Par Pacific Holdings Inc (PARR) 2009 Q2 法說會逐字稿

Hello and welcome to the Delta Petroleum Corporation's 2009 second quarter earnings conference and webcast. All participants will be in listen only mode. There will be an opportunity for you to ask questions at the end of today's presentation. (Operator Instructions). Please note this conference is being recorded.

Now I would like to turn the conference over to Broc Richardson, VP Corporate Development and Investor Relations. Mr. Richardson, please begin.

Thank you and good morning. Before we begin, I would like to remind you that we are conducting this call under Safe Harbor, and that this 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 credited 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 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 SEC's guidelines strictly prohibit us from including in the 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, 2008, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

The speakers from Delta are Dan Taylor, Chairman of the Board; John Wallace, President and Chief Operating Officer; and Kevin Nanke, Treasurer and Chief Financial Officer. With that, I'll turn the conference over to our chairman, Dan Taylor.

Thanks, Broc. Good morning and thank you for joining us on this morning's conference call. By way of introduction, I am an executive of Tracinda Corporation, Delta's largest shareholder. I've been a member of Delta's Board of Directors since February of 2008 when Tracinda initially invested in the company and Chairman since late May.

Since assuming the responsibilities of Chairman, I have worked closely with members of management and the business teams to become much more familiar with the company's assets, employees, and day to day operations, and from that process have experienced two things I'd like to share with you. First is a deepened understanding and confidence in the intrinsic value of the company's assets as well as its exceptional potential, mainly the Columbia River Basin. John will be speaking in greater detail regarding the status and plans of the Gray well in the CRB in his marks momentarily. Second is an appreciation of the high degree of talent and experience that our management team and our operations team possess. We have a team with an innate knowledge of how to operate our assets and to persevere in this commodity price environment and yet create value for our shareholders. The team we have has been in cyclical industry long enough to have weathered similar downturns and their experience has proved invaluable.

This brings me to a similar topic, which is the CEO vacancy. The CEO search has been suspended for the time being. This is due to the strength of the team in place and so the company can focus its efforts on execution and cost control.

I also want to spend a moment on the strategy of Delta going forward. It is a three-pronged strategy that is rather simple. First, the first is to focus on the company's two core assets which are the Piceance Basin and the Columbia River Basin. Second is to realize value through the monetization of noncore assets. And third is to enhance our liquidity and reduce leverage. The common equity offering in May was an important step in achieving this. Liquidity preservation was also a factor in deciding to suspend completion operations in the Piceance Basin as stated in our press release. I truly have full confidence that the operational and management personnel will be able to execute this strategy we have put in place.

I'd like to spent a few moments discussing our leverage position. Since the first quarter, the company has been in regular discussions with the banking group that provides our senior credit facility. The discussions with them have been and continue to be very constructive. We have recently informed them that, barring a substantial improvement in near term natural gas prices, it is highly unlikely that we will be in compliance with our leverage covenant upon the reporting of our fourth quarter of 2009. This is due to two things -- realized gas price in the Rocky Mountains, both currently and projected over the next two quarters, and our decision to suspend our completion activities in the Piceance Basin. While I can't speak for our banking group, based on discussions to date, I'm highly confident that we will reach an agreement with them that removes this overhang without hindering our strategy going forward.

To conclude my remarks, I know we will continue to show cost reduction and sound execution on our strategy. We will position this company to realize its tremendous asset value once the market and industry environment improve. While there is still much work to be done, I am enthusiastic about Delta's future.

Before I turn the call over to John, I know you have many questions regarding our operations in the CRB. Regretfully, I must inform you that under our joint operating agreement with our partner in the Columbia River Basin, we cannot disclose well information other than information that is required to be disclosed under securities laws or information that our partner agrees may be disclosed. While we would love to provide additional information that we have gained since our last conference call regarding our operations in the CRB, we must operate within our agreement with our partner. Once we obtain information that is required to be disclosed, we will share it with you promptly.

I'll now turn the call over to John Wallace, Delta's President and Chief Operating Officer, for his comments on operations.

Thanks, Dan. To begin, I'm pleased to discuss the current operations of our Gray well in the Columbia River Basin. I'll address the current status, then discuss the expected timeline of events.

