Par Pacific Holdings Inc (PARR) 2008 Q4 法說會逐字稿

Hello and welcome to the Delta Petroleum Corporation 2008 year-end and fourth 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, Vice President Corporate Development and Investor Relations. Mr. Richardson, please do ahead.

Thank you. Good morning. Before we begin I would like to remind you that we are conducting this call under Safe Harbor and 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 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. Today's participants from Delta are Roger Parker, the Chairman and Chief Executive Officer, John Wallace, President and Chief Operating Officer, and Kevin Nanke, Treasurer, Chief Financial Officer, and Ted Freedman, our General Counsel. With that I will turn the conference call over to Mr. Parker.

Thank you and good morning. Yesterday, Delta Petroleum reported its 2008 financial and operating results. Operationally, 2008 proved to be a year of significant reserve and production growth, as well as record revenue and EBITDAX. We reported proved reserves of over 884 bcf equivalent, up 135% from year-end 2007 and up 35% from the unaudited proved reserves reported as recently as September 30, 2008. Equally impressive is that we were able to grow our proved reserves with an all-in finding and development cost of only $1.37 per Mcfe, a drill bit finding and development cost of $1.55 per mcfe. And in spite of declining commodity prices, we also reported revenue of $221 million and EBITDAX of $156 million, which represent increases of 79% and 80%, 86% respectively over 2007 levels. Production also increased significantly by 48% averaging 68 million cubic feet equivalent per day for the year.

While I think 2008 certainly was a year of accomplishments for Delta, it also ended with significant challenges relating to the precipitous drop in commodity prices. Along with the filing of our 2008 10-K and related press release yesterday, we issued an S-3 registration statement and a rule 134 press release in conjunction with an expected shareholder rights offering of $175 million of convertible preferred stock. Additionally, the Company has signed an agreement with the lenders in our senior credit facility that provides for covenant relief for 2009 and 2010. The combination of this offering and the forbearance from our banking group will provide the Company with sufficient liquidity and flexibility to endure a prolonged downturn until commodity prices recover. Additionally, as part of our go-forward plan, we will also be hedging to take advantage of the Contango and the gas price strip. We will also be paying attention to meaningful cost reduction.

Our general and administrative expense, as shown in our fourth quarter financials, decreased by 23% from the third quarter. This downward trend in G&A will continue into 2009 and we are taking the necessary steps to reduce projected 2009 G&A by at least 50% relative to 2008 levels. I will also address our proved reserves at this point. The total proved PV 10 is lower than our proved developed PB 10. However, if you were to run the reserve deck at today's strip, total proved PB 10 goes up significantly. Further, the year-end reserve estimates include historical capital costs from 2008, which are clearly coming down and doing so in a very meaningful way. As you would expect, numerous contractors have indicated large reductions already. If you were to further assume lower capital costs and the current strip, total proved PV 10 goes dramatically higher.

In our major areas of leasehold ownership, it is also important to note the following. In the Paradox Basin only 3.5% of our existing leasehold would expire over the course of the next two years. In the Utah Hingeline play only 1.4% of our leasehold would expire over the next two years. In the Columbia River Basin only 4.7% of our existing leasehold will expire over the next two years. In the Piceance Basin only 5% will expire over the next two years and 81% is currently held by production. In the Haynesville acreage approximately 24% will expire over the course of the next two years, but in every single one of these areas we will be taking the necessary efforts to insure that we maintain ownership of all of our important leasehold. Lastly, I will address indicative terms related to the convertible preferred rights offering.

We have discussed indicative terms of the rights offering convertible preferred with our major stockholders that we would offer once our registration statement is declared effective. The terms we have talked about are a $3 pricing indicating a $3 liquidation preference and conversion price, a 3% pick dividend and a mandatory conversion at the third anniversary of the issue date. On the basis of those discussions, Tracinda Corporation and another significant stockholder have indicated their intent to participate at approximately their pro rata share. With that we will go ahead and turn the call over to questions and answers.

(Operator Instructions) The first question comes from Tom Gardner of Simmons and Company. Please go ahead.

Good morning, everyone.

Morning, Tom.

Hi, Roger, can you walk us through the timeline of getting this shelf approved and you've laid out some of the structural terms, but just want to get an idea of what needs to occur to get that going.

Tom, we have filed a registration statement and timing is up to the SEC. It is impossible for us to predict whether or not it will include review or not.

The next question comes from Joe Magner of Tristone Capital.

Good morning. Thank you. Just wonder if you can walk through the reserve bookings. If I go through this based on some of the map that I was looking at adjusting for the acquisitions, it looks like you've booked on average 4 to 4.5 offsets per approved developed location and that would be up from 1.5 to 2 offsets from year-end '07. Can you comment on that and then just comment on what changed throughout 2008 that allowed you to increase those bookings.

