Par Pacific Holdings Inc (PARR) 2008 Q1 法說會逐字稿

Good day and welcome to the Delta Petroleum first quarter earnings call. For your information, all participants will be in a listen-only mode. There will be an opportunity for you to ask questions at the end of today's presentation. (OPERATOR INSTRUCTIONS) This conference is being recorded.

With that in mind, I will turn the conference over to Mr. Broc Richardson.

Good morning. This is Broc Richardson, Vice President of Corporate Development and Investor Relations. Before we begin, I need to read the forward-looking statement disclosure. This conference call will include projections and other forward-looking statements within the meaning of the Federal Securities Laws and are intended to be covered by the Safe Harbor's creditor buy. In that regard you are referred to the cautionary statement displayed on Delta's website which is incorporated by reference to the information provided on this call. Further, the Securities and Exchange Commission permits oil and gas companies in their filings with the SEC to disclose only proved reserves that the Company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.

Delta may use certain terms in this conference call that the SECs guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in Delta's Form 10-K for fiscal year end December 31, 2007, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively. On the conference call today from Delta are Roger Parker, the Chairman and Chief Executive Officer; John Wallace, President and Chief Operating Officer; Kevin Nanke, Treasurer and Chief Financial Officer as well as Carl Lakey, Senior Vice President of Operations. With that, I'll turn the conference call over to Roger Parker.

Thank you, Broc. Good morning and thank you for joining to us discuss our first quarter results. I'll open today by saying that the Company is now experiencing the benefits of significant preparation and implementation at all levels and it is being realized in the most important areas which are reserve growth, production growth and cash flow growth.

Internally estimated proved reserves have grown by 60% over year end 2007 levels in the first quarter alone. Much of the growth was related to our previously announced Piceance Basin acquisition but as you can see, organic growth has been very meaningful in a short and the company is estimated to have in excess of 600 bcf equivalent in proved reserves. Additionally, production growth is occurring consistently and at expected levels that will allow for the substantial growth we have projected for 2008. Production from continuing operations was up 68% over prior year levels and the second quarter is projected to be up 8 to 12% sequentially and over 40% higher than the prior year period. So it is very apparent that production growing -- production is growing at the significant rates necessary to achieve the high standards that we set at the beginning of the year.

We are also realizing substantial increases in cash flow. Discretionary cash flow, which is a non-GAAP measure was up 87% year over year to $31.3 million for the quarter. This is a function of higher commodity prices and production increases and is expected to continue to grow accordingly as we go through the year. This will further allow for plenty of available liquidity as we move forward. In an effort to assist in determination of our current liquidity position, we have added a paragraph to this press release describing what is essentially our cash and liquidity position at the end of the quarter and after the other significant events transacted during the quarter, which include, of course, the Tracinda Corporation equity transaction and the subsequent Piceance Basin transaction with EnCana.

Lease operating expense for the quarter was up on a per-unit basis almost $0.20 per Mcfe, which is not good but it is related to what are essentially nonrecurring events going forward. We had abnormally high snow at our Piceance basin properties, which caused numerous cost increases, and we also had a high nonrecurring charge for our nonoperated interest in the Santa Barbara channel.

On the positive side, DD&A. degreased by $1.46 per mcfe on a year-over-year comparison to $4.03 per mcfe which was a result of greater reserve additions and lower well costs primarily in the Piceance basin. We reported a loss of approximately $21 million, most of which was in the form of noncash in the form of unrealized mark to market derivative instrument losses which were $14.1 million and $3.9 million in noncash equity compensation. We also had $2.3 million of carry over dry hull costs for our Utah overthrust well, which was begun in late 2007 but did not reach total depth until January.

With regard to production for the quarter, we are reporting 5.37 bcf equivalent, which is within the range of orange originally issued guidance but below increased guidance issued on February 28, 2008. Actual production was 5.56 bcf equivalent. The reason we refer to that number is for better comparative information on a go forward basis. The 5.37 bcf number was slightly below the increased guidance that was issued on February 28, 2008, and is entirely related to unannounced downtime at the Coburn Valley gas system processing facility which occurred in late march. Had there been no down time at that processing facility, the increased guidance numbers would have been achieved as well.

For the second quarter, we are projecting production of 6.0 to 6.2 bcf equivalent which is an 8 to 12% growth rate over the 5.56 bcf equivalent number we referenced as actual production for the quarter.

