Par Pacific Holdings Inc (PARR) 2005 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. My name is Nelson and I will be your conference facilitator today. At this time, I would like to welcome everyone to the Delta Petroleum six-month transition period earnings conference call. All lines have been placed on mute to prevent any background points. After the speakers' remarks, there will be a question-and-answer period. (OPERATOR INSTRUCTIONS).

Certain statements made in 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. Thank you.

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

Good afternoon. Thank you for joining us today for the six-month transition period earnings conference call. I have got with us today John Wallace, our new President and Chief Operating Officer; [Brock] Richardson, our Vice President of Corporate Development, Dave Donegan, our VP of Corporate Communications; Kevin Nanke, our Chief Financial Officer and Stan Freedman, our General Counsel.

I will be leading you through most of the presentation this morning and then when we get to the question-and-answer period, John will be available to answer questions related to operations, which may be a topic for conversation as we go forward here.

The headline of our press release today is that we have experienced 20% proven reserve growth to 269 Bcf equivalent as of calendar year-end. We are very pleased with the increase that we have experienced. I would also note that, over the last 18 months and from our last K filing period of June 30, 2004, we experienced 60% reserve growth in an 18 month period. So 20% in six months, 60% in 18 months, numbers that we think are very good and also have the expectation of being able to continue as we go forward.

With regard to results of operations, a couple of things to note. On a quarter-over-quarter basis, we had a 42% increase in revenue to $29.1 million. Over a six-month period, we had a 55% increase in revenue to $61.8 million. Net income for the quarter was $0.03 per share and net income for the six-month period was a $0.01 per share loss.

The items that materially affected the performance for the three and six-month period are worth some discussion. We had ineffective gas hedges, which we reported on the last conference call that we had, largely related to the blowout in pricing related to hurricane Rita at the end of the September 30 quarter.

At this point in time and with gas prices at their current levels, we are essentially in a situation where that is not a concern or not an issue with the current pricing levels that we have. You can see that during the six-month period, we had an unrealized loss related to ineffective derivative instruments of $9.9 million. We also $8 million of realized loss related to our costless collars being quite a bit under what the high prices rose to during the period.

The other thing worth mentioning under items that materially affected the results are the part here where we discuss higher exploration and dry hole expenses of $7.5 million. Approximately half of that is related to new seismic activity. Much of that seismic activity in the six-month period was related to our 3-D shoot over the Newton Field in Newton County, Texas, which has yielded very good results.

While we will not have a significant amount of continuing seismic cost going forward in the Newton area, we do expect that we will probably be incurring on the order of about $2 million per quarter in seismic costs on various other areas that the Company currently owns.

With regard to the other half of the $7.5 million expense item on that category, that was largely related to three dry holes and the prospect fees associated with the drilling of those dry holes that were done with nonoperators. We had three areas where we participated as a nonoperator on three new ventures with actually three separate companies. Those ventures were exploratory situations that resulted in dry holes and will not have any future development or attempts associated with them. So we have approximately $3.5 to $3.75 million worth of cost associated with that activity and I would put that in the category of non-recurring as we go forward.

Moving to the next section in the outlook for 2006, I think it is important to emphasize all of the things that are going on in 2006 and all of the things that will be realized and known by the Company during calendar 2006, many of which will occur within the next six months. We have a substantial amount of activity that we have been building for, as you all well know. We have spent a large part of 2004 and 2005 building a property inventory, a personnel inventory, a drilling rig inventory that will give us the platform for very substantial growth going forward. And we are in a position today where we have begun to realize some of the value associated with these many different assets. As we go further into 2006, we will have results from virtually everything that has significant potential value to this Company.

Notably, during the course of 2005, we expanded our ownership in the Piceance Basin, began a continuous drilling program in the Vega Unit, which is performing very well at this point. Also acquired an interest in the Garden Gulch field. The Garden Gulch field is the field that is also in the Piceance Basin that is now being operated by Berry Petroleum. Many of you have probably seen the announcement last week, on March 1st, wherein Berry Petroleum identified that they have now closed on the acquisition of 50% working interest in the Garden Gulch field that was owned by Orion Energy Partners.

We own a 25% working interest in that same field and we will be participating alongside Berry Petroleum for their drilling plans in 2006. Both areas in the Piceance Basin are expected to add significantly to both daily production rate and proven reserve growth.

In addition to that, we have had recent very good successes in South Texas. We have talked about previously the Austin Chalk well that we put on at the beginning of the year, which is still producing at a very high rate, approximately 10 million cubic feet of gas and an associated 825 barrels of condensate per day today, 60 days or a little bit more than 60 days after initial production.

We have begun drilling a second well on that property being drilled by a DHS rig #9 with the expectation that we will leave that rig in the area to continue to develop our ownership. We have a number of additional locations remaining to drill.

Also during the quarter, we drilled to total depth on the Sligo formation well. That is the deep structure that we saw in 3-D seismic below our currently producing Opossum Hollow field in McMullen County, Texas. This well looks as if it will be a very good producer and has probably opened up will be additional development opportunities on the structure that has been identified and we will have completion activities occurring very soon. We expect to have the well completed actually this weekend.

In addition to that, the 58 square miles of 3-D seismic that we shot over our Newton Field last year and have now interpreted has identified a significant number of additional opportunities as we had hoped. We have found or identified a couple of other large Wilcox structures, which seem to be very similar in nature to the producing Newton Field. We have also identified numerous other shallow opportunities on that 3-D seismic shoot. So one of the other things that will be occurring this year is our drilling activity will expand to not only developing the Newton Field itself, but also testing some of these other 3-D seismically defined features that we have in the immediate area around it.