Before I provide the completion timeline, please allow me to clarify a few things. First, keep in mind that this is our first operated well in the Basin and not our 10th well or our 20th well. Being such requires that we learn as much as possible from each individual zone as we complete them. While we've planned on perforating the zones and then flowing them for specific number of days, if a particular zone performs better or worse than we initially expected, the plans and timing will change accordingly. I need to emphasize this since we need to have latitude and understanding from our shareholders in regards to timing and information acquisition and disclosure as we go into this process.

We are now at total depth and will begin perforating the lowermost zones and working our way up the well bore. The prospective sands have porosities ranging from 12% to 17% with associated permeabilities ranging from 27 to 107 millidarcies. Additionally, as stated in our press release, these zones are not in the Rosalyn formation which was our primary target prior to drilling, but rather in the Wenatchee formation, which was our secondary target before drilling. But now based upon the fact that it appears to contain gas saturated sands, it will be a primary target as well going forward.

Each zone will be perforated followed by a short flow and pressure transient test. Stimulation will follow if required based on transient results and unstimulated flow potential. Subsequent to that will be a longer flow period and longer pressure transient buildup testing. These tests are required to determine flow capabilities which then can be used to estimate reservoir recovery potential. Each completion stage of testing will follow a similar flow and analysis procedure. Results from this effort should be available in next few months.

In regards to our future plans in the Columbia River Basin, we are actively permitting additional wells. Should the Gray well prove to be a commercial well, we will immediately begin preparations to drill a confirmation well on what we call the Bronco prospect. This well would likely spud in the fourth quarter of this year. As mentioned in the press release, future wells are expected to experience a significant cost savings resulting from both procedural changes and higher execution expectations. The combined savings should be substantial in comparison to the drilling costs experienced in the Gray well.

As Dan mentioned, we have had a focused and rigorous effort to control and reduce our costs. We have implemented two separate rounds of staff reduction that have brought our headcount to just over half of what it was at the beginning of the year. Dan and I believe the company has the appropriate staff and talent level necessary to develop its core assets. We have also had successful negotiations with a number of our service providers to reduce the costs of ongoing services. Our leadership team is drawing on past experiences to identify and implement a number of broad based cost reduction and capital preservation initiatives. While we continue with this effort, we are pleased with the cost reductions we've been able to realize to date. These reductions in cost structure and activity are all part of Delta's strategy to enhance and preserve our liquidity.

In regards to the monetization of assets, we have done a thorough review of our asset portfolio and have selected a group of assets -- some producing, some nonproducing -- that we will be selling over the next several months. We estimate through both producing and nonproducing asset sales we will be able to raise around $70 million of additional liquidity.

In the Vega area of the Piceance Basin, we have deferred previously scheduled completion activity. We have 23 wells that have been drilled but not completed. While this will preserve capital in the near term, the primary consideration to delay the capital investment was to coincide with better forecasted commodity prices, thereby generating greater return to the company for its invested capital. With the dramatic decrease in CapEx costs in the Piceance Basin resulting from the lack of drilling and the new cost structures surrounding the currently lower gas price environment, our team is prepared and positioned to promptly resume this activity when commodity prices rebound. As a result of the ceased drilling and completion activity in the Piceance Basin in the first quarter, the production experienced a higher natural decline associated with those new wells coming online. This decline is normal and generally masked in a consistent drilling and completion environment.

I will now turn the call over to Kevin Nanke, our CFO, for a discussion of the quarter's financial results.

Thanks, John. During the second quarter we took initial steps to strengthen our balance sheet. As mentioned, we raised $247 million net to the company in an equity offering and also received $49 million net proceeds from a portion of our litigation with the federal government. These proceeds were used to reduce debt and improve our working capital. Our borrowing base was reduced from $295 million to $225 million in accordance with our forbearance arrangement. We paid down our credit facility to $83 million, leaving $141 million of remaining availability at June 30th. In addition, we reduced our accounts payable by 43% during the quarter.

Delta continues to have the support of its banking group and is confident that the September bank redetermination will not have a material impact on the company's efforts to preserve liquidity. The decision to suspend completion activities is primarily due to the desire to preserve liquidity and time expenditures to yield a better return on investment.

Accordingly, production guidance for 2009 is being revised to 21 Bcfe. These operating expenses have improved from $1.56 per Mcfe in Q1 to $1.34 per Mcfe in Q2. These improvements include lower saltwater disposal costs, field staff reductions, and purchasing compression facilities as opposed to leasing them. We expect further reductions in these operating expenses with additional cost cutting measures at the field level.

