Par Pacific Holdings Inc (PARR) 2006 Q4 法說會逐字稿

At this time I would like to welcome everyone to the Delta Petroleum fourth quarter and year-end 2006 conference call. [OPERATOR INSTRUCTIONS] Certain statements made on this conference call constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements involve a number of known and unknown risks, uncertainties, and other factors that may cause actual results to differ materially from such forward-looking statements. Many different items may affect results and they include but are not limited to commodity prices, environmental, and regulatory factors, drilling schedules, and capital plans.

It is now my pleasure to turn the floor over to your host, Roger Parker, Chairman and Chief Executive Officer. Sir, you may begin your conference.

Good morning and thank you all for joining our 2006 year-end conference call. I'll go ahead and open today with a statement that we will not by filing our 10-K today due to the shortened time period for filing and increased audit procedures now required under the Sarbanes-Oxley Act, we were not able to complete the income tax review audit procedures necessary for the timely filing of our 10-K. Accordingly, not all of the audit procedures for the financial statements reflected in this press release have been completed and it is possible that some amounts reflected herein could change upon the final completion of the audit, although we do not expect that any such changes would be material. We also do expect that we will be filing our 10-K within the next few days. Let's see. With that we'll go ahead and go on to the 2006 highlights.

A number of things to point out that we'll go into a little bit of detail about. First, we experienced proved reserve increase of 23% net of sales. Total reserves as determined by our third party engineers are 302.4 Bcf equivalent at year end 12/31/06. That number would have been approximately 330 Bcf equivalent net of sales. In addition, we had about 43 Bcf equivalent of downward revisions, most of which was related -- directly related to commodity prices. In addition to that, we had a total revenue increase of approximately 64% to $176 million. Our oil and gas revenues increased approximately 27% to $124 million, and DHS Drilling Company revenue increased 320% to $57 million, which is primarily reflecting a full year in operation.

In addition to that, we had production increases of 12% to 16.1 Bcf equivalent for the year 2006. This was in spite of the fact that virtually all of our drilling activity in 2006 in the Piceance Basin in Western Colorado did not -- was not able to begin producing until right at the end of the year because of the Coburne Valley Gas System pipeline, which did not become operational until the end of November. Since then our daily rate has increased approximately 11 million cubic feet per day, or 9 million cubic feet per day net since we began completion activities about 90 days ago. This will significantly benefit us in terms of production growth for 2007.

For 2007 we have set an approximate drilling CapEx budget of $200 million with 75% of that being spent in the Rocky Mountain region. What's very important to point out with regard to this is that all of the drilling in the Rocky Mountains, especially in the Piceance Basin, Wind River Basin, and Paradox Basin will be at depths of approximately 9,000 feet. In prior years, 2005 and 2006, most of the drilling activity company-wide was in excess of 12,000 feet. What that means is that there is a very direct expectation that wells will be drilled much quicker and will be hooked up much quicker than has been experienced in years past. And in fact in the Wind River Basin and the Piceance Basin where we expect to have most of our development drilling activity, these wells should be drilled in two weeks or less on average. And again, with the new Coburne Valley Gas System pipeline hooked up in the Piceance Basin, wells will be going to sales much quicker than has been experienced in years past. With that we also expect to experience much more predictable and much more meaningful production growth for the year.

The next item that I will refer to in our financial highlights is our DD&A. As you all have seen and experienced over the last handful of quarters, our DD&A is abnormally high. There are essentially no changes to the reasons for it being high. It is primarily because of a couple of South Texas fields which have significantly greater DD&A rates than other fields that are operated by the Company. We are in the process of divesting ourselves of these fields and we expect that during the first half of 2007 our DD&A should reduce significantly and become much more in-line with industry numbers in the second half of 2007. Other financial items including EBITDAX, cash flow, lease operating expenses, are mostly in-line with expectations.

Moving on to divestitures, most of you are aware that we put up for sale three separate packages primarily located in Texas but mostly i Gulf Coast Texas through Tristone Capital. Two of those packages are under executed P&S agreements and are expected to close in mid-March for a total sales price of $31.5 million. The one package that was not sold was our Austin Chalk package, and the Austin Chalk package was -- the main reason for that not selling was because we had two new wells drilling at bid time, and it was too hard to adequately value the package itself from the position of the buyers. So many originally interested buyers chose not even to bid. We will visit this again at a later date after both of the new wells are online. One of the wells is online and referenced in the press release here. The second well will be online in about two weeks. That well looks to be a very good well, which I think also contributed to the problem of being able to be adequately valued by the buyers. During 2007 we will continue to divest other noncore properties with a primary focus, continuing focus on the Gulf Coast as we have referenced in the past. I would point out that we still do have a substantial amount of value in the Gulf Coast region that is on the order of 100 Bcf equivalent in proved reserves even after the Tristone sale.