We have also, in anticipation of a lot of this, continue to build the rig fleet of DHS Drilling Company. As of year-end, DHS owned 11 rigs. As of today, DHS has another four rigs under contract, which will be closed on within the next 30 days giving DHS a total of 15 rigs, most of which have a depth rating of 10,000 to 16,000 feet and 10,000 to 16,000 feet is the primary depth of virtually most of our currently drilling properties other than the Howard Ranch area where we are drilling to 19,000 and 20,000 feet and DHS does own two 20,000 foot rigs to accommodate drilling of those depth as well.

And as important as anything else here, I think it is important to point out that our technical personnel especially has increased substantially and with the intention of handling a significantly increased drilling budget going forward. For this year and in our 10-K, you will see that we're anticipating a drilling capital expenditure budget of $150 to $195 million and the expectation that as time goes on those numbers will be increased as well.

I think also it goes without saying we have and will know the results of two very significant projects within the next four months. We have the expectation that as DHS rig 7 moves to Columbia River Basin in the state of Washington, which we expect will be very soon, DHS rig 7 is currently on a well in the state of Wyoming for the same operator, but is expected to be moving literally within a few days, if not a few weeks, and drilling results will be known later this spring from the initial activity in the Columbia River Basin.

In addition to that, we are currently working on and permitting both our Utah Overthrust play, our Hingeline product in central Utah and the other locations that we have been telling you about in the Paradox Basin in southeastern Utah as well. All of these areas have the potential to experience very large reserve recoveries in the event that we experience success on the drilling activity. And certainly with regard to the Columbia River Basin properties and the Utah Overthrust play, the potential reserve recoveries will be very large by comparison to most of the other drilling activities that we have going on.

We will move to production guidance and once again talk about a revision downward for the quarter, for March 31, 2006. We had originally put out an estimate suggesting that we would have 4.6 to 4.8 Bcf of production during the March 31 quarter. We are revising that downward today to a 4.1 to 4.3 Bcf equivalent number for the period. The primary factors affecting this revision are a couple of things. The first being our Sligo well, which we do think has very good productive capacity associated with it. This well was originally expected to be hooked up and selling gas in early February. We have been informed of a couple of changes in the timing by the pipeline company recently. Initially, they had move that number to March 1 and just recently they have now moved it to the first part of April.

The biggest problem there being the pipeline company that is responsible for building the pipeline was acquired by another pipeline company and the acquisition of the pipeline company closed during the month of January. We had originally been informed that that would not affect the scheduling of our pipeline and I suppose, as is typical in situations like this, it did in fact end up affecting the timing of the pipeline itself.

We also note in here that the Castle Energy merger has not concluded yet. We are still waiting for the SEC to allow the S-4 document related to the merger to go effective. At this point in time, we expect that that will occur in early April. There is production associated with Castle Energy in the Appalachian Basin that we will begin to book as soon as the merger is complete. It too was originally expected that the Castle merger would conclude in early February. Unfortunately, that timing was not allowed to be met. Castle Energy's financial statements went stale and the end result was added time to the process to declare the merger effective.

So in any case, the requirement was that production guidance be reduced. Related to this, I think it is worth noting at this point in time that as we sit today, the Company has between 15 and 20 million cubic feet equivalent per day behind pipe from wells that have been drilled and will be coming online at various stages between now and the next two to three months.

There have been very good drilling results experienced in virtually everything that we are operating. On a go-forward basis, we would certainly expect that that success will continue because much of the drilling we are doing is in areas where we have already experienced that success. I believe that in spite of the fact that we are going to have to or did have to reduce our production guidance for this quarter, we will experience quarter-over-quarter production growth and probably in meaningful amounts.

Because of what has been a continuing situation of revising downward our guidance on a quarterly basis, we have made a decision that on a go-forward basis the way we will handle production guidance information is to predict guidance for the quarter that is very largely related to what our current daily production rate is at the beginning of the quarter with anticipated normal declines.

In addition to that, we will go into a discussion about the various areas that could have a positive impact on each quarter's performance going forward and identify some of the challenges associated with each of those areas that may cause either delays in timing of pipelines coming on, delays in timing of hookups related to weather, depending upon what time of year it is and try and be in a position where you all have a little bit better ability to predict along with us what some of the things are that would affect the positive increases on daily production during a given quarter.

So expect that around the end of March, as we get to the end of this quarter, we will put out production guidance for the June 30 quarter and it will be based on the comments that I just made.

Our current daily rate today is approximately 48 million cubic feet equivalent per day. A couple of comments about that. We put out a press release at the beginning of February saying that our production rate was approximately 53 million cubic feet equivalent per day, which it was. The difference in those two numbers is somewhat normal decline, but probably largely decline related to Austin Chalk wells. We had identified in the January 10 press release that we had put out that the Austin Chalk that we had drilled was performing very well. It has continued to perform very well, but we also referenced that a typical decline curve for an Austin Chalk well has very high initial decline rates followed by a shallower rate after the initial six months of production. So what you see there in the difference between 53 and 48 is largely related to what I will call normal Austin Chalk decline.

The 48 million a day could obviously have been positively impacted by a number of different things, including Castle Energy and Sligo. The likelihood is those things will contribute more to next quarter than to this quarter. As an example, and I won't go into a lot of detail here, I'll leave it for discussion on the operations update section, but as an example at the Vega Unit, we are currently drilling with one rig full time. The expectation is that we will increase the number of rigs drilling on the Vega Unit in the summer months after we have had the opportunity to build more locations, but in the meantime, we are restricted by the current capacity of the pipeline that services our area.

There is a new pipeline being built. That project has been under process now for about six months. The expectation was that that pipeline would be operational by the middle of May and we have the pipeline company telling us as of yesterday that the anticipated dates for startup of that pipeline are now somewhere between the middle of May and the middle of July. You can see that that type of situation will have an impact on the individual production performance of a given quarter. By the middle of May, we will probably have on the order of 10 million cubic feet a day behind pipe waiting on pipeline at the Vega Unit. If that is allowed to go on production in the middle of May, it will obviously have a positive impact on the June 30 quarter. If it is not allowed to go onto production until the middle of July, it will have no increased effect on the June 30 quarter.

