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Executives

Ted Freedman - Executive Vice President, General Counsel and Secretary

Roger A. Parker - Chairman and Chief Executive Officer

John R. Wallace – President, Chief Operating Officer and Director

Kevin K. Nanke – Treasurer and Chief Financial Officer

Analysts

Michael Bodino - Coker and Palmer

Larry Busnardo - Tristone Capital

Brian Kuzma - JP Morgan

Tom Gardner - Simmons & Company

Gregg Brody - JP Morgan

Delta Petroleum Corp. (DPTR) Q4 2007 Earnings Call February 28, 2008 12:00 PM ET

Operator

Welcome to the Delta Petroleum fourth quarter and full-year earnings conference call. (Operator Instructions) I would now like to turn the presentation over to your host Mr. Ted Freedman.

Ted Freedman

I’m going to begin the conference call with a forward-looking statement disclaimer. This conference call will include projections and other forward-looking statements within the meaning of the federal securities laws and are intended to be covered by the Safe Harbors created thereby.

In that regard you will refer to the cautionary statement displayed on our website which is incorporated by reference to the information provided on this call. Further the U.S. Securities and Exchange Commission permits oil and gas companies in their filings with the SEC to disclose only proved reserves that the company has demonstrated by actual production or conclusive formation test to be economically and legally producible under existing economic and operating conditions.

We may use certain terms in this conference call that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in our Form 10-K for the fiscal year ended December 31, 2006, as updated by our subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

With that I’ll turn the conference call over to Roger Parker.

Roger A. Parker

Thank you for joining our 2007 earnings conference call. We will be discussing our financial, production and reserve results for 2007. But first I would like to review a significant transaction that we have recently accomplished with EnCana USA in the Piceance Basin.

We have been consistently increasing our drilling activity in the Vega Unit, North Vega area in the southern part of the basin. This area has benefited greatly from new pipeline capacity, which became operational about 15 months ago, and is now undergoing an additional pipeline expansion project, which will significantly increase take-away capacity and will be operational within about 12 months.

We believe increased ownership and exposure in this area will add substantial near-term and long-term value to the shareholders of Delta Petroleum Corporation. As such we have entered into an agreement that will give the company a contiguous acreage position in and around our existing Vega/North Vega properties.

The transaction gives us in excess of 1.4 trillion cubic feet equivalent, in new resource potential from the Williams Fork formation, which brings our total resource potential to over 2 trillion cubic feet equivalent in the low-risk, predictable Piceance Basin.

We will gain approximately 18,000 gross acres in this area giving us over 20,000 net acres, which has now been approved for 10-acre spacing. Although our near term plans do not call for drilling on 10-acre spacing, we will have an inventory of over 2,000 locations. We are also adding about 6 million cubic feet of gas per day net. Further, we estimate that our total company proved reserves are now approximately 530 billion cubic feet equivalent.

Under the terms of our agreement with EnCana, we have committed to fund $410.5 million, of which $110.5 million has been paid and three additional $100 million installments will be made over the next four years. These installments are guaranteed with a Letter of Credit.

By virtue of the strategic investment by Tracinda Corporation and our new transaction with EnCana, we have revised our 2008 drilling CapEx budget so that it now stands at a range of $350 to $370 million. Approximately $250 to $260 million of this amount will be spent in the Piceance Basin with $200 to $210 million going to Vega/North Vega Buzzard Creek area.

We are also slightly increasing production guidance for the first quarter 2008 and full year. The additional 6 million cubic feet per day should add approximately 180,000 Mcf equivalent to first quarter numbers and our previously issued guidance will therefore be raised by that amount to a new range of 5.46 to 5.66 billion cubic feet equivalent.

We are also increasing the lower end of our previously issued guidance for the full year. We are now projecting an increase of 45% to 60% over 2007 levels. We have not raised the high side of guidance due to pipeline limitations in the Piceance that will not allow for further growth until right after year end.