Total G&A decreased 29% from Q1 and was comprised of $2.7 million in cash savings and $1 million in non-cash equity compensation savings. We reduced our staff from a high of 160 to 85. Total annualized salary and benefit savings from the two reductions in force approximate $8.4 million. You can expect total G&A to stay consistent with 2Q as we recognized an equity comp benefit for all four [fitted] shares related to the most recent reduction in force during Q2. However, you can expect cash G&A to decrease to approximately $6.5 million to $7 million a quarter for the rest of 2009, as cash savings for the June reduction in force was not recognized in the second quarter.

EBITDAX, adjusted for a one time executive severance arrangement, was $5.8 million for Q2, an increase of $6.2 million during the quarter. This increase almost solely can be attributed to the cost cutting measures previously mentioned.

During the quarter, we recorded $107 million in non-cash impairments. These impairments were made to unproved properties, pipeline and gas plant, pipe inventory, and spare drilling equipment. No proved producing oil and gas properties were impaired. These impairments were driven by sustained lower commodity prices, reduced lease rates, and delayed drilling plans. We recognize that although we've made very important strides during the quarter, we will continue to practice strict financial discipline on both capital and operating expenses.

With that, I'll turn it over to Ryan for our Q&A. Thank you.

(Operator Instructions). our first question comes from John Freeman of Raymond James.

Good morning, guys. The first question I've got on the Columbia River Basin, you guys are raising the CapEx a little bit here despite the delaying of the completion activities in the Piceance. And it's stated that it's because of the additional unexpected costs on a current Gray well and on this next confirmation well you hope to drill, can you say -- what the confirmation well, what you're putting in the budget for that cost, what the AFB is on it?

This is Kevin. I think included on the CapEx is approximately $5 million to initiate the activity on that well. The total AFB is probably somewhere in the order of $25 million dry hole cost.

Okay, great. On the Piceance, can you quantify if there's a certain price where you would restart the completion activities?

John, this is John. Based upon the CIG strip and you get to $3.75 on CIG, the minimum economic thresholds for the company is then met. And as we're heading into the winter heating season, there's a lot of uncertainty with pricing, but we will be monitoring that, but that's pretty much where we believe that it's become -- it becomes economic for completion and drilling.

Okay. And then you mention there's been probably about a 40% reduction in completion costs. Can you just estimate what you think the completed well cost would be in the Piceance?

I would say that there's probably at least a 40% reduction in completed well costs, and our completed well costs are running about $1.95 million at the end of 2008.

So if you were to restart a drilling program, drill and complete a well, what do you estimate it would cost in the Piceance, all in?

Well, you could assume $1.4 million. Once you start up this process and really begin getting hard bids, I expect that number to come down from there, but that's an initial target.

Okay. And then last question I have and then turn over to somebody else, on the acres are that you have at the moment in the Haynesville and the Paradox that you have shelved for the moment -- are there any lease expiration issues we need to worry about on those?

No. We have active negotiations with third parties in all those areas right now but we don't have any lease expirations really throughout the company.

Okay. I'm sorry. I got one more.

Sure.

If memory serves, the DHS, any sort of compliance issues there, if memory serves, that's nonrecourse to Delta. Is that correct?

Correct.

Okay. Thank you very much, guys.

Our next question comes from Tom Gardner of Simmons & Company.

Just to follow up on that question about impairments specifically around acreage, were they related to lease expiration, the impairments, or something else?

No. Lease valuations, the Haynesville has been a wild ride over the last couple years and from initial expectations when gas was double digit to where gas prices are now and how that translates into lease bonuses. And it's just coming in line with what our expectations of what more reasonable lease bonus figures would be in today's world.

Okay. I got you. With respect to your asset monetization plans, you mentioned that you hope to attain $70 million in additional liquidity. Is this figure net of any borrowing base redetermination that may come about with the associated property sales?

Yes.

It's net?

Yes, it would be net to the company.

Approximately how much in the way of properties do you plan to monetize?

Probably about --

Probably around $90 million to $100 million with a borrowing base reduction somewhere on the order of $20 million. We're focusing not only on our producing assets -- a lot of that will be nonproducing, noncore assets.

Tom, what we're really focusing on are the nonproducing assets, things like pipelines and aiming units and ranches and things like that. That's what we're really focused on.

I see. And any specific region or are they just spread out?