So these are the type of things that we will be dealing with going forward and explaining to you in future press releases. Let's see. I have already referenced the fact that DHS has grown to a total of 15 rigs that are currently 10 rigs in the field. The other five rigs will be in the field and working or will be operational for DHS I should say at various stages over the next 45 days. By the middle of April, all 15 rigs will be in the field and available to Delta for its use.

With that, I will recap briefly our expectation for the coming year. We have a number of areas that are going to have a significant impact on what we do or potentially have a significant impact on what we do here and what the valuations of Delta are, many of which will be drilled and known in the first six months of 2006.

We at Delta are very excited with the prospects of what we have in front of us and with that, I will go ahead and open up the conversation to questions related to anything in the press release. Thank you.

(OPERATOR INSTRUCTIONS). Ron [Sanchez].

Congratulations on tremendous growth. I was just wondering -- you mentioned you had almost $10 million in unrealized hedging losses. Is there a chance that since it's unrealized that some of this will be recaptured?

Based on the fair value of the prices that are realized today, we will probably end up still realizing that. You can tell by the last quarter, we took in about -- or over the last six months, we realized $8 million of a loss. So I'm guessing that unrealized will actually go into a realized position.

Okay. The second one -- my question was regarding your Best Kenesson well. It dropped from a couple thousand barrels a day to about 800. Where do you expect to -- and I think your gas production from 15 million to 10 million -- where do you expect to see that well stabilize or do you have any expectation yet? What kind of reserves do you anticipate for this field?

This is John Wallace. We have done quite a bit of modeling in this area as far as the other wells. There are probably in the neighborhood of 30 to 40 wells that we've used to model the Austin Chalk performance and decline curve prediction. I will say our well is exactly on trend of where it ought to be as far as the average decline rate for the area. It has already made the turn and is beginning to -- the decline rate is dramatically lessening here.

Most of the decline in an Austin Chalk well happens in the first 30 days. We had seen again a dramatic decrease in the decline rate and it has been actually fairly stable here for the last three weeks. Based upon that, the ultimate reserves are in the 10 plus Bcf range. We will no more as we are a little further down with the decline on itself, but it is very predictable compared to the other wells in the area.

Well, I guess what I was kind of wondering about was I think you are going to be drilling around 14, 15 other wells in this same area. Do you have any idea what the total size of the reserves from that field might be?

What we know so far is what we expect from this well and as John had pointed out, we anticipate that we will recover about 10 Bcf equivalent reserves from this well. That is very economical, especially at today's prices and taking into consideration the cost of drilling these wells. Will we experience 10 Bcf as an average per well across the area? It is certainly possible given the results of our well and the results of some other drilling by Anadarko.

I think what we have done internally is use a larger sampling of Austin Chalk reserve recoveries that actually extend over an area that is quite a bit greater than just the 15 unit area in which we own an interest and the average Chalk wells that we have identified in the area that we are drilling and that have had dual laterals drilled in them, that is another important aspect. Average is about 8 Bcf per well as a gross recoverable reserve number. So I think it's certainly within expectations to assume that we would have something on the order of 100 Bcf plus in gross reserves for the area that we are currently drilling.

Also you mentioned on the release that you're currently drilling that second well. Has there been any indication yet in terms of success or failure and it is another dual horizontal I assume?

It will be another dual horizontal. We are drilling the vertical section of the well. We will be making the turn and beginning to drill this well horizontally here in the next two to three weeks.

It will also take approximately another 45 days from now until the well will be accomplished. Once you begin drilling the dual laterals, each lateral is likely to take on the order of three weeks.

Larry Busnardo.

Just a follow-up on the previous question in regards to the Chalk. Can you just update is in regards to well costs that you saw in the first well and then what you expect those to be going forward and then the number of wells that you will be drilling this year in that play?

Yes, Larry. We have a rig running full time in the field. We are modeling $6 million as a completed well cost for these Austin Chalk wells gross. We are fairly comfortable with that based upon our previously drilled well and other operators' cost in the area. We will again be drilling on a continual basis. There might be a period down the road that we could add some additional drilling activity, but DHS rig #9 is in the field right now and will drill these wells every two months.

We have an average --

Sorry. Go ahead.

We have an average 40% working interest in what we're drilling right now. Some units are a little bit less than that. Some units are a little bit more than that. Actually the well that we're drilling at the moment is a little bit more than that, but the average through the area is approximately 40% working interest.

Okay. Switching over to Howard Ranch, can you talk about that a little bit, what you have seen? You talked at -- the last two stages have got you producing in excess of 3 million a day on the 36-13 well. Can you just talk about what has changed there, your thoughts on that well and where do you think it could be once you get out there and you frac some additional zones there?

Sure. Let me first talk about the Copper Mountain well, which we have just drilled, and then I'll talk about some of the results from the Diamond State well. But the Copper Mountain well we just reached a TD of 19,100 feet. It is the first well we have drilled completely through the Mesaverde section. Based on log calculations, we have three times the net pay in this well as any other well that we have seen. We have got almost 400 feet of net sand in just the Mesaverde section -- excuse me -- the Meeteetse and the Mesaverde section alone in the Copper Mountain well.

We had tremendous flares while drilling and then an important facet of this play is that we saw a higher degree of overpressuring than we have seen in the past. And our pressure gradients were approaching 0.8, which is what we would expect from where we drilled the wells, why we located it where it is. We are more in the Basin centered portion of the particular play.