We are excited about this transaction as it will provide significant predictable growth immediately and long-term, and will allow for solid low-risk growth while we continue to proceed after our exciting greater return potential projects in the Paradox Basin, Utah Hingeline, and Columbia River Basin properties.

We believe we are uniquely situated with available capital, liquidity, and property mix to experience expected proved reserve and production growth and potentially company-changing exploration and exploitation drilling activity.

Turning to financial results for the fourth quarter of 2007 and full year, we reported a $30 million loss for the fourth quarter and a $149 million loss for the full year.

The fourth quarter loss was primarily a function of four factors: $11.3 million of dry hole expense, which was mostly in the Parowan project in the Utah Hingeline play; $5.4 million derivative instrument loss from hedging activities, we have oil hedged at $80 per barrel; $4.8 million non-cash equity compensation loss; and $4.2 million for DHS Drilling Company that among other things includes expenses related to refinancing of their credit facility during the quarter.

Due to the nature of our business plan, which includes low-risk and high-risk exploratory drilling, dry hole expense is something that we will face periodically although not expected in the first quarter of 2008.

On the positive front, EBITDAX totaled $26.6 million for the quarter and was up 48% over the same period in 2006. And full year EBITDAX was $83 million and was up 9% over 2006. Proved reserves were up 24% to 376 billion cubic feet equivalent. Reserve replacement was up 512% and production was up 10%, all in and in spite of property sales earlier in the year.

We have added some CIG index costless collar hedges as natural gas prices have risen over the past month. 10,000 MMBtu per day were added to the second and third quarters of 2008 with an average floor of $6.25 per Mcf and an average ceiling of $7.55 per Mcf. 35,000 MMBtu per day was added for the first quarter of 2009 with a CIG floor of $7.50 per Mcf, and a $9.88 per Mcf ceiling.

With that, I will turn it over to John Wallace, our President and Chief Operating Officer, to discuss some operational highlights not previously mentioned.

John R. Wallace

I would like to take a few minutes to expand on the operation section of our press release. As discussed earlier by Roger, this EnCana transaction in the Vega Area is a milestone event for the company. It will, as Roger mentioned, allow the company to increase all production and reserve metrics for several years to come.

In order to meet this increased drilling pace we have been planning for several months by hiring additional well-qualified technical people, designing rig scheduling needs for the future, and most importantly, increased gas takeaway capacity from this area.

In the Greentown area we’ve been completing and testing the lower intervals of the lowest section of the Paradox formation and both to Federal 28-11 and the Federal 36-24. In the Federal 28-11 we have been focusing our completion efforts on several different clastic zones that are located in between the lowest clastic intervals, which are the two Cane Creek intervals and the “O” zone.

These results from extended flow tests have been very encouraging and are very important because some of these intervals are mapable and continuous throughout the entire field area. In the future we will be targeting our completion efforts on the “O” zone itself, which is the lowest zone that was extensively tested in the previously drilled Greentown State 36-11 and Greentown State 32-42 wells.

In the newly-drilled Federal 36-24, we have focused our completion efforts on the deeper Cane Creek intervals where the initial results from the lowest Cane Creek interval alone are very positive, but more information is needed to be able to begin modeling reservoir projections from this lowest Cane Creek interval.

In order to avoid confusion we will only make public specific reservoir projections or individual flow rates when a particular well is being extensively tested. Because these classic intervals are unconventional in nature we anticipate that substantial testing will be required to accurately forecast reserve estimates and more importantly is able to project commingled flow rates from numerous different intervals.

In the Howard Ranch area we are very encouraged by the recent flow rates from our newly-drilled wells and we are confident that we can determine an economical way to dispose of water that would allow for a long-term development program.

In the Midway Loop area we’re finishing the drilling portion of our Baxter well, which is expected to be a very good well. Our next location in the field will be positioned in between the soon to be completed Baxter well and the Simmons well, which is our best well in the field.

In the Hingeline area we’re beginning the permitting process for our next well with anticipation of drilling sometime this summer. This prospect is well-defined based on brand new 2D seismic and is projected to be large in aerial extent.