They're spread throughout the company. Obviously the pipe inventory is spread throughout various different yards across the Rockies and even in South Texas. The ranches would be acquired in the Vega area for the purposes of not being able to negotiate acceptable surface use agreements. Now that we own the ranches we can put surface use agreements on those lands and then remarket them. Pipelines would be our interest that we own in some of the Vega pipelines as well as what we own in the Paradox Basin. So they're spread around where our core assets are, but they will not affect the economics of a future development of our core assets.

Thank you for that. And one last thought. I appreciate your comments on your plans for the Gray well, the 31-23. Will you be releasing interim updates or is there -- do the well watchers have a leg up on the testing?

Well, unfortunately as far as scouting a well in this part of the world, there's not a tree within miles and they're county roads. And so we really can't restrict scouting of the well. Having said that, it's our intention to comment on the well when it's fully completed. There could be misconceptions even within Delta as far as what a particular interval meant to the overall success of a well. And portraying those results on zones yet to be completed is probably not prudent given this is expiration wells. So we will comment when the well's been fully completed.

And we're moving on this fairly quick. One of the things I wanted to allude to is that there is some uncertainty in the completion of these zones. There's likelihood that these zones will not require fracing, but we are modeling that they might. So you can see there is uncertainty knowing exact timing. And having said that, we ought to have results within the company and results that we think will probably be material to the company here within say eight weeks.

Did you say eight weeks?

Eight weeks, yeah.

And just there's no pipeline currently, so you'll be flaring the gas as you test?

Correct. Or burning it.

I just -- one last question. In a continuous program, I mean just modeling it out, what do you hope to achieve on a well cost basis in the Basin?

Well, any exploration play that moves towards development, you see pretty significant cost savings at least for the first five or six or seven wells. Other plays around the US. especially in the Rocky Mountains, has experienced as much as a 15% capital reduction from well to well for the first several wells. Given the fact that our challenge here is drilling through basalt, there's not a readily available learning curve for Delta and having said that, we think that we have really improved our procedure for drilling the basalt and we're pretty excited about things that we've learned subsequent to actually drilling the basalt section. And that will be the big area of major cost savings that we can see going forward. So I would say -- I'm not trying to get around your question, Tom, but I would say we ought to at least achieve something like double-digit decrease well by well for the first five wells.

Got you. Thank you very much, John.

Our next question comes from Joe Magner of Tristone Capital.

Good morning. Have you released what the actual TD was on the Gray well or can you provide that information?

No. At this time we're not giving any specifics on the well and you understand the sensitivity we have surrounding around the well, and obviously it's a fairly well scouted well. There's a lot of information on it, but we're currently not commenting on specific parameters on the well.

Okay. One parameter you did provide was the 27 to 107 million millidarcies permeability. Was that measured at the surface or was that measured somehow downhole?

That's an ambient air permeability, and we used that because that's more of a common denominator when you talk about permeabilities in other sands.

Do you have any estimate or have you run any tests or calculations on what that might be?

We have studied this route like you can't believe and unfortunately I can't comment on it. We have a lot of professionals and very seasoned veterans working on this both at Delta and with our partner.

Okay. And I guess one asset that's been talked about over time off and on is the potential JV or an outright sale of your Piceance assets. Can you provide any update on those plans?

We're continuing to discuss any and all alternatives here at the company. It is a core asset and is one that we think underpins the value of the company now and going forward. And having said that, we're in conversations with various different entities concerning all the assets. That's not one that we want to turn loose, though, because we know the value of that asset is so dramatically increased in a more normal gas pricing environment. But having said that, we are focused on any and all alternatives, funding alternatives.

Okay. In terms of the gas production trajectory, just did it quickly, looks like 18% decline sequentially. Is that indicative of what you expect to be going forward? If not, can you provide an estimate?

Well, it depends on future drilling. These are hyperbolic declines and they have steeper declines initially and then they flatten out with time. As time goes on, the decline arrests itself and flattens to a fairly shallow decline ultimately. When you have normal ongoing development in a field like the Vega, new wells -- continually bringing on new wells masks individual wells' steep initial decline for the first several months. You only saw that in the first and second quarter because not only did we quit drilling, we quit completing. But having said that, in a normal situation with an ongoing drilling program, you actually have increasing production, and then at some point when you're done developing this asset several years from now, it will experience initial steep decline for a few months and then it will flatten out over time. I don't know if that answers your question, but I guess what you're alluding to is the decline we saw from first quarter to second quarter, is that normal? And the answer is no, it will get shallower and shallower with time.