Yes, Joe, this -- you are correct, the overall total is approximately a 4 to 1 booking and is primarily related to 10-acre booking in the Piceance Basin. We have indicated to others before in previous calls and especially at the end of 2007 that like many others in the Piceance Basin, Delta's properties qualified for ten acre development and that we had received approvals as such. There were, there was a significant amount of work and effort done to establish ten acre spacing as the correct spacing for booking purposes in the Piceance Basin. That's how we have ended up with the increase in proved reserves that you point out.

Okay. In the release and in your K you talk about some possible divestitures, asset sales, as part of your need to raise proceeds. Can you talk about, in addition to the Piceance Basin JV and the Haynesville JV that were mentioned specifically, what other properties could be on the block?

We have numerous nonproducing assets at this point in time that have a reasonable value associated with them, even with taking into consideration the current economic environment. We are working on many different fronts to do things. We refer to joint ventures related to the Haynesville and the Piceance Basin effort, but I think it is also fair to say that we are essentially looking at that type of a situation on virtually every area of ownership that the Company has. We, as an example, I will refer you to the comments that we made in the Paradox Basin section. There's additional drilling activity going on immediately adjacent to us as we speak. There is, we believe, and we believe that there is additional production that is desirous of getting into the pipeline and processing facility that we own and we think that there may be opportunities related to that type of a thing as well. So, there're, without getting into the detail of all of these things, I guess I would say in a very general sense that we think that there is on the order of $100 million worth of potential liquidity type activity that would be related to joint venture and/or sales efforts.

Okay. And I guess one thing to circle back on the previous question about the rights offering timeline, I think there's a two week period the SEC has time to decide whether they're going review it. If they decide to review it, can you walk through what the timeline could look like, whether they do or whether they don't review?

Joe, just a moment. We are discussing off line here for a second. Joe, with regard to the SEC, it is typical that they will let us know one way or another within a few weeks, but it is -- we are really not in a position to make comments with regard to the timing that the SEC will take to do something or not do something.

Okay. And just one last one, it looks like you will be required to hedge some of your production this year and next year. Have you hedged anything yet? If so at what prices and do you have a sense as to what the basis will look like on those positions, either for the tail end of '09 or 2010?

Yes. We are -- we have not as of this moment hedged, although we will be looking to do so here in the very near-term over the course, probably, of the next week or two. And with regard to differentials and everything else, it is, we all, we all see the same thing as to what is out there at this point.

Okay. Thanks.

You bet. Thank you.

The next question comes from [Crystal Choi] of Raymond James.

Morning.

Morning, Crystal.

Wondering (inaudible)- what kind of activity does that assume?

I'm sorry, Crystal, can you repeat that. We can barely hear you.

And if you could move the voice tube a little bit closer, Ms Choi, that might help.

Is this better?

That is better, yes.

Okay. The 52 million, I was wondering what kind of activity that assumes now?

Well, in a very general sense, what that allows for, we tried to set it out in the earnings release, but the 52 million essentially allows for obtaining all of the necessary information including completion and testing information at the Columbia River Basin. Grave 31-23 well that we are drilling and then also what will be a very measured and consistent effort of completion activity on our drilled but not yet completed wells in the Piceance Basin. And the combination of those two things makes up the majority of the 52 million.

Okay. So the timeline on activity in the Piceance meaning bringing the wells on-line, do you have any kind of expectations of when they will be tied in?

Yes, the intention is to do it, as mentioned, in a very measured way so that we can keep production as close to flat as possible. And that is the intention behind the completion effort in the Piceance.

Okay. And what is your internal rate of return in the Piceance with $4 NYMEX gas.

I am going refer back to some of the opening comments that I made here related to our proved reserve bookings. I think at this stage of the game, it is not appropriate to use capital cost pricing from 2008 when you look at a commodity price deck that we are currently experiencing right now. We have already -- we would note again that numerous contractors, not only with Delta, I'm sure, but with others in the industry as well have proposed significant cost reductions. And if you were to, if you were to assume that these significant cost reductions will take place, then in a very general sense, the rates of return, even at a lower commodity price deck, will be very good.

And I would further comment that if you turn the clock back to the 2001 to 2005 timeframe, you had a commodity price scenario that was somewhat similar to where we are today and there were numerous companies that were able to grow and experience very reasonable rates of return out of the Piceance Basin based on -- or with lower commodity prices. They were able to do so because capital costs at that point in time were significantly lower than where they are today, all of which speaks to the idea that as we go forward here, if commodity prices do not change from their current levels, I think it is very safe to assume that capital costs are going to come way down, substantially down.