In the Columbia River Basin we’re finishing the location for the Gray 31-23 well, and will begin moving DHS Rig 7 in the near future. Based on wells drilled in the 1980s utilizing the same drilling technology we plan to employ, we’re projecting the well to take four months to drill and another couple of months to complete.

With that I think we can turn this call over to the Q&A section.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Michael Bodino - Coker and Palmer.

Michael Bodino - Coker and Palmer

Couple of follow-ups here relative to Piceance Basin, first of all, can you give us any breakdown on those incremental reserves from proved developed and proved undeveloped, kind of as we sit 1-1-08?

Roger A. Parker

1-1-08 it was 31% proved developed.

Michael Bodino - Coker and Palmer

And so there’s quite a few wells already drilled on this new acreage, transaction acreage.

Roger A. Parker

Actually we don’t have the percentage proved developed. Percentage proved developed would actually be fairly light and on the order of about 12%.

Michael Bodino - Coker and Palmer

And this new acreage, I know some of it you already have interest in, but the newest acreage you’re picking up, was there a lot of data points there? Is it consistent in terms of the waves form in terms of thickness, reserves per well?

Roger A. Parker

Yes, we have numerous well bores that identify a thickening gas column and are very consistent with estimated ultimate recovery maps that we’ve got in our investor presentation materials. If you looked at those materials you’ll see that we have the expectation of increasing per well reserve recoveries on the acreage as you move north from the Vega unit area and all of this acreage is concentrated in that area.

So, yes, we do have the expectation. We do have numerous data points and a very good expectation of increasing per well reserve recoveries.

Michael Bodino - Coker and Palmer

And then can you kind of walk me through first quarter, second quarter, either on a gross or net basis, production volumes as this next phase of the coal burning gathering system comes online, kind of what you expect from a delta perspective?

Roger A. Parker

Yes, if you also look in our investor presentation materials, you’ll see on the slide for the area we have a bar chart showing anticipated production growth throughout 2008. What you see is that we expect an average of about 45 million cubic per day for the second quarter of ‘08, topping out at 60 million cubic feet per day in the third and fourth quarter of ‘08, and that is limited by pipeline capacity until the expansion project is complete.

Michael Bodino - Coker and Palmer

So, this acquisition is not really additive to that second quarter volume number, or is it?

Roger A. Parker

Well, slightly and only to the amount of what we identified in the press release today, which is about 6 million cubic feet per day.

Michael Bodino - Coker and Palmer

On the stepped up budget, I know you put in here you talked a little bit about what’s going to be spent in the Paradox and in the Piceance Basin. But can you give us any color on the break down on the remaining budget relative to acreage in other areas that are going to get dollars thrown at it?

Roger A. Parker

No, not at this time, suffice to say we will have some activity going on in basically all property areas that we’ve got. But it’s not significant in any individual area which is why we didn’t go into the detail for those other areas.

Michael Bodino - Coker and Palmer

Can you explain to me maybe the accounting of this payable to EnCana over the next couple of years, how we should look at that?

Roger A. Parker

Well, what we have is a situation where the company closed with a payment of $110.5 million. The total commitment is $410.5 million and we will therefore have three $100 million payments due over the course of the next four years. We’re booking the entire $400 million, $410 million now. We have the payments guaranteed by a Letter of Credit. And what other details are you looking for Michael?

Michael Bodino - Coker and Palmer

Kevin, are you going to classify like $100 of it as a payable and the other $200 as a long-term debt?

Kevin K. Nanke

Well there’ll be $300 as a payable, because we paid a $110 today. And it’s a non-interest bearing so I’ll probably discount that, but that liability will go on the books as of today.

Operator

Your next question comes from the line of Larry Busnardo - Tristone Capital.

Larry Busnardo - Tristone Capital

On the Piceance Basin, what’s the current production rate out of the field right now, and then year-end would kind of be maxed out of that 60 I would take it. And then looking out a little bit further what do you think the peak production rate could be? I don’t know if you’ve done any of that kind of projections yet, on where Piceance production could go? And then what year do you think you might hit that peak rate?