Have you seen that [rest] itself during the quarter and do you have any July volumes that might provide some indication of -- ?

I don't have that really available at my fingertips. I will tell you, though, we've modeled every well in this field and they have a very predictable production profile, and there should be no variance whatsoever from that production profile because we have wells with years of history, and they all have the exact same shape or very similar shape. The only difference in reserves is more of a difference of initial starting rate in the pay thickness.

Okay. I'll try to take a stab at what the production looks like.

Call me and we can talk about it offline. I can walk you through the production profile.

Yes. I mean we've built it internally. I'm just trying to get a handle on --

I mean there is a ton of research on Piceance Basin and its production profile and all the different fields and they really don't change much. The Vega area is one of the thicker pay calls, and so it behaves like some of the fields to the north like Rulison and some of those fields. So -- and they have more history, so there's a lot out there.

Okay. We can follow up offline. Any additional information that you can provide on the timing of the second California litigation settlement, where that stands and what the hurdles are going forward to getting that completed?

I'm going to put Ted on the line, Ted Freedman, our Corporate Counsel and he can answer that question.

We'll be all right now, as we have a judgment against the federal government for $91.4 million. The federal government has filed a notice of appeal of that judgment, but has not yet filed its opening brief. The briefing schedule right now is for all briefing to be completed in November. It's possible that we would have oral arguments as early as December, but I'm expecting it in January with the decision likely in the spring of 2010.

Okay. Is that final appeal option they have, similar to what took place in the first one or -- ?

It's exactly the same as the first one. They can always -- they would have the option of filing a writ of [social] with the United States Supreme Court, but they didn't do it last time.

Okay. And then Dan or Kevin, you mentioned that based on the outlook you might not be in compliance with your bank covenants at the end of the year. It looks like the end of the second quarter your borrowings were well below at least the conforming base as it stands. Even with the reduction of some property sales of $20 million to $30 million you'd still have some flexibility there. Can you just lay out what the limits on covenants will be or could be that you're anticipating?

Yes, sure. The leverage ratio takes into consideration the last four quarters of our EBITDAX, and as you recall, last quarter it was negative. So what we're talking to the banks about is giving us some relief over these next couple quarters and then having them do more of an annualized calculation on leverage ratio going forward, most likely in the second quarter. So what we would do is take our EBITDAX for the second quarter times four, and with that we anticipate being in compliance with that particular covenant going forward.

And keep in mind the challenges that we're facing on bank covenants is not a liquidity issue, but merely a covenant issue. That also makes it easier for to us have these discussions with the banks.

Okay. That's all I have for now. Thanks.

Our next question comes from Joe Allman of JPMorgan.

Thank you. Hi, everybody.

Morning.

Hi, Joe.

John, what are the implications of that secondary target, the Wenatchee, maybe becoming the -- primary target and is that the case? Is the Wenatchee less extensive than the Rosalyn? Can you talk about what the implication may be?

Well, I'll try and touch on it without revealing too many facts and adhering to our agreement. By the way, you said it correctly, nobody around here can pronounce it right. But the Wenatchee is an uphole formation that was generally thought to be a secondary target in the Basin because it appeared to be porous and permeable, but also contained water in different parts of the Basin. We're lucky where we are here to have a higher than previously seen gas column. And so now you have these sands in a different environment, in what could be a gas charged environment, and appears to be. Further testing will validate that. As far as how big of an area it covers, again this is the first well that looks like this, but I will tell you those sands are persistent throughout the Columbia River Basin. You can find those sands in all wells, just where we are they appeared to be gas charged.

Okay. That's helpful, thanks.

I will state that the Rosalyn was the primary target prior to drilling. Everything that we learned about the uphole formation excites us about the Rosalyn potential, knowing that the gas source is actually in the Rosalyn. So the Rosalyn is -- will not be moved to a secondary target. We must have two primary targets.

Okay. And thanks, that's helpful. Just moving over to the Piceance, if I remember correctly at the beginning of the year, I think you had 30 wells drilled but not completed and now you've got an inventory I think you said 23. So does that mean that you've completed seven wells? And if that's the case or whatever the number is, how much has that cost you so far this year to complete?