Moving on to guidance, you will also see in here that the Newton Field Gas Pipeline was placed back in operation on January 30. We did meet previously-lowered guidance numbers of 3.75 Bcf equivalent for the fourth quarter of 2006, and we are reaffirming but narrowing our guidance for the first quarter of 2007 with a range of 4.3 to 4.6 Bcf equivalent for the first quarter.

In general I would like to make a couple of comments about 2007 and what we are most excited about. In the Piceance Basin, we are obviously very pleased that the new pipeline is in place and operational. This will allow for much more consistent and predictable production increases. In the Wind River Basin, as referenced in the property section here, we have a new acreage acquisition of approximately 38,000 acres, which gives us significant additional leasehold for lower Fort Union formation development that has unrisked reserve potential of approximately 6 to 700 Bcf equivalent.

In the Paradox Basin where we had two significant discoveries in 2006, we will be drilling more confirmation wells and some development wells to further establish the size of the discoveries and to assist in appropriately sizing a new pipeline that we are currently working on. With that we'll go ahead and turn the next part of the presentation over to John Wallace, our President and Chief Operating Officer, who will take you through the operations update section of the press release. Thank you.

I would like to provide some information and hopefully any clarity if needed for some of our more important project areas. First and foremost and one of the biggest growth drivers for the Company in '07 will be the Vega Unit, where we're currently selling approximately 13 million a day and we'll continually increase our production as we complete the eight wells remaining to be completed that were drilled in 2006. And the newly-drilled wells that we are accumulating with two rigs running full-time. We are projecting approximately one net well completed per week for the remainder of the year, which will provide us with a net affect of an increase of approximately 2 million a day per month for the next several months into the summer, and then a net affect of approximately 1 million a day per month for the remainder of the summer until the year end.

In the Howard Ranch area, as Roger mentioned, we're excited to announce the acquisition of 38,000 acres. This acreage sits in close proximity to our Howard Ranch acreage and dovetails and gives us a strong position for repeatable growth driver, which we expect in '07 we will begin a, what's hoped to be a continual drilling program in the Howard Ranch area and we will be developing a fairly low-risk reservoir and a lower Fort Union. We also, of the acquired lands, we have two operated wells with acquired lands and we do plan to recomplete both of those wells.

In the Greentown area in the Paradox Basin, I would like to provide some clarity. It seems there is some confusion in the market as to the total reserve potential of the Greentown wells and I would like to state that the Company believes that the total reserves of those two wells is in excess of 8 Bcf per well. Based upon the geologic consistency between the two wells and other wells throughout the area, we think that the unrisked net reserve potential, depending upon spacing for the Company, is 2 to 4 Tcf on our acreage. We're currently waiting on permitting and plan to drill six to eight wells in 2007. We are also, as referenced in the press release, we are currently permitting and staking a pipeline to get that sales to market.

The Salt Valley Oil discovery also in the Paradox Basin is also currently waiting on permitting and we do plan to drill five to six wells in 2007, depending upon the permitting process. This oil discovery will be developed immediately and our first well is planned to be online in two weeks. Also in the Paradox Basin, we are excited to drill a new prospect, exploratory prospect that's similar in the geologic parameters prior to drilling as the Greentown prospect. That well, we're waiting on winter stipulations to clear and we plan to drill that well in the second quarter of '07. If successful that well has immediate marketing availability and if a gas discovery, we would develop that particular feature immediately in '07.

In Newton County, we are permitting several shallow [Yaywood] tests based on the success of our [Aolis] well which is a [Yavo] well that I paid for a million a day and 100 barrels of oil. The well has increased and is currently making over 2 million a daily and over 200 barrels of oil with a well cost of $1.5 million. So we are permitting several additional Yaywood bright spot anomalies based on our 3D seismic shoot. In addition to that, we are permitting offsets to our North Newton feature in the -- offsetting the James Gray number one and number three. In addition to that, we've recently had some improved production results from the James Gray number two and we're beginning to believe that the entire James Gray feature will be a source of development for later half of '07.

As Roger referenced in the Midway loop area of the Austin Chalk development, we brought on our first well that we were drilling here recently towards the end of the year and we have currently reached TD on our second well. It's important to point out that the first well was a single lateral in the Austin Chalk. The Simmons well, which will be online in a week is a dual lateral. In fact, it's the longest -- that well has the most horizontal section intersected for any well drilled by Delta with over -- almost 12,000 feet of horizontal section. The well had very good shows and we anticipate a very good well when we bring the well on next week or possibly the following week.