Moving to the property discussion, I will begin with the Piceance basin and remind everyone that we will be drilling on 20 acre spacing patterns and booking reserve increases primarily based on that spacing as well. I think it is important to point out that many of the other operators in the basin have been drilling and booking reserves on a 10 acre spacing pattern. Recently we have heard many comments that they are not experiencing reserve communication between Well bores drilled on 10 acre patterns. Geologically we are very similar or the same. We're the same so we will begin to focus our efforts on 10 acre pilot drilling to substantiate that our properties are in fact subject to the same results. This definitely allows for the idea that our Piceance properties hold well in excess of 2 trillion cubic feet of reserve potential with a corresponding opportunity to experience substantial annual reserve growth through our increased drilling activities.

I'll also go ahead and address a couple of comments that we saw this morning related to production growth at the Piceance basin. The number that we have in there today is 44 million cubic feet equivalent, which is a net number for the Piceance basin. The gross number related to that interest is approximately 55 million cubic feet a day net and the Company is not currently constrained in any way by production growth and will not be until we enter into the third and fourth quarter of this year. The numbers that we had reported previously were evidencing growth in gross daily rate and was related to the previous agreement that we had in place with EnCana Corporation where in we did not own 100% of the working interest in the wells that we had been drilling on the lands that we had ownership in by virtue of our agreement with EnCana.

At this time, we now have 95 to 100% working interest on those properties. On a go forward basis we will be reporting numbers from that area on a net basis as opposed to a gross growth rate. If you look at our investor materials on our website, you will see that the predicted production growth from the Vega area is essentially in line with what's been on the website for a number of months and we do not expect to be pipeline constrained until we get into the third and fourth quarter. Referencing that, I will also tell you that the additional pipeline project, which is in place and will significantly increase take away capacity from this area remains on schedule and is expected to be in operation by the end of 2008.

Moving on to the Paradox Basin, we have spent significant time and effort testing wells in preparation for our pipeline operation which is still scheduled to begin at the end of the second quarter. Much information has been gathered that offers continued excitement and also suggests that drilling horizontal laterals may be the most effective method to maximize daily rate and reserve recovery. We're currently drilling horizontal laterals in three wells and each is building curve or drilling in the Cane Creek formation. We expect to be drilling multiple laterals in each wellbore with the intention of having laterals producing from both the Cane Creek formation and the O interval in a single wellbore. Recently we have been producing the Federal 28-11 well as a vertical well at rates of approximately 200 barrels of oil per day and 600,000 cubic feet of gas per day, but we are reasonably certain that those numbers will be much enhanced with horizontal laterals as well. As of now, we expect to have the three drilling wells productive for multiple laterals by pipeline start up by quarter end.

Moving on to the Columbia River Basin. We have made a significant decision to move forward with the drilling of the Gray 31-23 well on our Bronco prospect with or without industry partners. We believe the potential for both the well and the prospect area warrants drilling with 100% working interest if that's where we end up. This is a multi-tcf potential prospect as identified by geophysical interpretation that shows the existence or appears to show the existence of a very large geologic feature. As we have previously stated, we have been in the midst of many discussions and negotiations with potential industry partners, and have reviewed proposals or offers that we have elected not to go forward with at this point. We are continuing discussions and may end up with a partner, but if terms are not agreeable and in our estimation most beneficial to the shareholders of Delta Petroleum Corporation, we may elect to maintain our 100% working interest. DHS rig number 7 is being moved up to the Columbia River Basin as we speak. The well is expected to be spud prior to month's end and will likely take 120 to 150 days to drill to total depth.

Going to the Utah Hingeline project. We're currently in the midst of the permit application process for another well to be drilled in our Beaver prospect area. This area is essentially midway between the producing covenant field to the north and the Parowan prospect well that we drilled late last year to the south. Important to remind everyone in that well we did encounter Mississippian oil in the Twin Creek limestone that we've not been able to test as yet but importantly the source for production in this play has moved through the area both to the North and to the South. We anticipate that we should be able to be approved for drilling another well in the overthrust sometime in the third quarter.

With regard to the Midway Loop area in South Texas, we reference in the press release today that the wells and acreage are held for sale. Having said that, we are going to be drilling an additional well, the Carter a-141 after we put the Baxter well on line over the next ten days. And at some point during the course of 2008, we will divest of that property ownership.