Yes. We had 31 wells at the start of the year. We've completed eight of them and we have 23 remaining to be completed at some point in the future and I'll let Kevin speak to the costs of completing those eight wells.

We spent approximately $3 million to complete those eight wells. All of that's included in the second quarter CapEx.

Okay. And so the rest of the spending this year, has that mostly been Columbia River Basin or -- ?

Yes.

Yes.

Okay, okay. That's helpful. And, Kevin, regarding the borrowing base for your determination, it seems you're thinking that maybe you'll get a reduction of about $20 million. What gives you the confidence in that? I mean could you talk about -- have you --

No. That's not what we said. I think if we sell assets, we will be required to pay down $20 million. We are in discussions with the banks right now on a redetermination and really haven't come up with any potential paydown and hope that -- and plan on that being very immaterial for the quarter. But that will happen over the next month or so.

Okay. I get it now. So when you were talking about asset sales, you were just linking the borrowing base reduction with those particular assets?

Correct, correct.

But I guess in terms of reserves, I guess it would appear that you probably didn't add reserve this year. Is that right? So when it comes time for the borrowing base redetermination, the reserve number probably will be lower than what it was last time you had the redetermination? And then I guess are the banks signaling that the gas price is going to be lower, too, than -- ?

Well, from a PDP standpoint I think we've pretty much preserved our reserves and that's -- we're going through those numbers right now and we'll be sending our initial reserve reports to them. The price deck has been floating up and down and, in fact, just right before the call we were a little too aggressive on their price deck and we're rerunning numbers and hope to maintain the same PDP as we had before.

You should keep in mind, from a strategic standpoint, the banks have been working very closely with us. We have done everything that they have asked to us do under our forbearance agreement including raising equity, lowering costs, and selling assets and continuing to look at selling assets. In addition to that, the borrowing base discussion, there's only one part of the overall discussion of our loan capacity with the banks. And we are working -- they are working very closely with us and we expect a positive outcome.

Okay. That's helpful, Dan, appreciate that. And the cost savings -- earlier in the year you highlighted some cost savings that you targeted. Are those on track? Are they a little slower than expected or better than expected both from a capital expenses and operating expenses?

I'd have to say in generality that they're better than expected. Our guys have done a very efficient job of really going in and either bidding out or sitting down with our particular vendors and various different accounts and convincing them that this is the right thing to do for Delta's viability, and Delta's viability ultimately pays their bills. So I'm very pleased with the evident that the guys have put forth.

Okay. That's helpful.

Having said that, it's obviously a little bit harder when you have a payables issue that we had earlier in the year. So it made it even more challenging, but we've overcome that.

Okay. That's helpful, John. And then back to the asset impairment issue, I think the impairment was $107 million. Kevin, could you give us how much of that was just related to leasehold and say, for example, on the Haynesville, does that mean that you wrote that down entirely or you just think you were carrying that at too high of value and you just -- ?

Yes, we thought we were just carrying it at too high of a value. The key was going to be coming out here in a couple hours, and it's well detailed on the impairments by area, not exactly sure the number. I'm thinking it was approximately some $20 million in the Haynesville. Let's see. Yes, $26 million we impaired the Haynesville. We still believe in our Haynesville acreage position, and it's just that the lease rates around some of it were substantially reduced from where we purchased it.

Yes. There's a lot of renewed interest in and around one of our biggest blocks in particular, but having said that, there's a perception that the overall lease bonus has come down dramatically even with some of these big IPs that have been reported close by.

Okay. Very helpful and then last one, in terms of asset sales, could you highlight like where are you in the process, and are you close to agreeing on some of the asset sales or can you give us some details on that?

Well, various different stages. Some things are easier to sell than others. Pipe inventory may be a little bit easier to sell than say a ranch in the Vega area. But having said that, we have people assigned to each one of these assets and they're all ongoing. We've had data rooms. We've had data rooms set up and we've had numerous different people in here. I think that there's a perception in the industry at least here at Delta that for the past three or four months it was not all that easy to sell any asset in the oil and gas sector and things seem to begin to be freeing up a little bit. So we have -- it's focal. I will say that and it's very concentrated in its effort whether it's nonproducing or producing. The expected timing is in the next several months. I can't comment exactly when we're going to sell the ranch, but I will -- I do expect to have a lot of this concluded by year-end.