Concerning the Central Utah Hingeline project, we are processing some aeromagnetic data into our geologic model to review the remaining 20 prospects. This data will help us image potential igneous obtrusive bodies, like the one that was encountered, unfortunately, in our Joseph well. We believe this technology will allow us to identify the igneous bodies and not drill into anymore more igneous rocks. Lastly, in the Columbia River Basin, we are continuing the permitting process of our three wells on acreage that we own 100%. We are planning drilling later this year and results will follow based upon completion of the well. With that I think it makes sense to turn the call over for questions.

[OPERATOR INSTRUCTIONS] Your first question comes from John Freeman of Raymond James.

Good afternoon, guys. How are you?

Good.

My first question on the Paradox Basin. Just want to verify, the 2 to 4 Ts of unrisked, was that the total Paradox Basin acreage?

No--.

Is that just Greentown?

That's just Greentown and those are net numbers to our 70% working interest, 82.5% NRI.

And what spacing does that assume?

Well, the 2 to 4 Tcf refers to 80 acre spacing or 40-acre spacing.

Okay. On the drilling activity this year in the Paradox, how should I think about it in terms of a split between drilling additional wells in Greentown versus trying to prove up these other prospects?

Well, we plan to drill six to eight wells in Greentown to delineate the size and limits of the field. They all will be qualified as exploratory in nature being a mile away from one another. Having said that, these wells appear so consistent that we're expecting similar results to what we've achieved so far. And we'll drill five to six wells in the Salt Valley feature, which again will be developed because it's an oil discovery and does not need -- did not -- won't suffer delay in marketing that Greentown will. And then we're going to drill one well, an additional Paradox prospect, a new prospect, in '07.

Okay. And then on the pipeline that's being built, can I conservatively just assume that maybe a year for completion, in when that would be online from now?

I think that would be a reasonable assumption at this point, John. There are a number of issues to deal with, but -- and then certainly on our part, there's the hope that we might be able to get it done sooner, but given the fact that it will primarily go across federal acreage, I think it's a safe assumption. Your assumption is a safe assumption.

Okay. Then moving to Howard Ranch, maybe you could just provide some color on maybe what has kind of changed there over the past year. I don't know if some of it was just due to that third party study that was done. But obviously -- or, it seems like you've been acquiring a lot more acreage, you're now a lot more optimistic about the play. Maybe just some added color there.

Well, sure, John. We have several Delta employees here that were involved in the genesis of this play that was developed primarily by Tom Brown and the Frenchy Drawfield. It's a resource play in that the reservoir is made up of sand, shale, silt, various different formations. It is generally throughout a large portion of the Wind River Basin, so it is very consistent geologically across a large area. It's something that we've always focused on internally here at Delta, but we had it as a behind-pipe recompletion potential with the Lance and Mesaverde drilling that we experienced in '04 and '05. But upon recompletion of our own wells and other drilling in the area, it's been determined that this is better reserves and definitely warrants its own drilling program. The F&D costs are fairly low given the Rocky Mountain region and one of the lower F&D costs for the Company. It will be an area that we think we can consistently develop over a large area with repeatable economics.

John, this is Roger. I would also just refer back to comments already made with regard to that. Most of the drilling activity are -- actually, virtually all of the drilling activity in the Wind River Basin for us going forward will be to these shallower formations, which are typically 9,000 feet or shallower and can therefore be drilled much quicker than our Wind River Basin activity in the past.

Okay. Then last question I had, on the Columbia River, what are you all's estimates on the time and cost to drill one of those wells?

The timing, the permitting -- because we're permitting the first well in a county of Washington that's never had a well drilled before, an oil and gas well, we're having to do quite a bit of educating to make sure that we do this right and do this in conjunction with the county level. So the anticipated timing is unknown at this time. I will say we are fairly well along with our permitting process.

Sorry, I was referring to, like, how long it would take to drill and complete the well and the costs that you would expect?

Well, we've prepared an AFE and we are really working on the drilling procedure. We're going to drill our well -- we're planning to drill our well a little bit different than some of the more recent wells, and we're looking at a well -- a completed well cost in the neighborhood of 14 million.

Great. Thanks, guys.

Okay.

Your next question comes from Joe Allman of JPMorgan.

Hey, everybody.

Hi, Joe.

Hi. John, could you give more details on that James Gray number two? Because I think initially that wasn't looking so good and now it seems like it's looking better.