In the Howard Ranch area, we see many additional geologic opportunities but are of the opinion that the best thing to do at this point is to wait for surface discharge permits for water production before we resume additional drilling activity. With that, I will summarize and wrap up before we open the call to questions and discussion at this stage of the game, the Company has experienced significant proved reserve growth and production growth. Production growth in spite of the 5.37 bcf number reported this quarter. 5.37 by the way is a very slight miss and does not affect full year production numbers which we still expect to achieve. With that, I'll go ahead and turn the call over to questions and answers.

Yes, sir. (OPERATOR INSTRUCTIONS) Our first question comes from Larry Busnardo of Tristone Capital.

Good morning, Larry.

First on the Green Town 2811 well, is that being constrained at all? Because I think you initially talked about the well being able to flow at a higher rate. The 600 mcf a day seems a little bit lighter than what you had initially talked about.

It is -- Larry it is not being constrained at all. It is limited to production from the 0 and the P zone. The Cane Creek interval is not currently contributing at this point in time. Part of the process that we're continuing to go through is gathering information both production and pressure from individual intervals which is what we're doing at this point. That well is being produced vertically primarily because we don't have another rig to be able to put over at this point in time. Ultimately it will likely be drilled horizontally in both the Cane Creek and the O.

Is that well being flared right now?

Yes.

Okay. Are there any flaring constraints?

Carl, go ahead.

There is a constraint at 50 million cubic feet. Total production, however, we've been able to work with the regulatory bodies to allow in leniency to that. That constraint could still reappear, but at least at this point we've been able to work with the bodies to allow us to continue to test the well.

Okay. And then just a second one. What -- in terms of the duly completed wells, what's the comparison on the cost of these duly completed wells versus the initial vertical wells? I shi you were initially talking six B.s. Can you give us a comparison on the two?

Larry, this is John. It's a good question and as far as the completed well costs, we're expecting that the horizontal legs to the general cost of those legs will equate to an artificial stimulation or Fra. So there will be additional cost but it will only add about 700,000 to $1 million to two laterals in both the Cane Creek and the ozone which we're expected to be several thousand feet in length. As far as the reserves right now, what we need to do is get several of these formations online before we can really alter our reserve projections. Right now, I think our initial reserve projections of 6 bcfe we feel comfortable with.

And that 700,000 to a 1 million, was that for both horizontals?

For both horizontals.

I'll jump back in. Thanks.

Thanks, Larry.

And the next question we have comes from John Freeman of Raymond James.

Hi, John.

It looks like just looking at your most recent presentation that you increased your acreage position at Green Town by I guess almost 20% via I guess nearly a 6,000 acre farm in. Can you just elaborate on that?

Yes. That's a farming we have from a third party. Requires two more wells to fully earn the acreage via the agreement we plan to drill the second well here this summer and the third well later this fall. It's high up on the the anticline, we think it's very prospective acreage and its lands that sit generally between the first two original wells.

Moving over to the Piceance, I'm just trying to get an update on where you all stand from what you all initial goal was in terms of costs per well. I think your original goal was 1.8 million. I think you are internally modeling 15 days to drill, what the latest trends have been there.

We'll let Carl Lakey take that one.

In the fist quarter, our actuals came in 2.15 using field estimates or costs that haven't fully hit the system yet. We feel confident in those numbers. Second quarter we're averaging around 2 million. Still with the intent and the belief that we can get our costs down towards that 1.8 number.

I'm sorry, on the 2 million, how many days was it taking the drill?

We're averaging 13.3 or 13.4 in the second quarter.

It's worth pointing out that our current drilling as we move north from the Vega area is in that portion of our acreage position where we happen to put in road infrastructure, pipeline infrastructure for the first time. So the initial wells will be a little higher than later development wells as we put in the infrastructure costs for further development.

Yes. It does look like you're beating your expectations at least on days to drill. What is the kind of current EUR assumptions in the Piceance. I know the IP rates have been going up at decent clip.

Go ahead, John. Go ahead.

Based upon the EUR map that we have in our presentation materials as we move north, the pay column gets considerably thicker and we expect the EUR reserves to increase similarly. That is in the Vega area we'll move from the 1.2 Bcf per well contour north of 1.5 Bcf as we move north into the north Vega and especially into the Buzzard Creek unit itself.

Okay. Last question and I'll drop off. On Cockamoor draw, you mentioned there's going to big differences in terms of what you're doing in Greentown for Cockamoor draw in least of what your intervals you're going after.