Having said that, we're really excited and look forward to anticipating completing the Copper Mountain well based upon what we have learned on the Diamond State 36-13. We're very encouraged that we have changed our frac design a little bit and are seeing the expected results or the increased results. We are now doing what our frac engineers refer to as a hybrid slickwater weak crosslink. What that is is a portion of the frac is more the slickwater in design, but it has a weak crosslink, which allows us to actually get into this tight rock and it is important for us at this depth.

The net effect we are seeing in our last frac stage at pretty sustained rates in and around 3 million a day. It is only two sands, the Mesaverde section. The Diamond State 36-13 has 16 total sands. We have now completed six and we are currently at a rate that is higher than we modeled for all 16.

Having said that, I don't want to comment on exactly what we expect all the Mesaverde to produce, but I think at this point it is safe to say it is more than we were thinking. Again, the Copper Mountain well has three times as much sand than the Mesaverde, so we're real excited in this deep rock that we are seeing such high degree of overpressuring. We are seeing no water and we are seeing pretty sustained high initial gas rates.

We are continuing -- we're in the process of finishing the Mesaverde completion and the Diamond State 36-13 and then we are very hopeful that all these zones will be additive like we modeled and that the well will be able to produce at rates significantly or at rates at an increase of where it is currently producing, which is, and again, around 3 million a day. So we really have made some strides in our frac technology, our frac design, the materials that we use. We knew that this was going to be important to this play.

Other plays like this have gone through a similar amount of a learning curve if you will. I am not saying that we've totally cracked the code or we have finished advancing our frac technology, but we sure made some big first strides here recently.

That 3 million a day rate, how long has that flowed at the rate?

It has only been a week.

10 days. But on some of our previous fracs, just to give you an idea, we had individual frac days that come on at 2 million a day and at this point, would be down to half a million a day, but would be fairly flat at half a million a day.

Comparative performance at this point is much better.

Do you wait for that rate to come down or do you go right into completing the other sands in the Mesaverde?

We're not seeing any water. We are going to continue on with the completing of the Mesaverde. There is nothing on logs that would be suggested that this sand is any different than the sands above and below it. We are just very hopeful that the technique we have used to complete it is the important factor here.

And once the 35-13 is completed, which location will you go onto next?

Well, what we will be doing there is we have -- if you all remember from previous press releases, what we had to do on the Gates Butte 10-17 well, which was our earning well in the Stone Energy farmout that we had, we got to a depth of approximately 13,000 feet in mid-December and ran into winter stipulations and had to set 7 inch casing to 13,000 feet and move the rig off of that hole.

So the next operation out there will be to finish drilling the Gates Butte unit 10-17 well. We will take it down all the way through the Mesaverde, which is expected at that location to be at about 16,500 feet. Then after that, and as we have discussed before, we will go ahead and remind that our plan after drilling that well to total depth is to move back over to what we call our West Madden acreage, the western acreage that we own. We will be drilling a 20,000 foot Cody test that will probably spud sometime early this summer after the Gates Butte unit well has been drilled.

We've done a lot of work on the Cody recently as well. We note that -- the thing that caught our attention initially and early on a well that will recover approximately 10 Bcf from the Cody. It is about a mile off of our acreage to the East and in further review has identified a number of very large Cody wells on trend, this 10 Bcf well being the westernmost of those wells, but there are a number of wells that have produced between 10 and 30 Bcf from the Cody formation that are on trend with our acreage and immediately to the east of it. So we will be testing that zone this summer.

Certainly we will expect Lance and Mesaverde reserves in that well also, but given the size of recovery from the well just from the Cody just off of our acreage to the East, we believe it warrants the drilling of a Cody test.

Larry, this is John again. Let me just make one quick comment that this new frac that we are using in the Mesaverde section so far is cheaper than the fracs that we were doing in the past. We think that we might even be able to decrease the completed well cost. When you have a portion of the frac or a major portion of it slick water, or actually water, it's going to lower the cost of the fracs.

Do you just keep the one rig active or are there plans to bring in a second rig here?

At the moment, it is one rig and I will tell you that is largely related to current gas pricing. At $6.50 NYMEX gas prices, we are getting about $5 per Mcf at the wellhead at the Howard Ranch area in the Wind River Basin. When you are drilling wells that are 19,000 to 20,000 feet deep and spending somewhere between $8 and $11 million per well depending upon how deep you go, the economics start to get thin enough at $5 per Mcf at the wellhead that we look at it and say instead of accelerating activity, we should just continue with our current activity and under the assumption that prices will rise again, that would be the time at which we would look to increase activity.

At what point would you cut back? Have you given that any thought?

$4 per Mcf at the wellhead.

At $4 you would look at the program and then decide at that point whether or not to continue drilling?

At $4 per Mcf at the wellhead I think you, in spite of the fact that we've got large per well reserve recoveries, you would have to look at the cost of drilling this area and say do we drill it at a $4 per Mcf at the wellhead price. Now if we thought that $4 per Mcf was going to be very short-lived, it probably wouldn't have an impact because these wells do take 90 days to drill, but if we thought $4 was going to be an environment that we would experience over a longer period of time, then, yes, that is the type of thing that would cause us to back off continuous drilling activity up there.

It is also worth pointing out that historically in the Rocky Mountain if gas prices approach those kinds of numbers that differentials generally come down and that translates probably into a less than $5 NYMEX price in a historical trend.

Okay. Thanks.

Michael Bodino.

I have a few questions. Larry got most of them. But one of the things -- a couple of things we haven't talked about I wanted to just kind of get an update on -- back in the fourth quarter, you announced some progress with the offshore California litigation. It has gone radio silent on there. Is there any progress this year since everybody has reconvened in Washington?