Yes, I will, Joe. Basically, there are numerous sands in the upper Wilcox, which is the same interval that produces at Newton. And as with the Newton field itself, some of those sands have a higher water cut than others. We completed several of these sands simultaneously and we think one or possibly two of the sands had such a high water cut that they were overtaking the producibility of some of the oil sands. And what we've begun to selectively test some of the intervals and now the well's making oil. We feel like that was true. You never know that until you actually find out where the water is coming from and seal it off. It's early -- it's too early to tell for sure, but we're seeing fairly significant oil rates from the well, essentially for the first time. So we're very encouraged about the upper Wilcox in addition to the lower Wilcox.

And then John, in your prepared remarks, I missed the very last thing you said. You were talking about one well and I missed that. Can you repeat that?

I think I said something about, it's time for questions?

Just before that.

I believe we were talking about the Columbia River Basin?

Is that what you were, okay--.

Yes, and we would like to drill a well later this year.

Any intelligence on what results look like so far there?

No, not at this time.

Okay. Then lastly, on Howard Ranch, I haven't had a chance to process your press release and I apologize, but this acquisition you made. So this is looking -- the economics look better on this acreage than what you currently hold?

No, it's very similar. In fact, it's -- that's one of the appeals of this play is it's very predictable and repeatable, we think, from an economic standpoint. So we have completed two wells on our own acreage. One well has ultimate reserves of 1.9 Bcf and the other well has ultimate reserves of 1.3 Bcf. So we're modeling 1.3 Bcf across both our own acreage and the acreage offsetting Howard Ranch that we recently acquired.

Then, okay -- if I can just flip back to Newton county for a little bit. The implications of the James Gray two working. You've got the James Gray one on one side, the James Gray three on the other, the James Gray two in the middle. So this is really helping to make this whole prospect look a little better, isn't it?

Absolutely. It gives us a lot of confidence that the entire structure is worthy of development, where before we had a pause in drilling where we tried to figure out whether this structure was compartmentalized. If we could believe it exists throughout the wells that we've drilled to date, the James Gray one, two, and three, then we'll feel confident in the further development of the entire structure.

Your next question comes from Michael Bodino from Coker and Palmer.

Good morning, gentleman.

Hey, Michael.

I had just a few questions. First of all, Howard Ranch on this acquisition acreage, is this acreage contiguous? Does it move back toward Madden field or down toward Iron Horse? Could you give us a little bit more proximity to where the acreage sits?

We'll both answer. The answer, Michael, is that it's more or less yes on all fronts. What it does do is it gives us a very solid, large block of essentially 100% owned leasehold that is probably on the order of about 12 to 14 sections around the existing Howard Ranch acreage and then in addition to that, there is quite a bit of additional acreage that moves toward the other areas that you referenced.

And in these two well bores, you said they were being recompleted. Were they deeper tests or were they actually completed originally in some of the Fort Union sands?

Both of them were deeper tests. One of them did test this particular interval at fairly impressive rates and then went on and tested deeper intervals. One of the wells will actually just not recomplete but set a plug and produce the shallow interval and the other one will actually physically complete the shallow interval. But based on log analysis, mud logs, and our understanding of the play and mapping in the area, we're very helpful that both of these wells to be successful at lower Fort Union wells.

Your next question comes from David Tameron of Wachovia.

Good morning. Back on Howard Ranch, what -- remind me again of the drilling season there, as far as stips?

David, it varies. We actually have quite a bit of acreage that will not be subject to winter stipulations.

Okay.

So we will be planning the drilling program up there so that certainly during the winter stip periods, we will be drilling the acreage, especially state lands but also some federal lands that are not subject to winter stips during the winter time period. It should be a year round drilling program for us at this stage especially given the number of locations that are available that are not subject to winter stips at this point.

Okay, did you ever -- is it disclosed who you bought that from and at what price?

No, we haven't disclosed either at the request of the private party.

Your next question comes from James Gibbons of JPMorgan.

Good morning.

Hi, Jim.

You've announced a $200 million plus CapEx spending program for 2007. That's a little more than twice operating cash flow. You've obviously announced the sale of certain assets for 31 million in the first quarter. Have you given further thought to funding the balance of that CapEx?

Yes. Jim, I think one of the things we're trying to have the market understand is that there is an ongoing and continuing effort to concentrate our activities into our most core areas and I'll point to the idea that we have 70 -- 75% of our 2007 budget going to the Rocky Mountain Basin's Paradox, Piceance, and Wind River. And that means that over time we will -- we will be continuing to divest of especially Gulf Coast properties where we still do have quite a bit of remaining proved reserves. Also, we'd refer back to the fact that we did raise $56 million of net equity back in January.

What have you found the market to be in terms of asset sales since you have been reasonably active in the last month?