Sorry, go ahead, John.

The Cockamoor draw prospect is more analogous to the Hamilton Creek production that Encana has in the Gothic shale. Versus the Greentown is a little bit deeper and is the Paradox within the Paradox salt sequence.

Okay. Thanks, guys.

Thanks, John.

The next question we have comes from [Robert Glen] with Simmons & Company.

Robert?

Mr. Len?

Sorry, I was on mute. Hopping over to Greentown, just curious as to what you learn from the verticals? How sure are you that this is a naturally fractured reservoir?

We're very -- we have a good understanding based upon core analysis and FMI logging and imaging that all these reservoirs are fractured. One of the reasons that took so long to get to the horizontal drilling is we needed to understand the fracture azimuth and need to understand which is the best way to orient these horizontal wells. If you look at other resource plays whether it be the Bakken the Barnett even the Austin Chalk, they do work vertically but work much better horizontally. Given the idea we're on a large structure, fracturing is both structural and because these are plastics confined to salts, this will be expulsion fractures in the shales where the Hydrocarbons were expelled from the shales. We think that they are vertically fracture planes. If you look to the Cane Creek well to the south while the discovery well was over 1 million barrels from a vertical well, most of the economic drilling was from short radius horizontal wells that averaged approximately 600 feet in length. We're planning to drill several thousand feet based opinion our experience that we've garnered in the Austin Chalk play and basically in a play like this every hundred feet that is drilled horizontally potentially adds additional reservoir and would increase reserves accordingly. So if you look at the resource plays, a lot of them have been increased in their productivity and their economics by horizontal drilling. We just needed to understand better what the fracture orientation was before we begin orienting our horizontal wells.

And just to be clear, the horizontal legs are going to be -- are you still planning on stimulating this or does this replace a vertical stimulation?

Vertical stimulation. What we were trying to overcome with vertical wells and artificial or fracs was being able to frac into a fracture network. We believe you still can do that and we did prove that by virtue of some of our completions especially in the o interval. We were not able to frac into a large enough area that would equate to a 2,000 foot horizontal wellbore. We believe that ultimately we may drain as much as 80 acres with the 2,000 foot horizontal wellbore and additional cost for the horizontal leg far outweigh the additional costs of a second well within that 80 acre unit that would be required under a vertical program.

And you're not going to stimulate the horizontal leg?

No. If you look at the Cane Creek field, those are all, to the best of my knowledge those are not stimulated. We believe that the vertical fracturing network is evidenced by all of the shows that we encountered by drilling through all these formations. So at this time, we're not planning to artificially stimulate the wells. As we garner more information going forward, if we think we can increase the productivity by fracturing these wells, we sure have the experience and the capability of doing so.

Right. Do you plan on running casing in the lateral link or will these be open? Can you open a whole complete these wells?

We're going to run a predrilled liner in the hole.

Per perforated.

Yes, and just one final question. This is obviously a pretty complex area. Do you anticipate any initial problems with horizontals here?

So far, we've had, you know, all the experience that we have obtained in Austin Chalk play where the vertical debt is approximately 14,000 feet and with a 6,000 feet lateral drilling 20,000 for the wells. The target zone is much thicker here in the Cane Creek in excess of 100 feet in the Cane Creek in excess of 85 feet in the ozone relative to a 30 foot zone in the Austin chalk. The pressures are similar. The temperatures are greater in the Austin Chalk so we believe and we have experienced to date relative I don't want to say ease but we have had procedurally drilling horizontally in the Cane Creek formation has gone relatively smoothly so far. So we're expecting to be able to drill several thousand feet in these horizontal wellbores. The one factor that we need to understand in designing our wells is what faulting might do in a particular interval but right now we're not seeing a lot of faulting.

Just one final question. Why are you running three rigs to drill three horizontals at the same time? What is the thought process behind that?

The primary reason, Robert, was to get results sooner than later. We had a rig, DHS rig that was being moved from Texas up to the Rocky Mountains which became available and we already had vertical wellbores drilled to depth. We moved a third rig in so we could get as much information as possible in a short period of time. Decision to go forward with three rigs or more rigs will be made after the pipeline becomes operational and we have the results from this activity.

Thanks. That's all I had.

You bet. Thank you.

The next question we have comes from Michael Bodino with Coker & Palmer.

Hey, Michael.