Well, yes, I think a couple of comments there. The first is we have an open piece of that litigation. To remind everyone what we have received so far is a $1.1 billion award from the federal judge in the case for lease bonus recovery. We have an additional open claim to recover our sunk costs, which is or exploration related expenditures and when I say our, I mean Delta and 11 other companies. Our exploration related costs. Those costs are also very substantial as well.

So what has happened in the meantime is the judge has put some definitive timeframes on that part of the litigation process. He has put a time frame on discovery for that part of the case and has indicated that he is likely to set court dates soon after the discovery process has been accomplished. So from the litigation side, it is moving forward.

I think it is fair to say in the meantime that on a behind-the-scenes effort, we are exploring the possibility of a negotiated resolution given the fact that we do have a judgment at this point in time.

Second question, I know one of the things you mentioned relative to the March quarter and some of the deferrals of production had to do with Castle. I know originally this was supposed to be a February deal or closing and with the delay there, with the SEC review, obviously Delta is not going to end up with the production, but the production is being converted into cash flow. With the changing in stock prices, commodity prices, is there going to be any change to the effective date or is there going to be any amending of deal terms or everything is agreed upon and just waiting for closing?

Yes, no change to any of the deal terms. We are all just waiting for closing. Deal terms are all staying exactly the same.

Is there any more information relative to how the production is held up and/or what their current cash balance is?

No, their current cash balances are essentially what has been reported before mainly because they did -- during this process, they did pay the ChevronTexaco litigation settlement number, which was previously announced at $5.75 million. I think cash balances that have been reported before our largely the same as what we have had out there.

With regard to Castle's production, their production is old, very mature production from primarily the Devonian Shale and the Appalachian Basin that exhibits a very shallow decline rate. So Castle's production is essentially not much different from what it was six months ago.

You have had pretty good drill bit success over the last six months and it has ended up being a nice bump in reserves, but you have got quite a bit of deliverability that is currently shut in. Is there any way -- I know you mentioned specifically the Sligo and Castle. Could you give us a little more detail on what is currently shut in terms of deliverability in the Piceance, Howard Ranch, Austin Chalk or whatever you have out there?

Let me do that and then if I miss anything, John, you can make a comment as well. In terms of the Piceance Basin and when I refer to the Piceance Basin right now, I'm referring to both our Vega Unit that we are drilling plus the Garden Gulch field development, which has had a number of wells drilled that are not yet completed. The expectation at this point in time is that we have, on a net basis to Delta as of today, somewhere between 7 and 10 million cubic feet behind pipe from those two areas.

The Garden Gulch field as we understand it will be begin to have wells completed here very soon now that the merger -- not the merger but the acquisition of the Orion Energy piece by Barry Petroleum has occurred and then with regard to the Vega Unit increases, as mentioned before, that will happen and only be experienced once the new pipeline is operational.

The new pipeline is expected to be operational somewhere between mid-May and mid-July. So can't really say exactly when, but sometime in that time frame, we will get increases there. Plus, between now and then, we will probably drill another five wells with the one rig that we have currently running and our wells on average have been coming on at rates of about 1.5 million a day.

The Sligo itself, I think we have mentioned before, the expectation around here is that we are probably going to see initial production rates of somewhere between 5 and 10 million cubic feet per day. When I had referenced earlier that we had 15 to 20 million cubic feet a day behind pipe, I was using the 5 million a day number for Sligo.

Castle Energy, we have a couple of million a day net there. And then certainly up in the Howard Ranch area with ongoing completion efforts of both the Diamond State 36-13 and the Copper Mountain 35-13 and with the recent results that we have experienced there, we are only using in this 15 to 20 million a day number, we are only using 3 million a day from the Howard Ranch, but I think it is fair to say that our hope is that what we experience will be quite a bit better than that given recent results.

Austin Chalk, you brought up, certainly the only new Austin Chalk production that we will have is will be by virtue of the well that is currently drilling. It is not expected to be completed and selling down the line probably until the latter half of April.

My last question relative to DHS Drilling, I know you're getting rigs and there has been a lot of questions with the recent softness in natural gas prices. Are you still seeing a lot of third-party interest in those rigs and have prices stabilized? Has there been any weakness or any strength in pricing for the rigs?

Yes. A couple of things on DHS. As we were going through the year-end financial numbers and looking at the performance of DHS for '05, we noted that between June of '05 and February of '06 across the board and as an average, the dayrates at DHS increased 40%. What we have experienced in the last 45 days is that there certainly have not been any new increases in dayrates. There is not an expectation that we will have additional increase in dayrates, but we have also not noted any reduction in activity from the operators that we were drilling for. Nobody has informed that they will be cutting back their drilling programs accordingly. So the expectation is that if no one cuts back their drilling programs, then dayrates will likely stay where they are.

Robert [Lind].

Roger, would you update us on what your plans are for the DJ basin acreage? Has that program been put on the back burner?

Yes, actually no. It has been in a more extensive review process here recently. We do reference it in our 10-K. We are at a position right now where we have had an outside geophysical firm been doing some more detailed review of the 3-D seismic that we have shot. What we have requested of them is a review that would allow us to better identify why we experienced good results from some wells and not as good results from other wells when the initial 3-D review would suggest that both should produce sort of on a comparative basis. So that has been under review and studied by this outside firm for the last 90 days.

They have come to us with a number of different alternatives for additional drilling opportunities out there that include the Niobrara formation, the D sand formation and the J sand formation. So the expectation is that sometime within the next 90 days, we will probably have identified and begin the permitting process on a number of different locations that we will test. Depending upon where you are, it will test one or all three of these formations.

In addition to that, our G&G team has generated six additional prospect lead areas for the Niobrara that are in a part of this region that has more traditional, more mature Niobrara production. They are significantly larger than what we have drilled today in a potential aerial extent. We are very excited about those. We are in the process of finalizing those prospects and those will be something that we focus on this year.