Actually, the interesting thing was that during the month of January when oil prices dropped down to $50 a barrel, it didn't really deter or change the metrics that are being used by buyers in the marketplace right now. In fact, as has been typical for a number of years in the E&P business, most buyers are using the -- are using strip prices to come up with their valuations. So the short-term drop in commodity prices in, especially in January, didn't seem to have much of a negative impact on valuations.

Your next question comes from [Bob Seetchy], a private investor.

Good morning, gentlemen.

Good morning.

Just getting back to the Columbia River Basin, I just wanted to ask what your best guess for time expected to complete a well, and what depth you expect to TD at?

Well, it will vary dramatically across the basin. In fact, what Delta has concentrated on in its leasehold acquisition activities are areas where we believe that the Basalt will be significantly thinner and shallower than other parts of the basin. Certainly, there will be a direct correlation between the depth of the Basalt and the drill time expected. But the areas where we own leasehold, we're of the belief that we'll be drilling between 5 and 8,000 feet of Basalt thickness depending upon where we are and also depending upon the time of rigs that are used. At the moment we are thinking that conventional drilling rigs will certainly be the way we will go about drilling initial wells would allow for a much reduced drill time than I think what the market has seen over the last couple of years.

Okay. And this might be a little bit of an unfair question. Do you expect to spud more than one well this year?

No. At the moment we-- at the moment we don't. I think it's very fair to say that ongoing activity will certainly be dependent upon results experienced not only by us, but others as well.

Okay. Thanks a lot for your comments.

You bet.

Your next question comes from Michael Scialla from A.G. Edwards.

Hi, Michael.

I think that's me. Hi, guys. Not to beat the Fort Union winter play to death here, but so I have it clear, your 600 potential locations, you've got on that acreage two productive wells and then some logs from deeper wells. Are there some third party wells also that are producing out of Fort Union or no?

Yes, there are. There are other producing wells by other operators, and this play is so consistent across the western part of the Wind River Basin, especially the north, north-central part of the Wind River Basin that the wells do not vary much in their ultimate reserves.

My question is how many are we talking, just a couple of is it a significant number, or?

Well, if you look at the development in the Madden unit, Burlington is focused on Conoco on this particular reservoir and obviously Encana focused on it, at Frenchy Draw, I believe the initial phases of exploring the same reservoir, you'll see Nobel at Iron Horse. Those are areas that there is ongoing focus, in addition to that, Encana has, in and around the full reservoir has looked at the same reservoir. Those areas are in -- surround, I don't want to say surround, but are in relatively close proximity to these acreages that we've acquired.

Got it.

We feel like it's pretty consistent across western Wind River Basin.

Okay. Then the Piceance, remind me again, what was the pipeline capacity on that coal brand line?

Well, it's -- the initial capacity is 60 million a day. The pipeline -- pipeline expansion has already begun and we're not quite sure yet, because there's a lot of discussion amongst the parties where the total capacity will end up, but I think it's safe to say it would be at a minimum of 120 million a day.

Okay. And then on your revisions on proved reserves, would those primarily -- you said they were price-related. Primary just tail reserves, or were there some PUDs that came off the books?

They are price-related.

It's mostly price-related. There would -- there were some PUDs that came off the books. In fact, the PUDs that came off the books, Mike, were largely the deeper reserves in the Wind River Basin.

Your next question comes from Jack Aydin from KeyBanc.

Hi, guys.

Good morning, Jack.

On the reserves, you added 90 plus Bs. Could you break down where did you -- what area did you book those reserves from?

It was actually 111 Bs, I think, was it not?

No. Well, maybe.

The reserves, probably a full half of that came from the Piceance Basin, Jack. Down here, 111.

Yes, 111, yes, I was looking only on the gas, yes, 111.

Yes. 111, approximately half of that from the Piceance Basin and about a quarter of that from the Paradox Basin. And that would -- other than that 75%, I would have to get into more detail for you that I don't have at my--.

That's okay. Now, you have about 111 Bcfe in the Gulf Coast. What percentage of that is Austin Chalk?

About 20% of that is Austin Chalk, Jack.

And on the Paradox Basin, did you add more acreage in that play, or you just you kept it the way, you know?

We have continued to try and add more acreage out there, most of the recent leasehold acquisitions have been smaller, but we also have nominated a significant amount of additional acreage that we'll certainly bid on when the state and federal sales come up.

But you're not willing to give me a number?

Excuse me.

Any number? Position?

No. I think, in the -- as an example in the Greentown prospect, we've only been able to add about 3 or 4,000 acres here recently.

They've only come up, Jack, here recently.

Yes. John, how confident are you with that 2 to 4 Tcf of potential unrisked reserve?

