter going forward. LOE, Carl is right, this quarter we averaged $3.08, a year ago in the Piceance we're at $1.08 and prior to that we were below $0.90. So that's going to be the main driver of our LOE going forward. The Gulf Coast LOE, I would say probably average is somewhere around $1.50, so blended rate around $1.20 is reasonable. It'll probably take us a quarter until we get down to that but that's kind of where I see it moving.

Okay. And Kevin, I think in the first quarter, on an Mcfe basis, I think transportation was around $0.78 and then in second quarter around $1.14? So are you saying that going forward the $1.14 roughly is a good run rate or?

Yeah. I would say the $1.14 is a good run rate. Broc can walk you through the revenue offset to that, which is actually a net positive to us as opposed to a negative and that offset is recorded in a realized gas price.

Okay. All right. That's very helpful. Okay. Very helpful. Thank you.

And now I'd like to turn the call back over to management for any closing comments.

Thank you all for attending. We appreciate your attention and look forward to providing you updates in the future. Thank you.

Thank you. That does conclude today's teleconference. You may now disconnect your phone lines.