That's all I had. Thanks.

Jason [Phelps].

The first thing is I just want to call your attention to the fact that in your press release for the June 30 proved PBE, it says 65 million at June 30 increasing to 438 by the end of the year. That was a typo. It should have been 365 million. But the question I wanted to ask was that you added 60 Bcf in the last six months. It looks like 24 Bcf came from Newton. I was wondering whether you got additional reserves from Howard or whether the 36 Bcf that wasn't Newton came from this Austin Chalk where you were just describing that you had a 40% interest in 100 Bcf in potential. Can you explain where the 36 Bcf came from that wasn't from Newton?

Yes, well, let me address Newton first. From June 30, '05 to December 31, '05 we experienced an 11 Bcf increase at Newton. We did experience a 24 Bcf increase at Newton for the calendar year. So December 31, '04 to December 31, 05, it was approximately 24 Bcf increase, but for the six-month period it was only 11.

Howard Ranch actually experienced a downward revision and mainly because the Lance formation zones that we had producing in the Diamond State 36-31 were producing at a significantly restricted rate of about 800 Mcf a day and we had not completed the Lance formation reserved in the Diamond State 36-13 or the Copper Mountain 35-13 of course. So when you not only have a downward revision with regard to the producing reserve, you also have a downward revision with regard to the offsetting reserves and this is from the Lance formation itself.

The Mesaverde did not experience a downward revision. We believe that the Lance should not have experienced a downward revision, but our third-party engineers required it. Given that we only had essentially the single well completed in the Lance formation in that particular area.

The other revisions upward came from the Piceance Basin. Certainly we drilled a number of new wells at the Vega unit. There were also a number of new wells drilled at the Garden Gulch field and proved undeveloped locations around that were also booked in the proven reserve number as you would expect them to be.

Having said that, most of what exists in both the Vega Unit and the Garden Gulch field as of today are still in the probable category.

So the renewed reserves came some from Newton and mostly from the Piceance Basin?

And some from the Austin Chalk as well.

But it's a very similar amount from the Newton Field and the Piceance Basin. That's where the bulk of it came. Having said that about the Howard Ranch area, when begin completing the behind pipe zones, those will be reserved adds and will not have the CapEx associated with drilling new wells associated with it. That would just be essentially recompletions. So that would be fairly meaningful.

Okay. Did you complete the 1.5 million share placement that was referred to when you announced the $24 million acquisition of the Armstrong property?

Yes, we did.

What price was that set at? I didn't see a press release on it.

It was $23.76 per share.

That was great. Thank you very much.

[Katherine Ziebolski].

I have a quick question about your hedging losses for this quarter. There was an $8 million pretax realized loss noted in your press release today.

Yes.

And then on the income statement, a $5.3 million net realized loss. I just wanted to make sure that the $5.3 million was the best figure to use in trying to calculate cash flow accurately.

That is a true amount that hit our cash flow, yes. The line up above, which says realized loss, is the true cash paid by the Company, yes. Plus, it's just the change in fair market value of the hedges going forward.

And that was Kevin Nanke, our CFO.

And is that $5.3 million already built into the average realized prices that you issued later this afternoon? The $59.42 per barrel and the --.

I think we -- well, I am not sure of that. What we do is -- it is at the wellhead is what you're probably being disclosed and that does not take that into consideration on that. Our 10-K will show a net number too.

Okay. Great. My second question is about the Columbia River Basin. I see that you guys gave a quick update in your release today. It's much appreciated. I was wondering if you could talk a little bit more about drilling through that first -- basalt layer in the first well that was up there. Cost estimate of how much that first part cost or estimated drilling time in the future, something of that nature.

Well, I think it is safe to say -- I can't comment on cost at this point other than what the operator has published, but I think it is safe to say that there is a learning curve you go through in any new play and that we are seeing evidences of that learning curve.

Having said that, I don't -- I think that it is safe to say that wells going forward will take less time to drill than the current one.

James [Gibbons].

Could you please provide an update on CapEx spending in '06 and if you see sustained lower prices, how that could affect CapEx spending? That would be helpful, please.

Sure. At current commodity price levels, which are 650 per Mcf NYMEX and $60 per barrel of oil NYMEX, basically the only area that would possibly be lower would be the Howard Ranch area in the Wind River basin and that is, as mentioned before, because of the depth of the those wells and the cost of those wells. We have in our 10-K and also in this press release identified that we would spend $20 million in the Howard Ranch area for calendar 2006.

That $20 million is with the expectation that we would have one rig running full time. I think it is safe to assume that if gas prices do not go any lower than they are today, we will spend that and that overall CapEx of $150 to $195 million will not change.

If prices do go lower than this, then the first place to look is for the amounts associated with Howard Ranch to go down. In the operations update here today, we have tried to identify how much we have budgeted by area, which will get you to the $150 to $195 million range. The variance on that range is depending upon -- somewhat dependent upon success in a couple of areas, but also dependent upon the expectation that some service costs may increase as we go through the year.

Could you also comment on availability under your bank credit facility, please?

We are currently going through a redetermination with the bank. As of now, we essentially do not have any availability under our bank credit facility. A couple of comments in that regard. One is that we believe that the borrowing base is likely to be increased by $15 to $20 million this month after redetermination.

We also believe that that would be an acceptable level based on the parameters that we know the bond ratings agencies pay attention to. I would say that, with regard to borrowing base ability, were there not a concern for maintaining bond ratings, the borrowing base would be significantly higher. But we are interested in maintaining the bond ratings that we have and improving on those and as such we expect a reasonably limited increase in the borrowing base.

Given the cash flow in the first quarter and pressure on prices and limited availability out of the bank facility, how would you propose to fund your CapEx needs in the second half barring an increase in gas prices?