Well, I only have two wells and a scattering of old wells in the area to map the play out. We're talking about all of our acreage position. I will tell you that the similarity in the logs and similarity in the drilling shows and the similarity of the individual zones pressure testing give me a lot of confidence that I can expect this same interval throughout the acreage area and possibly even extending past our acreage area. So I feel very confident in it, but of course I'd rather have gas sales and that's more of a known. Further drilling this year will help delineate and prove up the repeatability of the play, but I can tell you based on the two wells we drilled to date, they look very, very similar.

Your next question comes from [Robert Lind] of Simmons and Company.

Good morning.

Good morning, Robert.

Most of the -- of my questions have been answered, but just to expand on Howard Ranch, you think you have 600 locations there on 40s. And I recognize that there are some old wells on that acreage, but are you risking that? Because your 38,000 net acres would suggest potentially more locations to drill there.

Yes, we are risking that in that there are -- there is a part of the leasehold that is deeper than the 9,000 foot interval that we're talking about, which doesn't necessarily mean that it's not going to be productive, but it does mean that the economics would be different and because of that, we are not considering that perspective at the moment. And that's why you don't have a direct correlation on your math there.

Okay. I know you're really not discussing the terms here, but on this acquired acreage, what's a good net revenue interest to assume?

80%.

80.

Okay. Thanks. That's all I had.

Thank you.

Your next question comes from [Ben Jigau] of [Huizenga] Capital Management.

Good morning, guys. First, congrats on the success at the Greentown. Those are fantastic numbers.

Thank you, Ben.

My first question relates to central Utah. Can you just comment a little bit about the 20 remaining prospects, when you plan on drilling the second and third well of the three-well commitment you've made with Armstrong?

Sure. Ben, the holdup there is in the permitting process, but we are making progress there. As far as the play itself, in hindsight to review what happened with the Joseph well, because we intersected this igneous intrusive that we didn't know was there, we really don't we've even think we've tested the play concept. We do need to make sure that we're comfortable, that the remaining 20 prospects will not have the same igneous bodies intersected and we feel to a high degree that most of them won't. A couple of them look like they have -- further information needs to be gathered to convince ourselves 100% that we won't see this igneous rock, but a majority of the 20, let's say 18 of them, we're not seeing much in the way of this igneous body. So we are very excited to continually develop this play and drill some wells, because, again, I don't think we've even tested the concept yet.

Any ideas to when you may start spotting the second or third well?

Hopefully sometime this summer.

Okay. Second question, I know you're not speaking much on the CRB. I know, on Encana's call they said that they were suspending two of their first wells which was a little confusing. I know, Roger, in the past you have said you were highly encouraged about the prospect. Does that still hold true when you think about Delta's view of the CRB?

I think from our standpoint, we have not seen anything that would cause us to have a different attitude about the overall project or the Basin itself and we're -- obviously, what needs to be done is there needs to be more wells drilled and more results known. Hopefully you'll see that from us and others.

Just to shed a little more color on that, there are now four wells drilled in the overpressured -- mapped as the overpressured portion of the Columbia River Basin. That aerial extent is about twice the size of Connecticut. That's not a lot of drilling. All four wells had tremendous gas shows and indications of overpressuring and potential reservoir rocks. We're very excited about the Columbia River Basin short of having a big field discovery.

Great. That's all I had. Thanks, guys.

Your have a follow-up question from Joe Allman of JPMorgan.

Hey, again, everybody. On the Utah Hingeline play, what's the status with 3D seismic over there?

Well, we're not really -- we don't -- these structures, the ones without intrusive rocks in them are large in structural height, as much as 3,000, 4,000 feet in structural height. So 2D seismic is at this point is only needed to determine the tops of these features. Upon a successful well, it would make sense for us to shoot out the feature with 3D seismic, because as with most normal overthrust fields, they are fairly complex with a series of cross faults when they're ultimately drilled. But to see if the structure is containing hydrocarbons, I think we feel very comfortable we can do that with 2D. And the 2D is all new vintage 2D that we've recently shot.

Okay. That's helpful. Back to the north Newton field. What are you thinking now based on what you know are the costs per well and the reserves per well over there?

Well, it's going to be a -- it's probably a little too early to comment. We have really on the -- especially in the James Gray number two and the upper Wilcox, we have very little data points now. This is only -- this oil that we're seeing from the upper Wilcox is only recently, so I think it's a little too early to tell as far as the reserves from the upper Wilcox. From what's been stated in the past the lower Wilcox we feel comfortable with and as far as completed well cost, the lower Wilcox is only 1,000 feet deeper than the upper Wilcox. It's not a -- these are not significantly more expensive than Newton wells.

They are wells that are drilled to the lower Wilcox, have been costing approximately $3.5 million per well.

Great. All right, thank you.