Not to beat a dead horse here. Just want to ask a couple more follow-ups on Green Town. I know things have changed relative to the initial plans on drilling from where we were last year going now horizontal. Relative to the reserves, you've got a low production history now. We're still talking Bcf. Is that zone specific to these two zones you're drilling horizontally or is that all the zones behind pipe?

The 6 Bcf numbers that we've been talking about previously and continue to talk about now are essentially for the intervals from the O interval down to the bottom of the wellbores. So it does not have any reference to the other plastics that continue to remain behind pipe above the O.

What are your plans ultimately with those zones? Clearly you've tested hydrocarbons in a lot of those zones?

Michael, we expect that once the pipeline's in and maybe sometime next year that there very easily could be a second drill in this area focusing on the shallower intervals. What we don't know is would that also be horizontal or vertical completions? I can envision a program that's roughly 5,000 feet to 8,500 feet, and then the main development program in the O and the Cane Creek drilling horizontal legs in reservoirs that are roughly 8,000 to 9,000 feet to 9,000 to 9500 feet.

When you think about that, is there a good rule of thumb that we can think about relative to horizontal wells for each leg that is certain horizontal length or x-amount of reserves you should build and produce? Is it too early to come up with a number like that?

It's too early in this particular area but in the Cane Creek field, roughly reserve expectations are roughly 0.5 million or 500,000 and the average horizontal length of the short radius laterals was approximately 600 feet.

Okay. Moving to another area. Relative to the gray well that you're getting ready to drill, could you walk us through a little bit and remind us how thick you think the Basalt is in that area and relative to that, obviously it's impacting your 120 to 150 day drilling program or is that just padded for that?

That is what we think is a conservative estimate. Based upon drilling the last several years that's going to require execution on a drilling procedure that was, I don't want to say perfected but was used by Shell in the early '80s. We have drilling charts from those initial wells and we feel like that we understand what some of the drilling challenges are and how to overcome those. Having said that, I think the amount of days to drill is a pretty good estimate. I think that the cost and the timing that we feel pretty comfortable with. As far as the depth, we're projecting to come out of the basalt around 8,000 feet, and it's a 15,000 foot well, which will be one of the only wells if we're successful in hitting our prognosis would be one of the only wells through the Rosslyn formation. So we're projecting a Rosslyn formation of about 4500 feet in thickness and we're projecting this well to go through the Rosslyn formation into some of the lower intervals which also had significant shows in the Yakima 133 well.

Perfect. I'll get back in the queue, thanks.

Thanks, Michael.

The next question we have comes from Greg Brody with JPMorgan.

Hey, guys.

Good morning, Greg.

I'm just trying to get a sense of the size of the Midway Loop acreage. I was looking through 10-K and you have 21,400 as of year end and then your proved reserves were 24bs. Any change in that as a result of your modified reserve number?

Not significant reserve number changes. We have essentially been drilling proved undeveloped locations. And that we have not expanded on the acreage position there.

Thought process behind potential sell of these assets, can you provide a little more color around that?

I mean, the bottom line answer is that we're running out of additional potential here that would have a meaningful impact on the Company going forward. We think we're better suited to spend CapEx in other areas like the Paradox Basin and also to have our human resources working those areas more diligently as well.

Shifting to CapEx I was trying to get a sense of what your CapEx was for the quarter, backing into what your burn was. Do you have an actual number?

Yes. The drilling CapEx for the quarter was approximately $86 million which is in line for what we issued for the year.

In terms of liquidity targets, on your last call you talked about Tracinda was focused on making a sure you had couple hundred million dollars of liquidity given the credit environment that we were in. I would say that that's improved a fair amount especially for energy investors. Is that still a target you have in mind or has that changed a little bit?

Well, we -- no, that has not changed. I think the one thing that has changed is where the liquidity will come from, as of right now we have recently gone through our bank redetermination efforts in mid-April and we expect to have a fairly significant increase in our borrowing base capacity. We have spent a lot of time reviewing the other financing opportunities that do exist out there that would essentially allow us to use the $300 million of cash that we have set aside for the EnCana transaction but when you look at the cost of those types of financing activities versus the cost of our borrowing base credit facility, we think it's most prudent at this point in time to rely on that for available liquidity as we go forward. We also, as mentioned earlier, obviously are experiencing pretty significant increase in cash flows as well.

That's helpful. Just a detailed question on the Piceance gas processing facility.

Yes?

Can you describe what actually happened there and then just do you have any further concerns about that?

