Delta Petroleum Corporation, Q1 2008 Earnings Call Transcript

| About: Par Petroleum (PARR)

Delta Petroleum Corporation (DPTR) Q1 2008 Earnings Call May 8, 2008 12:00 PM ET

Executives

Broc Richardson – Vice President of Corporate Development & Investor Relations.

Roger A. Parker – Chairman & Chief Executive Officer

John Wallace – President & Chief Operating Officer

Kevin K. Nanke – Treasurer & Chief Financial Officer

Carl Lakey – Senior Vice President of Operations

Analysts

Larry Busnardo – Tristone Capital Inc.

John Freeman – Raymond James

Michael Bodino – Coker & Palmer, Inc.

Robert Lynn – Simmons & Company

Greg Brody – JP Morgan Chase

Ron Sanchez – Spencer Edwards

Operator

Good day and welcome to the Delta Petroleum first quarter earnings call. (Operator Instructions) With that in mind I will turn the conference over to Broc Richardson. Mr. Richardson the floor is yours sir.

Brock Richardson

Thank you, 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 harbors created thereby.

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 only gas companies and 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 SEC’s guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in Delta’s form 10K for fiscal year end December 31, 2007 as updated by subsequent periodic and current reports on forms 10Q and 8K 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.

Roger Parker

Thank you Broc. Good morning and thank you for joining us to 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 period of time as well. And the company is now estimated to have an 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 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 currently – 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 non-recurring events going forward. We had abnormally high snow at our Piceance Basin properties which caused numerous cost increases. And we also had a high non-recurring charge for our non-operated interest in the Santa Barbara channel.

On the positive side, DDNA decreased by $1, $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 non-cash and – non-cash in the form of unrealized mark-to-market derivative instrument losses which were $14.1 million and $3.9 million in non-cash equity compensation. We also had $2.3 million of carry-over dry hole 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 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 28th, 2008 and is entirely related to unannounced downtime at the Cobran Valley [ph] gas system processing facility which occurred in late March. Had there been no downtime at that processing facility the increased guidance numbers would’ve 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 that we reference as actual production for the quarter.

Moving to the property discussion I will begin with the Piceance Basin and remind everyone that we have been 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 the 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 wellbores drilled on 10 acre patterns.

Geologically we are very similar or 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 equivalent 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 wherein we did not own 100% of the working interest in the wells that we have 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 in those properties so 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 takeaway 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 are 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 from multiple laterals by pipeline startup at 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 #7 is being moved up to the Columbia River Basin as we speak. The well is expected to be spud prior to the – prior to months end and will likely take 120 to 150 days to drill to total depth.

Going to the Utah Hingeline Project we are 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 that in that well we did encounter Mississippian oil in the Twin Creek limestone that we have 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 refer – we referenced 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 online over the next 10 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 additionally 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 in 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 effect full year production guidance numbers which we still expect to achieve.

With that I will go ahead and turn the call over to questions and answers.

Question-and-Answer Session

Operator

Yes sir. (Operator Instructions) And our first question comes from Larry Busnardo of Tristone Capital.

Larry Busnardo – Tristone Capital

Good morning Roger.

Roger Parker

Good morning Larry.

Larry Busnardo – Tristone Capital

First on the Greentown 28-11 well, is that being constrained at all because I think you initially talked about the well being able to flow at a higher rate and the 200 barrels and the 600 million – or 600 Mcf a day seems a little bit lighter than what you had initially talked about.

Roger Parker

It is, Larry, it is not being constrained at all. It is limited to production from the “O” and the “P” zone. The Cane Creek interval is not currently contributing at this point in time. Part of the process that we are continuing to go through is gather 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 do not have another rig to be able to put over it at this point in time. Ultimately it will likely be drilled horizontally in both the Cane Creek and the “O”.

Larry Busnardo – Tristone Capital

Is that well being flared right now?

Roger Parker

Yes.

Larry Busnardo – Tristone Capital

Okay. Are there any flaring constraints?

Roger Parker

No go ahead, Carl, go ahead.

Carl Lakey

There is a constraint at 50 million cubic feet. Total production however, we’ve been able to work with regulatory bodies to allow some 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.

Larry Busnardo – Tristone Capital

Okay. And then just a second one. In terms of the duly completed wells, what’s the comparison on the EURs and the cost of these duly completed horizontal wells versus the initial vertical wells? I think you were initially talking six Bs and 3.5 million a day on those. Can you just give us a comparison between the two?