Your next question is also a follow-up question from Michael Bodino of Coker and Palmer.

Hi, guys. I got a couple more here. I got cut off before I got through them. On the Howard Ranch, is there any infrastructure issues if you want to drill a bunch of wells in that area?

Well, there's, obviously, we have to lay a pretty extensive gathering system, but that's fairly inexpensive and fairly easy country to do that in. There are interstate pipelines running north-south through the Madden Anticline down to the southern Wyoming that connect into a bunch of east-west lines with excess capacity. So from a macro level, there is excess capacity in the interstate pipelines and we will be looking at constructing and we will be designing our development program around a Delta-owned gathering system.

Okay. In the Paradox, lump this together in Newton, are you going to be doing any new exploration this year, whether it's for the Gothic shale. I know you mentioned about another feature, a plastics feature that, similar to Greentown you were going to target, but are there anything beyond that that you're going to target in the Paradox? And then also, on the Newton field, any additional structures that you're going to try to target this year?

Sure. Let's start with the Newton field, Michael. We are definitely doing some more exploratory drilling in the shallow Yaywood. Each of these features are fairly small. Again, this is based upon the success of our Aolis well. These are bright spot anomalies that we've identified with our new 3D seismic and we have several of them that actually look better from a geophysical standpoint than the drilled Aolis well. So we will be drilling at least three wells targeting the shallow Yaywood in Newton.

As far as the deeper Wilcox drilling, I think most of that will be confined to the north Newton feature and some continued development of the Newton feature itself. The Newton field. In the Paradox Basin, we're currently trying to drill a well that we're -- a prospect we're very excited about that's a look alike and very analogous to Greentown. So it's more of a salt anticline play. We do also have a Gothic shale play, which we have been involved with for quite period of time. As you know, some of the people that were responsible for Hamilton Creek and Andy's Mesa are employed here at Delta. We've known about play that for quite a while. I don't know if we'll drill that this year. That does have some winter stipulations. But we will drill the one that's similar to Greentown.

Last question for me. You have a rig, obviously a DHS rig up in the Columbia River Basin. What are your plans for that rig beyond its current operations?

Hot potato.

We'll answer it by saying that DHS rig 7 is in the Columbia River Basin.

To stay?

It's there, it's there.

Okay. Thanks, guys.

Thanks, Michael.

Your next question is also a follow-up question from David Tameron of Wachovia.

Hi. One more question left. John, can you dummy down for me, you talked about aeromagnetic, doing a little bit of that in the Hingeline. Can you tell me -- is that just the anomalies that you don't see on the 2D or 3D shoot? What exactly does that give you, or get you?

From the geophysical world, the velocity contrast from some of these igneous rocks, and the host rock that you can find this in being the Permian vaporite is fairly similar, and so they don't really stand out geophysically -- or don't stand out as well. The magnetic data, which a lot has been used in the mining industry trying to locate these igneous intrusive bodies, the igneous rocks stand out much more readily. The only confusing thing is there are also surface volcanics, which would be on the neighborhood of basalts. So there is a little -- there is some information that needs to be garnered into the model concerning the shallow volcanics and the deeper intrusives. Obviously the deeper intrusives are the ones that we're after, trying to stay away from. Because until you either identify them with aeromagnate or drill into them, you don't know that they're there. So the aeromag data has been flown and we have acquired it and are processing it and have seen it and it does depict the igneous intrusive bodies much more readily than the geophysical data does.

Thanks for that explanation. Then in the Paradox, what's going to be the cost of the pipeline and have you -- are there going to be other partners in there with you? I mean is Encana or Barett or anybody else looking to jump into that?

David, it's Roger. I'm not -- we're not quite certain what the pricing of the pipeline itself is going to be until we have a little bit better handle on the size of the pipeline that we will install. The intention at this point is that Delta will construct, own, and operate the line.

All right. Thanks.

You bet. Thank you.

Your next question comes from [William Shaw] of [Drain Sleuths].

Yes. Good afternoon, gentleman. A couple things. You have a $300 million shelf registration for preferred stock, I was wondering if you might be looking to take some of that? Also, can you kind of give us an idea as to what actually you found at the bottom of the Joseph prospect when you got to the intrusive and you began to move away from it a little bit? Were you expecting that perhaps the volcanic activity was causing the landed air to melt down and perhaps take gas and oil that was there, and perhaps burn it up or eliminate it? Or if you can give a clarification as to what actually you found down there?

This is John. I'll answer a little bit of what you find. It's not anything dissimilar that you find in a lot of these igneous intrusive rocks. They bring up gases from -- essentially these rocks are sourced from [lacolus] or [bacolus] or ultimately from the core of the earth. They bring up various different inert gases like CO2, nitrogen, sometimes helium. That's fairly common in different areas throughout southern Utah. I think it's fairly safe to say that we saw that type of inert gases at the bottom of the well. And I'm sorry, the first part of your question --?