Barring an increase in gas prices, we will largely be experiencing the ability to continue our drilling program at its current pace by virtue of the anticipated closing of the Castle Energy transaction. Castle not only has cash in the bank, it also has producing properties in the Appalachian Basin, which are likely to become assets for sale.

Thank you very much.

Michael [Hall].

Just a real quick question -- just a couple of housekeeping on the model. You have got per unit costs all-in. Trend definitely going up. Clearly with additional volumes coming on throughout the rest of the year, those will come down. Just kind of wondering on targets what you guys are aiming for on that level and just more color there.

With regard to which specific expense area?

In particular, G&A seems -- that would be where you could probably do the most work on a per unit basis with just volumes going up and I know you've ramped head count coming into the year. So do you think on an absolute basis you see that same kind of flat still? I think that's what you had said in the past.

I think that one probably more than anything else is likely to come down the most on a per unit cost and the reason I say that is we intentionally ramped up G&A in anticipation of what has become a significantly increased drilling capital expenditure program around here and that drilling CapEx program is just now beginning to show the benefits of both the increase in the staff and the number of rigs busy in the field. We do not need to substantially increase G&A over the course of 2006 to accommodate -- from where it is right now to accommodate what we already have in process.

So as we go forward with this current drilling program and as additional production increases are added, that one area should come down the most on a per unit basis.

Additionally, you have got professional fees for the six-month period that were considerably larger due to the change in year-ends. You know we completed two audits and --.

What are those exactly?

Professional fees had gone from $0.21 per Mcf at June 30, '05 to $0.50 per Mcf at June 30 -- or excuse me December 31, '05 and that is essentially because of a doubling of the effort over a six-month period of time.

I am just more curious -- what are you getting from -- what exactly is behind the professional fee? I am just not familiar with that.

General fees are relating just to our --.

Legal.

Our legal and accounting.

Legal and accounting, all of which is a change in fiscal year-ends.

Fair enough. What about on the LOE front? That was up a decent amount quarter-on-quarter, higher than I expected. Do you have room there where you can improve on a per unit basis or is it flat to up?

I think we do have room to improve on it a little bit, especially as we put on some higher volume wells. Certainly the Sligo, the Chalk are going to be higher volume areas and then with regard to the Piceance Basin, because they are gas wells, the lease operating expense associated with producing a whole lot of gas wells together should be low by comparison to the general makeup. So the expectation is that going forward and as additional volumes are put on here, the LOE as a per unit cost will decrease as well.

You'll definitely see more benefit of that in the Howard Ranch area that only has a small portion of the well contributing at this point. But later in the year, we will have a higher percentage of production contributing to higher volumes.

Okay. Moving to the top line, you're talking about go forward production will be more along the lines of -- here is our daily production, apply a decline rate and here is some upside. You can make your -- take your own stab on that. What kind of underlying decline rate do you think is reasonable on a kind of quarter-by-quarter basis or an annual basis, whatever?

It had been coming down. We had been as high, if you look back at press releases from a year ago, it had been as high as 30% annual rate of decline. It had been coming down to a level more in the range of 24% to 25% annual rate of decline. Because of the Austin Chalk drilling that we are now doing and the steep declines associated with that activity, we are back up in the 28% to 29% annual rate of decline as an average for the Company.

But having said that, I think you will also -- we certainly expect that your production increases will occur certainly more dramatically in 2006 than they have recently.

Okay. And then finally relating to Austin Chalk, what plans if any -- what are your thoughts on expanding your acreage position around there? How prospective is the surrounding acreage in either Polk or Tyler County? Can you comment on that?

This is John again. We are working diligently on that. Since this well that we brought on is the furthest Western well in a series of increasing reserve wells and they are all fairly new, it is safe to say we are working diligently and have numerous people working on that. Also, as far as where we go, it is still competitive and we will comment on it when we actually acquire it.

Fair enough. That's all I got. Thanks much.

Jack Aydin.

I have got a couple of questions. One of them, could you give us an indication what kind of drilling will happen in Columbia River Basin? That is one. The second question -- you didn't mention any potential activity in the Hingeline area, the new acreage acquired and I have one or two follow-up questions.

As far as the Columbia River Basin, as far as I know right now, there will be two wells drilled this year. They are both in various forms of drilling at this point. I think it will have some meaningful results to the Company sometime this summer. In the central Utah Hingeline play, I think I referenced in the operations update that sometime late spring, we will begin developing or drilling the first of three exploration wells. We plan to drill those pretty much in succession and we will at least drill two of those wells this year, possibly three.

Has anybody else drilled any -- do you have any wells or any discoveries or dry holes in the past three to four months in that Hingeline area?

There has been a lot of drilling. I think that there has been a lot of permitting and talking of drilling. I am hopeful that the next field discovery will be the one that we'll be involved in, but it is my understanding that there was a well drilled to the North. I am not familiar with the success of the well. It's far enough away from our acreage position that it doesn't have any relevance. But there has not been a lot of activity, but I think that there will be in 2006.

John, I was under the impression that the Sligo and the Chalk ultimately would be a source of funds for you. And I getting the impression these are [keepers] type of properties?

Well, the Austin Chalk, given the fact that this has a return on investments of multiples within a year is pretty (indiscernible). I will have to admit to that. It does complement our long-lived Rocky Mountain gas production fairly well. I don't think I would be as excited about it if that is all that we had because of the steep declines, but it does again complement a lot of this flat production once either Howard Ranch, Vega, Garden Gulch or even the Niobrara after their initial decline of three to six months generally are characterized as being flat declines. So it does complement that.

The Sligo -- it's a little too early to comment. It is a fracture play. So there are a few unknowns about it. It is a detraction a little bit from our resource, our desire to be involved in developed resource plays, but there again it has a lot of potential. So I think we will just have to see where the market is, where gas prices are, what the appetite for A&D is in the future. But of the two, the Sligo probably doesn't really complement our property set as much as the Austin Chalk and detracts a little bit from our theme of resource plays.