John Wallace

Larry, this is John. It’s a good question and as far as on the completed well cost we’re expecting that the horizontal legs to the general cost of those legs will equate to an artificial stimulation or a frag. So there will be additional cost but it will only add about 700,000 to $1 million for two laterals in both the Cane Creek and the “O” zone which we’re expecting to be several thousand feet in length.

As far as the reserves right now what we need to do is get some of these formations online and before we can really alter our reserve projections. So right now I think our initial reserve projections of six Bcfe we feel pretty comfortable with.

Larry Busnardo – Tristone Capital

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

John Wallace

For both horizontals.

Larry Busnardo – Tristone Capital

Okay, great. I’ll just back in. Thanks.

Roger Parker

Thanks Larry.

Operator

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

John Freeman – Raymond James

Hi guys.

Roger Parker

Morning John.

John Freeman – Raymond James

First question I had, it looks like just looking at your most recent presentation that you increased your acreage position in Greentown by I guess almost 20% via I guess you only have 6,000 acre farman [ph]. Can you just elaborate on that?

John Wallace

Yes, that’s a farman we have from a third party. It requires two more wells to fully earn the acreage via the agreement. We plan to drill the second – we’ve drilled one well, we plan to drill the second well here this summer and the third well later this fall. It’s high up on the anticline. We think its very perspective acreage and its lands that sit generally between the first two original wells.

John Freeman – Raymond James

Okay. Moving over to the Piceance – I’m just trying to get an update kind of on where you all stand from kind of what you all’s initial kind of goal was in terms of cost per well. I think your original goal was like 1.8 million and I think you all were internally modeling like 15 days to drill. Just kind of what the latest kind of trends have been there.

Roger Parker

We’ll let Carl Lakey take that one.

Carl Lakey

Yes. In the first quarter our actuals came in at 2.15 using some field estimates for cost and haven't fully hit the accounting system yet. We feel confident in those numbers. Second quarter we're averaging around two million, still with the intent and the belief that we can get our costs down towards that 1.8 number.

John Freeman – Raymond James

Okay and I'm sorry, on the two million how many days was it taking to drill?

Carl Lakey

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

Roger Parker

John, it's worth point out that our current drilling as we move north from the Vega area is in that portion of our acreage position where we're having 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 cost for the development.

John Freeman – Raymond James

Okay, yeah, because 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 mean, I know the IP rates have been going up at a decent clip.

Roger Parker

Yeah.

John Wallace

Well basically, go ahead.

Roger Parker

Go ahead, John. Go ahead.

John Wallace

The basics on 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 pro, on a pro-well basis 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.

John Freeman – Raymond James

Okay, and then last question I have and then I'll drop off. On Cocklebur Draw, maybe if you could just elaborate, you kind of just mentioned that there's going to be big differences in what you're doing in Greentown versus Cocklebur Draw at least in what your kind of interval that you're going after.

John Wallace

Cocklebur --

Roger Parker

Yeah. Sorry, go ahead, John.

John Wallace

The Cocklebur Draw prospect is more analogous to the Hamilton Creek production than EnCana has in the gothic shale, versus the Greentown is a little bit deeper and it's a paradox formation within the paradox salt sequence.

John Freeman – Raymond James

Okay, thanks guys.

Roger Parker

Thanks, John.

Operator

The next question that we have comes from Robert Lynn [ph] with Simmons and Company.

Roger Parker

Robert?

Operator

Mr. Lynn?

Robert Lynn – Simmons and Company

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

Carl Lakey

We have a pretty good understanding based upon Corinell System SMI logging and imaging that all these reservoirs, all these clastics are fractured. One of the reasons that we've done, what took so long if you get to the horizontal drilling is we needed to understand the fracture azimuth and we needed to understand which is the best way to orient these horizontal wells.

If you look at other resource plains whether it be the Baken, the Barnett, even the Austin Chalk, they do work vertically but they work much better horizontally. And given the idea we're on a large structure, fracturing is both structural and because these are clastics confined to salt there will be expulsion fractures for in the shales where the hydrocarbons were expulled from the shales.

So we're expecting fairly intense fracturing. We think that they are vertically-oriented fracture planes. If you look at the Cane Creek field to the south, while the discovery well is over a 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 upon our experience that we've garnered in the Austin Chalk plane. And basically in a plane like this every 100 feet that is drilled horizontally potentially adds additional reservoir and would increase reserves accordingly.