The preferred stock shelf registration, $300 million. Is that still available? Any thoughts of maybe using some of that to enhance your drilling?

Yes, no. That shelf is a universal shelf. It's not necessarily a preferred or anything else shelf. We raised money back in January. And at this point in time, we're comfortable with where we sit in terms of being able to fulfill our 2007 CapEx program.

All right. Thank you very much.

Thank you.

Your next question is a follow-up question from Jack Aydin from KeyBanc. Sir, go ahead.

Hi. John, you threw out there a teaser. I'm going to follow-up with it. You said four wells so far drilled in the Columbia River Basin. Are you considering the shale well one of the four, or it is a new -- somebody else drill the four?

No. In the overpressured portion of the basin, I'm referring to two old shell wells and two recently-drilled wells.

Okay. Also, you said all four hatched gas shows. Can you little bit elaborate a little bit more what you're talking about?

No. I just meant along the idea of that we think that this is a basin-centered stacked sand resource play that has good sourcing, we believe that the overpressured portion of the basin should encounter natural gas and as far as drilling in this part of the overpressured section, we are seeing natural gas. That's as far as I can really go with that, Jack.

Well, the next question for me is this. You mentioned the guidance of production 4.3 to 4.6 for the quarter. Does that include the assets sold or exclude the assets sold? Is it clean number?

No, Jack. That includes the assets sold that will continue to be booked until the sale closes.

Okay. Thank you.

Yes, thank you.

[OPERATOR INSTRUCTIONS] Your next question comes from [Ron Sanchez], a private investor.

Guys, just, my question is regarding the Austin Chalk. How many successful wells have you drilled there and how many more do you intend to drill, and what are the approximate reserves per well and for the field?

We've drilled three successful wells, although the third one is currently being put on. The second well, which was essentially redrilled is successful in that it's got a very reasonable reserve recovery -- expected reserve recovery associated with it, but the well cost was quite high because the southern lateral had to be completely redrilled. I think at this stage, if a single lateral well is expected to produce on the order of 5 Bcf equivalent and a dual lateral well is expected to produce approximately 10 Bcf equivalent, and that is what we've experienced thus far with the first well that we drilled in the field, which was the best Kennison and was put on production at the beginning of January a year ago.

Our future drilling, we think that geologically we understand where the better part of this area is and so our future drilling will be focused on that portion of our leases where we're trying to recreate the production results we experienced in the Best Kennison well.

And on that Best Kennison well, I know it started out about 16 million cubic feet of gas or something like that and a couple thousand barrels. What is the current production, how much has it fallen off?

That well has exhibited very consistent decline with average horizontal chalk wells in the area. I think today that well makes on an 8/8 basis about 3 million cubic fee of gas and 250 million barrels of condensate per day, and that's after 14 months of production.

And how many more wells do you intend to drill there?

We're not sure. As we've referenced before, we obviously had it in the package for sale with Tristone and I think once we -- once the buying market might have a little bit more clarity about what our position is, you may very well see this property up for sale again.

And what do you -- are you currently estimating what potential reserves around 25 billion? You said it was 20% of 111 million?

That's correct. Well, 20% of -- yes. That is correct and that includes a couple of proven undeveloped locations.

And ballpark figure-wise for -- what is a billion cubic feet worth in the market down there, just just ballpark-wise?

It varies dramatically depending upon decline curves and everything else. Theoretically, Austin Chalk wells would bring more in the way of price per Mcf equivalent or price per barrel of oil equivalent because of the high initial cash flow associated with them, but I would expect that a $3 per Mcf equivalent-type number wouldn't be out of the realm of reality.

And what would that make 25 billion cubic feet worth at $3 per Mcf?

Well, 3 times 25.

Oh, okay. That's simple. All right. All right, well, Bob, I thought you were talking about billion cubic feet versus the Mcf which is -- okay. Never mind.

Yes, okay.

Okay. Thank you, sir.

There appears to be no more questions. I will now turn the floor over to you for any finishing remarks.

Okay. Thank you all for joining us for the 2006 earnings conference call. We'll talk with you all soon. Thank you.

This concludes today's Delta Petroleum conference call. Please note the following. If you've missed any portion of today's conference call, you may dial into the digital replay at 1-877-519-4471 for domestic parties and 973-341-3080 for international parties. All parties must enter the PIN number 8437408 followed by the pound sign. The replay will be available from March 1, 2007, until March 8, 2007. You may now disconnect.