Roger A. Parker

Larry, we will be capped at 60 million a day until additional pipeline capacity is available, which is as mentioned earlier not expected to be in operation for about 12 months from now.

I would point out that we also have a fairly significant capital expenditure in the Piceance Basin this year in the Garden Gulch property, which is the Berry Petroleum operated ownership. And as of right now, on our Piceance Basin, total production is approximately 40 million cubic feet per day, actually about 38 million cubic feet per day, but growing essentially daily.

And then because of additional volumes anticipated in that project as well, we would expect that we would be exiting ‘08 with a daily rate of approximately 75 million cubic feet per day for the Piceance Basin.

As we get into ‘09 and as we have takeaway capacity increasing in the first quarter of ‘09 in a substantial way, we expect to experience a pretty significant increases in production at that time because we should have a fairly good inventory of wells that have been drilled and not yet completed.

Right at the moment we haven’t gotten into extreme detail about peak production rates out of this area but suffice to say we expect it to be in excess of 200 million cubic feet per day and possibly quite a bit higher than that. At the moment, it’s looking like later in 2010 we would be able to achieve closer to peak productive capacity from what we currently own.

Larry Busnardo - Tristone Capital

That 75 million a day, does that include Garden Gulch?

Roger A. Parker

Yes, it does.

Larry Busnardo - Tristone Capital

And what’s that, remind me on the pipeline expansion. Is that 60 going to 120?

Roger A. Parker

No, it’s actually a second pipeline project and the second pipeline project is a significant pipeline in and of itself. And it is expected to have approximately 500 million cubic feet a day of take away capacity once complete.

We do not have ownership on the line. But we are certainly working on firm capacity and given the fact that the line is that large, we expect to have plenty of available capacity to Delta’s production.

Larry Busnardo - Tristone Capital

And that’s the one that is going to come on next February correct?

Roger A. Parker

Correct.

Larry Busnardo - Tristone Capital

Also looking at the plays as we look at it as a whole now, just looking at the Vega area. What do you think kind of average EURs are going to be in the field given what you are seeing so far in the wells, completed cost and things like that? And then are you seeing anything different geographically, you talked about sticking to a little bit to the north, but I’m just looking for some more details on those items?

John R. Wallace

As we’ve mentioned previously we talked in detail about the Vega economics which we are modeling as 1.35 Bcf and well, completed well costs of $1.8 million completed. As we move north the pay column is considerably thicker about 25% thicker, but we’re still going to model 1.35 Bcf as we move north.

The completed well cost should remain fairly consistent with what we’ve been achieving in the Vega area. It’s actually easier topographically, we moved down into a little bit of a valley. But, there are some additional infrastructure costs, so I would say that the per-well reserves should increase from over the Vega area and the completed well cost should remain in line with what we’ve been achieving in the Vega area.

Larry Busnardo - Tristone Capital

And then just couple other quick ones just in the CRB. What will your working interest be going forward now that you have your partner?

Roger A. Parker

We haven’t announced a partner yet. We do expect to be able to communicate with you all very soon about that situation. But we do not have a partner as of now that we are ready to talk about publicly yet.

John R. Wallace

We will operate the well.

Larry Busnardo - Tristone Capital

On the Paradox Basin, I think you mentioned what the capital will be this year on the expanded budget. Could you just give me that number again?

Roger A. Parker

Yes, it’s approximately $40 million.

Larry Busnardo - Tristone Capital

And how many wells do you think would be drilled?

Roger A. Parker

Right now, we’re projecting 12 wells, yes.

Operator

Your next question comes from the line of Brian Kuzma - JP Morgan.

Brian Kuzma - JP Morgan

Can you tell me just how did these the Letters of Credit affect your borrowing base?

Roger A. Parker

They haven’t affected our borrowing base at all as yet. We have cash set aside for the Letters of Credit. We’re working with our banks currently to allow the cash that has been set aside for the Letters of Credit to also be available for drilling CapEx on these properties.