So if you look at the resource planes, a lot of them 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.

Robert Lynn – Simmons and Company

I see. And just to be clear, the horizontal legs are going to be in the place—are you still planning on stimulating this or does this replace a vertical stimulation? And are you –

Carl Lakey

It'll be a vertical stimulation. What we were trying to overcome was vertical wells and artificial or fracs, was being able to frac into a fracture network. We believe that you can still do that and we did prove that by virtue of some of our completions especially in the O interval.

But we were not able to frac into a sufficient—into a large enough area that would equate to a, say a 2,000-foot horizontal well bore. We believe that ultimately we may drain as much as 80 acres with the 2,000-foot well bore and additional cost for the horizontal leg far outweighs the additional cost of a second well within that 80 acre unit that would be required under a vertical program.

Robert Lynn – Simmons and Company

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

Carl Lakey

No, if you look at the Cane Creek field those are all, to the best of my knowledge, those are not stimulated and we believe that the vertical fracturing network is extensive. We believe that it's open full of hydrocarbons as evidenced by all the shows that we encounter while drilling through all these formations.

And so at this time we're not planning to artificially stimulate the wells. As we garner more information going forward, if we think that we can increase the productivity by fracturing these wells we sure have the experience and the capability of doing so.

Robert Lynn – Simmons and Company

Right, and do you plan on running casing in the lateral length or will these be open hole? Can you open hole complete these wells?

Roger Parker

Carl, one second, they're just going to be a—we're going to run a pre-drill in the liner in the hole.

Carl Lakey

It'll be perforated.

Robert Lynn – Simmons and Company

Okay.

Roger Parker

Correct.

Robert Lynn – Simmons and Company

Yeah, and then just one final question, this is obviously a pretty complex area. I mean, do you anticipate any initial problems with horizontals here?

Carl Lakey

So far, you know, all the experience we have obtained in Austin Chalk plane where the vertical depth is approximately 14,000 feet and with a 6,000 foot lateral we're actually drilling 20,000 foot wells. The target zone is much thicker here in the Cane Creek and in excess of 100 feet in the Cane Creek.

And in excess of 85 feet in the O zone relative to a 30-foot zone in Austin Chalk. The pressures are similar. The temperatures are greater in the Austin Chalk and so we believe and we have experienced today 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 well bores. 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

Robert Lynn – Simmons and Company

Okay, and just one final question. What is—why are you running three rigs to drill three horizontals at the same time? What is the thought process behind that?

Roger Parker

Well, 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 well bores drilled to total depth, so we moved the third rig in and so that we could get as much information as possible in a short period of time. The 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.

Robert Lynn – Simmons and Company

Okay, thanks. That's all I had.

Roger Parker

You bet. Thank you.

Operator

And the next question we have comes from Michael Bodino with Coker and Palmer

Michael Bodino – Coker and Palmer

Good morning guys.

Roger Parker

Good morning, Michael.

Michael Bodino – Coker and Palmer

Not to beat a dead horse here, but just want to ask a couple follow-ups on Greentown. 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 little production history now and we're still talking 6 bcf. Is that zone-specific to these two zones you're drilling horizontally or is that all the zones behind pipe?

Roger Parker

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

Michael Bodino – Coker and Palmer

And what are your plans ultimately with those zones? I mean, clearly you've tested hydrocarbons in a lot of those zones.

Roger Parker

There's –

Carl Lakey

Michael, we expect that once the pipeline's in and maybe some time next year that there very easily could be a second drilling program in this area focusing on the shallower intervals. What we don't know at this time is would that also be horizontal at specific intervals or would that be vertical completions.

But I can envision a program that's roughly 5,000 feet to 8,500 feet and then the main development in the O and the Cane Creek with drilling horizontal legs in reservoirs that are roughly 8,000 to 9,000 feet to 9,000 to 9,500 feet.

Michael Bodino – Coker and Palmer

Would, 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 is there X amount of reserves that you should be able to produce? Or is it too early to come up with a number like that?

Carl Lakey

Well, it's too early in this particular area but in the Cane Creek field, you know, roughly reserve expectations are roughly half a million barrels or 500,000 barrels in the average horizontal length of those short radius laterals was approximately 600 feet.

Michael Bodino – Coker and Palmer

Okay, moving to another area, I mean, 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 that's impacting your 120 to 150 a day drilling program or is that just padded for that?

Carl Lakey

Well, that does add, you know, that is what we think is a conservative estimate. But based upon drilling in the last several years, you know, 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.