Ed [Kozelka].

Again, back to the Utah Hingeline product. Is most of the acreage that you acquired from Armstrong, would you classify it as C acreage or is much of it BLM land?

It's a combination of the two. That portion of the BLM acreage is not as burdened by stipulations as we find in Wyoming, but it is a combination of mostly state and federal with some fee.

Some fee. So there could potentially be some permitting problems. Have you already permitted the first two or three locations?

We are in the permitting process for the first three locations right now.

Okay. What is the closest town to where you are on the Hingeline in Utah? Do you have a sense for what that is?

South of Salt Lake City.

Well, yes, I know that. Do you anticipate getting any joint venture partners to spread risk with you?

Not at this time.

Not at this time, no.

What would be your primary target at 8000 feet?

The Navajo, which is the same producing zone as the Covenant Field, which also goes by the name Nugget in Wyoming.

Eric [Nuttall].

Just first question on the deep Sligo, with what you have seen from drilling the first well, has your internal estimates of potential recoverables changed either for the positive or the negative?

No, not at this point, Eric. There is a portion of this particular play that relies on fracturing and right now we are waiting and we are anticipating the completion of this pipeline to get this well completed. But we will complete the well prior to the pipeline being in place. But we won't really know that much about the well until we complete it. That is logs don't help us that much.

Having said that, we're at 37 feet high to directly offsetting a well that came on at over 5 million a day. So we are very encouraged, but it is not something that easily translates into rate based on log analysis. So we won't really know until we have completed the well.

I seem to recall that early estimates were around 75 Bcf net recoverables to Delta on success of the entire formation. Is that ballpark?

Eric, we had given a range of 50 to 100.

50 to 100?

Yes.

Is that gross in place or gross recoverable?

That would be gross recoverable.

But we have 98% working interest in them.

Fair enough then. Secondly, on Austin Chalk, there has been a lot of conversation, but how many locations do you have? Is it around 14?

We have an interest in a total of 15 with an average of 40% working interest, but our working interest varies throughout.

And then lastly, on the Paradox, can you elaborate on that in terms of how much acreage you're sitting on now and if it is the shales that you're targeting or any conventional sands?

Yes. We have 50,000 acres. Our prospects -- we have five different prospects. We are going to drill three, the first three and each prospect is around 10,000 to 12,000 acres in size. They are unconventional. They are a combination of shale, silts and sands. We would have liked to have been drilling those by now. We have had some issues with the permitting process with the BLM. We have those resolved now. It just took some time. We will be drilling here -- initially drilling plans here within about 30 days and those wells should take about 30 days each to drill.

And that is 50,000 net acres?

That is gross acres -- no -- excuse me -- that is net acres. I'm sorry.

Net, okay, at 70%. Thank you.

Michael [Scala].

A couple of quick modeling questions. For your reserves, can you give us a pretax [PB-10] number?

A little over one billion.

Yes, a little over -- It should be in the press release, Mike, 1.14 billion.

I'm sorry if I missed it, but did you give the prices used for that as well in the press release?

No, we did not. I don't think we gave the prices used. What are the prices used, Kevin?

I think it was (multiple speakers).

Pretax is 1.14 billion.

Kevin is looking that up.

Okay. I saw where you put the realized prices for the six-month period, do you have them for the quarter as well in that press release or did I miss --?

No, it was not in the press release -- three months realized for the period.

Do you have those as well?

We do. Throw us another question and we will find it for you here in a second.

While you're working on that --.

Hold on, Michael. On the year-end pricing units, it was --

$60 oil.

$60 oil, $60.22 for oil, $9.62 for gas.

I assume those are NYMEX.

Those are NYMEX numbers.

I'm sorry, Michael. Realized through the quarter, $57.54 for onshore oil and $10.59 for gas.

All-in.

$57.54 is all-in. That is onshore as well? $57.54, I am sorry, is onshore and onshore. Offshore is a minor portion of our daily production, but also brings about a $15 per barrel (indiscernible) from NYMEX. So onshore oil is higher than $57.54.

Then finally on the Hingeline play, those three wells that you plan to drill, are those all mutually exclusive? Are they each testing a separate prospect?

Yes.

Yes. They are each testing a separate prospect.

Right.

I think worth noting, we have referenced it before in other press releases, but this -- we are excited by a lot of things here. One of which certainly is the fact that individual structures could hold very significant amounts of remaining or recoverable reserves, but in addition to that, we have the acreage that we own is over what is numerous already identified structural features that appeared to have four-way closures. So we are not testing a single structure. We have -- literally, I think we've actually already identified the number. We have 14 separate structures that have been identified.

Can you say anything as to how they compare as far as size-wise at this point to Covenant?

No.

Covenant, the general expectation is, and this is from various publications that are out there, the general expectation is that they are going to recover on the order of 75 million barrels of oil from Covenant Field. The structures that we have identified and that we own acreage over are all at least the same size as Covenant and in most cases quite a bit larger than the Covenant Field structural size. In addition to that, we also have the expectation that the structures could very possibly be more filled than what has been experienced at Covenant Field. So I think it is safe to say that our expectations for reserve recoveries if we are successful are going to be quite a bit higher than what has been experienced so far at Covenant.

Sir, there appear to be no further questions.

Very good. Thank you all for attending today.

Thank you. A replay of this call will be available to dial into beginning today at 2 PM Eastern time and ending on March 14. The toll-free number is 877-519-4471. The local number is 973-341-3080 and European number will be 7092560. This does conclude today's Delta Petroleum six-month transition period earnings conference call. You may now disconnect and have a wonderful day.