Internally, the assets to be sold or to be considered for sale have been presented to the board along with proposed timelines for those assets. We do currently have in-house bids on some assets that, as John said, are easier to market more liquid-type assets. We also have assets out to some specific potential buyers. So progress is being made and the board is watching this project carefully.

That's helpful. Just what about on a gross basis, what proceeds are we talking about? Is that -- ?

$90 million.

$90 million, okay. So that's all in, everything you've got marketing right now?

Well, yes.

That's less than all in. That really contemplates what we reasonably expect to accomplish over the next six months.

Right. Dan's right. Our expectations are a portion of what we have for sale will actually sell.

Okay, got you. Very helpful.

Okay?

Good stuff. Thank you.

Our next question comes from Evan Templeton of Jefferies.

Hi. Just two detailed questions on some of the items in the income statement. Just first of all, interest expense just seemed higher than I modeled based on some calculations. Are there some one time events or charges running through that?

Yes. We did take a one time write-off of our deferred amortization costs for DHS, as at this time we do not have an agreement with the Lehman commercial paper group, and when you do not have an agreement in place, you're required to write off all of your costs. And that was in excess of $0.5 million.

Okay. And anything else running through that or that's pretty much it?

No, that's pretty much it. It's probably the timing of the paydown of our debt, which happened at the end of the quarter.

And then also just similar question just as far as G&A. What was the non-cash comp component?

The non-cash comp for the quarter was almost $1.8 million. It will be detailed in the Q also, but that is probably $1 million less than your run rate going forward.

Okay. Perfect. That's it. Thank you very much.

Our next question comes from David Tameron of Wachovia.

Hi, good morning. Most everything has been answered, but one quick question. Piceance, does this have any impact on the EnCana JV? Where do you stand on that agreement?

No. You mean does the ceasing of completions and drilling? No.

Yes.

Doesn't currently have an impact on the EnCana joint venture.

EnCana relationship is purely a financial relationship.

Okay. And my understanding was if you didn't drill down, if you didn't get enough wells done by a certain time, that under the agreement you had to complete so many wells by a certain date -- is that correct or am I incorrect?

No.

That's the old agreement which we took out with our last --

My bad. All right. Thanks.

(Operator Instructions). Our next question comes from Jack Aydin of KeyBanc Capital Markets.

Can you hear me?

Hi, Jack.

Hey, how are you?

Fine, thanks.

Regarding the asset sales, is the Paradox and Haynesville assets are on the block, part of the asset sale package?

The Paradox assets we still have quite a bit of hope for and we're looking for more joint venture participation in the Paradox asset. There's just too much romance left with that particular asset and the Hingeline play where it's a combination of the two either an outright sale of the leases or joint venture participation, and might even be a hybrid of that.

I was mainly asking about the Haynesville acreage.

Haynesville.

Yes. Is that --

I'd have to say the same, either an outright sale or potential joint venture participation.

John, regarding the CRB, if it is an offset well, will cost you dry hole in a sense $25 million. Wouldn't be spreading risk more advisable in a sense, doable, get the joint venture partner? I mean $25 million dry hole costs for a company of your size is a lot. I mean I know it is not all -- it's all yours. Are you in the process or -- ?

Well, Jack, as you'll recall we have a partner, so I think we've made it public that we only have half interest in the well. All these decisions can be made a lot more concrete once we have completion results on the well. But I mean we talk about any and all scenarios around here, but right now what we need to see and you guys need to hear are concrete results on the well, and that's what we're focused on getting.

Jack, we have plenty of liquidity in-house today to drill our proportionate share of the CRB well. It's $12.5 million for our proportionate share.

Okay. When would you need in terms of EUR to make it economical for that kind of cost on a full cycle in a sense in development phase?

Well, it's too early to tell at this point, Jack. We have to see what the production profile looks like, get a better handle on marketing and timing. It's just -- when we get some results from the well, we'll then be able to comment on the economic viability of it.

Thanks a lot.

Our final question comes from Joe Magner of Tristone Capital.

Thanks. Just one follow-up to Joe Allman's question about the completions that took place -- sounds like mostly in the second quarter. Can you provide a little more detail on the timing of when those may have come on?

Mostly in the first quarter, I believe, spilled into the second quarter. February, March, April timeframe.

Okay.

A little bit in May.

Thanks.

That does conclude our time --

Well with that, with the questions being over we appreciate very much you being on the call and we look forward to talking with you in the future with some meaningful results. Stay tuned and thanks for tuning in.