So 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 that 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 and in hitting our prognosis, would be one of the only wells in the basin to drill through the Roslyn Formation.

So we're projecting a Roslyn Formation of about 4,400, 4,500 feet in thickness and we're projecting this well to go through the Roslyn Formation into some of the lower intervals which also have significant shows in the active 133 well.

Michael Bodino – Coker and Palmer

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

Roger Parker

Thanks, Michael.

Operator

The next question comes from Greg Brody with JP Morgan.

Greg Brody – JP Morgan

Hey guys.

Roger Parker

Morning, Greg.

Greg Brody – JP Morgan

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

Roger Parker

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

Greg Brody – JP Morgan

Okay, and then just in terms of the thought process behind selling it, the potential sale of these assets. Could you provide a little bit more color around that?

Roger Parker

Yeah, we're, 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 there. There are other areas like the Paradox Basin and also to have our human resources working those areas more diligently as well.

Greg Brody – JP Morgan

Okay, and the shift in the CapEx. I was trying to get a sense of what your CapEx was for the quarter. I'm kind of backing into what your berm was, but you actually haven't—do you have an actual number?

Roger Parker

Yeah, the drilling CapEx for the quarter was approximately $86 million which is in line for what we had issued for the year.

Greg Brody – JP Morgan

Let me just look at mine. No, no, in terms of liquidity targets on your last call you talked about how Tracinda was focused on making sure you had a 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 is that changed a little bit?

Roger Parker

Well we, no, that has not changed. I think the one thing that I would say 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 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, are obviously experiencing pretty significant increase in cash flows as well.

Greg Brody – JP Morgan

That's helpful, then just a detailed question on the Piceance gas processing facility?

Roger Parker

Yes.

Greg Brody – JP Morgan

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

Roger Parker

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

Carl Lakey

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.

Greg Brody – JP Morgan

Who was the operator with that?

Roger Parker

The operator is DCP Midstream.

Greg Brody – JP Morgan

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

Roger Parker

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

Ron Sanchez – Spencer Edwards

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

Roger Parker

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 certainly experienced the significant shows that you expect from the better wells while 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 cost of the well, we still expect the well to be very economic individually. I think that answers your questions, doesn't it?

Ron Sanchez – Spencer Edwards

Okay, well, just in general, what was your—why are you trying to sell this field or this decision or what's your reasoning for pulling out of this area?

Roger Parker

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.

Ron Sanchez – Spencer Edwards

Okay, thank you sir.

Roger Parker

Thank you.

Operator

And the next question we have comes from Michael Bodino with Coker and Palmer.

Michael Bodino – Coker and Palmer

Hey Roger, just a couple of follow-ups. Relative to the Utah overthrust, I know that the Parowan well you lost some pay in the Twin Creeks limestone. Industry rumor suggests that in the covenant fill there's some production from the Twin Creeks.

Do you have any insight to what the Twin Creeks can produce? I understand it's fracture launched and reservoired so it may vary, but is there anything you can provide on that?

Roger Parker

Well, that—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 in that particular area as well. So, John, do you have any additional comments in that regard?

John Wallace

Roger, you're right. To expand upon that the Wyoming overthrust belt which is upwards of ultimately a two billion barrel provenance, approximately 25 to 33% of the production was derived from the Navajo Formation so it is a meaningful –

Roger Parker

The Twin Creek Formation.

John Wallace

Excuse me, the Twin Creek. It is a fracture reservoir and you really can't give and I sense for pro-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.

Michael Bodino – Coker and Palmer

Okay.

John Wallace

We have heard the similar rumors about the Twin Creek potentially being a contribution in the Central Utah Hingeline area.

Michael Bodino – Coker and Palmer

And, you know, given the recent discovery of the Providence Field and now there's a couple different field discoveries in that Utah overthrust, has there been any additional work on getting through the size and make arrow macro data that you have? Is there anything that you can elaborate on relative to high grading prospects or?

John Wallace

You know, no, I would say though it is really important is the Parowan feature was one of our southernmost structures and we did evidence the Mississippi oil that tells us that a large percentage if not all o four prospects could be in the fairway of worldwide 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 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 structure 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.

Michael Bodino – Coker and Palmer

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

Roger Parker

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

Michael Bodino – Coker and Palmer

All right, thank you.

Operator

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

Roger Parker

Okay, very good. Well, thank you for joining us for our first quarter conference call and we'll look forward to the next one. Thank you.

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