Yes. In a general sense, we do not have any concerns going forward. We had significant discussion with the operator of the pipeline system. As you might expect, but I'll turn it over to Carl to let you, or have him identify what occurred in the month of March.

In the month of March, they were doing a plant expansion, and as sometimes is the case during plant expansions, unforeseen events arise from the start up of new equipment that delayed the resumed function of the plant longer than expected. Some of that was electrical, and some of it was reliability with compressors. We believe those have been resolved and shouldn't be a forward issue.

Who was the operator of that?

The operator is DCP Midstream.

That's all I have. Thank you very much.

Thank you.

The next question we have comes from Ron Sanchez with Spencer Edwards.

Hello, gentlemen. I just want to regarding your Austin Chalk in the Midway loop, you announced that you're completing this lateral portion that you redrilled. How -- what are the production numbers on that going to look like and what is your working interest and what did it cost?

Ron, the expectation is that it's going to be a strong well. It's in the immediate area of our better wells that we've drilled down here. We've certainly experienced the significant shows that you expect from the better well drilling down here. The individual well cost has gone up dramatically as you might expect with regard to the requirement to essentially redrill the entire lateral. Having said that, and even with the increased costs of the well, we still expect the well to be very economic individually. I think that answers your question, doesn't it?

Just in general, what was your -- where are you trying to sell this field or this decision? What's your reasoning for pulling out in this area?

The primary reason as mentioned before is that we're essentially out of running room that would have a meaningful impact on the Company on a go forward basis. We're out of leasehold.

Thank you, sir.

Thank you.

The next question we have comes from Michael Bodino with Coker & Palmer.

Roger, just a couple of follow-ups. Relative to the Utah overthrusts, I know that the Parawon well you logged some play and the Twin Creeks limestone, industry rumors suggest that in the Covenant there's production from the Twin Creeks. Do you have any insight to what the Twin Creeks can produce? I understand it's a pressure limestone reservoir so it may vary but is there anything you can provide on that?

Well, we can't with regard to the production from the Covenant field but what we can steer you to is other overthrust fields that produce in the Wyoming Utah overthrust belt that were discovered 25, 30 years ago. There are numerous fields in that overthrust area that do produce meaningful recoverable amounts from the Twin Creek lime above the Navajo and that particular area as well. John, do you have any additional comments in that regard?

Roger, you're right. To expand upon that in the Wyoming overthrust belt which is upwards of ultimately a 2 billion barrel province. 25 to 33% of the production was derived from the Navajo formation. It is a meaningful.

The Twin Creek formation. Excuse me, the Twin Creek. It is a fracture reservoir and you really can't get a sense for proved oil reserves unfortunately because it is fractured and hard to determine the characteristics based on logs. It requires production history. But it was a meaningful contributor in the Wyoming Utah overthrust belt.

Okay.

We have similar rumors about the Twin Creek potentially being a contributor in the central Utah Hingeline area.

And, given the recent discovery of the Providence field up there, now there's a couple different field discoveries and that Utah overthrust, has there been any additional work on the seismic or aeromag data you have, or is there anything you can elaborate on relative to high grading prospects?

No, I would say it is really important since the Parawan features with as one of our southernmost structures and we did evidence Mississippi oil that that tells us that a large percentage if not all of our other prospects could be in the fairway of oil migration and therefore could be potentially hydrocarbon traps. As mentioned before, overthrust fields or overthrust regions take on the appearance of a string of pearls where's they're in an elongated pattern along a leading edge thrust fault. That can be seen in the Canadian overthrust belt and the Utah/Wyoming overthrust belt and now you have a second discovery in the central Utah Hingeline belt that is along that leading edge thrust where all of our structures are also located. It's beginning to have the appearance of the string of pearls. But time will tell to see how many fields are ultimately discovered in the central Utah Hingeline area, but it does give us a lot of confidence and a lot of excitement going forward that at least a large portion of our acreage is in the right area.

And my last question, given the acquisition of the EnCana acreage and some other fill in acreage around Vega plus the agressive drilling program on the Paradox and Piceance basin, any thoughts about providing interim reserve reports during the year?

Michael it's Roger. We referenced quarter end numbers on this press release, and I think it may be reasonable to expect that same thing on a go-forward basis.

All right. Thank you.

Mr. Parker, gentlemen, we're showing no further questions at this time.

Very good. Thank you for joining us for our first quarter conference call and we'll look forward to the next one. Thank you.