Brian Kuzma - JP Morgan

So, you’re saying that it wouldn’t impact the borrowing base.

Roger A. Parker

Borrowing base itself has not changed. And it will not change by virtue of this situation.

Brian Kuzma - JP Morgan

And then the net acreage that you ended up picking up in this acquisition, what did that come out to then?

Roger A. Parker

The net acreage is approximately 17.5 thousand acres, net increase.

Brian Kuzma - JP Morgan

From what you were at before?

Roger A. Parker

That’s correct. Yes.

Brian Kuzma - JP Morgan

In terms of your overall capital structure where do you see yourselves wanting to be at for the next two to three years?

Roger A. Parker

Well, I think in a very general sense the primary comment to make there is that we’ve done an extensive amount of modeling as we have considered and entered into this agreement. And we are intent on being able to do two things.

One is be in a situation where we do have an acceleration of drilling activity. The increase in drilling CapEx for ‘08 already identified, but certainly the expectation as we move to more rigs in operation in 2009, additional increases in drilling CapEx. And all the while making sure that we have very comfortable levels of liquidity, and by that I would mean certainly nine-figure type liquidity as we go forward at all times.

Operator

Your next question comes from the line of Tom Gardner - Simmons & Company.

Tom Gardner - Simmons & Company

On your Vega unit, the 10-acre down spaced wells, are you assuming lower reserves on those infill wells?

Roger A. Parker

What we have is we have recently received approval for 10-acre spacing. We do not currently have plans to develop on 10-acre spacing at all. We have a significant number of locations that will allow us to continue to drill on our current pattern of 20-acre spacing.

But certainly as we go forward in time we will be doing various work including micro-seismic work to determine what actual drainage patterns might be and drainage areas might be before we make a decision to increase density over what we’re doing right at the moment.

So it’s too early to make any comments in the regard of how much you might experience in the way of communication, especially given the fact that we’re not going to be drilling on that density any time soon.

Tom Gardner - Simmons & Company

And just trying to talk around this 2 Tcf resource potential in the Piceance. Does that include the resources associated with your EnCana deal?

Roger A. Parker

It includes the EnCana deal, the Vega unit properties we already owned, and also the Garden Gulch Field reserve potential in the basin.

Tom Gardner - Simmons & Company

And is it net of royalties?

Roger A. Parker

It is net of royalty, yes.

Tom Gardner - Simmons & Company

And then with respect to the EnCana deal, can you give us an idea on what the net revenue interest is let’s just say on a 100% basis?

Roger A. Parker

Yes, on a 100% basis the average is approximately 82% net revenue.

Tom Gardner - Simmons & Company

With respect to the Garden Gulch net acreage position I just wanted to confirm, we’ve got at 6,300 acres, 31% working interest.

Roger A. Parker

That is correct, yes.

Operator

Your final question comes from the line of Gregg Brody - JP Morgan.

Gregg Brody - JP Morgan

In terms of liquidity of the Tracinda investment of the cash coming in, how much of that was, is allocated towards this investment? So how much is left for you to go out and spend?

Roger A. Parker

Well, that’s what we tried to allude to earlier. Right now, we have set aside $410 million, $300 million of which is cash related to the Letter of Credit that has been issued in favor of EnCana. We are and have been working with our banks to have the $300 million in cash that supports the Letter of Credit be available for drilling capital expenditure during the course of drilling activity on this particular transaction.

Gregg Brody - JP Morgan

So it would be allocated specifically for that purpose.

Roger A. Parker

Correct.

Gregg Brody - JP Morgan

And then in terms of your reserves, you added some nice reserves here with this transaction. When do you evaluate your credit line again?

Roger A. Parker

We’ll be having our next bank meeting in mid-April.

Operator

There are no further questions in the queue and I’d like to turn the call back over to Mr. Parker for closing remarks.

Roger A. Parker

Thank you all for joining us. We look forward to communicating with you again soon.

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Source: Delta Petroleum Corp. Q4 2007 Earnings Call Transcript
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