Okay. Stepping to the CRB on the gray well, do you have any kind of estimate on how much the completed costs will be or can you tell me how much has been spent so far.

No, and in fact, the comments that we have made in the press release are typically a little bit more than we would make at this stage of the game and with a well that is still drilling, but given the overall situation here, we felt it necessary to go ahead and come forth with the information that we did. So, we put quite a bit in there, but that will be the extent of what we will comment on the Columbia River Basin at this point.

Thanks.

Thank you.

The next question comes from [Zin Loo] of JPMorgan. Please go ahead.

A couple of questions. For your (inaudible) asset I think that you moved off assets for sale category. Is that still a viable option to sell that asset?

We have received proposals related to the asset as of this point in time, but also as of this point in time we have not made any definitive decisions as to what to do with the property. And that's the reason for moving the property out of the current asset category. Or out of the category as being listed as an asset held for sale.

Okay. Is the offer received above the book value you had at end of third quarter.

We can't speak to that.

Okay. Then looking at your fourth quarter severance tax, it seems a little bit low. Should we expect the same (inaudible) in 2009 or there is some one-time items.

I'm sorry. What was low? Which item.

The tax, severance tax.

Just a moment.

For the production tax.

Yes, we did see, receive severance tax credits back for some of our properties in south Texas. So there was essentially a onetime reduction that would be nonrecurring and as a result, the third quarter numbers are probably more representative of what to expect on a go forward basis. On a cost per unit basis.

Okay, thank you.

Okay.

The next question comes from David Tameron of Wachovia, please go ahead.

Hi. Thanks, good morning. A couple of questions. DD&A rates, can you give us an indication. Given the reserved bookings and the impairment charges, do you have a number for that, Kevin or Roger, going forward for 2009?

Okay. You think so?

Hi, David. We think that the fourth quarter mcf numbers are representative of what's going to go forward. So you can use that number.

Piceance Basis would actually be slightly lower on average than fourth quarter. I think it was right around 380, something like that. No, it was lower than that. I am sorry, David, go ahead.

Thank's fine. And then cost reductions in the Piceance, what magnitude are you looking for? Obviously, it depends on prices, but let's say prices stay where they are at, what magnitude would you need and what are you seeing out in the field?

David, all I can do is tell you some of the things that have been proposed without detailed negotiation thus far. We've had proposals on the order of 25% to 35% cost reductions depending upon which contractors you are talking to. And I think it is widely assumed and expected across the service industry that if they're not coming forth with those types of reductions, they're certainly going to see a continuing reduction in activity, not only from this company but from all others as well. So those are initial indications, but I think one of the things that I think has been very helpful is we are in an environment right now where everybody, there have been a number of companies, especially the bigger ones that work for us out in the field that have approached it from the standpoint of we are all in this together so we are going to come to the appropriate amounts that allow for an economic viable program going forward and if costs have to come down that much or even more, then there's probably going to be a concerted effort to try and allow that to happen.

All right. But at $4.00 gas if you get 30, 25%, 30% reduction in service costs then Piceance works, I take it.

Yes, if you put a 30% cost reduction on your program out there, your rates of return jump back up to very appealing numbers.

All right. And before we leave the Piceance, the JV with EnCana, you have got the $100 million in November payment but that's looks like it's already -- you still have that cash sitting on the other side of restricted deposit.

That's important to point out. We have 300 million in restricted cash on our balance sheet. And that cash has been set aside for a letter of credit that was issued by JPMorgan to EnCana specifically for the payment of the EnCana transaction that we entered into a year ago. So those payments are already set aside and do not affect our go forward plan.

Okay. And my question was going to be, are you -- you've talked about Piceance JVs, are you allowed to or what restrictions do you have surrounding the EnCana agreement that would prohibit you from selling it or can you -- ?

We have no restrictions.

Okay.

We have no restrictions related to our EnCana agreement. It was a straight acquisition.

And as I think if you were to sale that asset or JV that asset, you would still owe that restricted deposit to EnCana, correct?

Yes. Essentially take the cash and set it aside and consider the agreement with EnCana fully paid.

Okay. Let me look out six months if you get this offering, assuming you get this offering done, what do you see -- in the 10-K it still talks about the conforming basis 185, so assuming you would have to make that whole at some point, plus you have the accounts payable, come June 1, how do you see the -- how do you see your financial situation. Can you give us a snap shot of what that looks like, how much cash flow you think you will be generating and is there a need to do additional equity behind that.

No. The intention behind this effort is to insure that the borrowing base reductions that will be required to occur are covered. And that all other items necessary are covered and that we also have sufficient liquidity that will allow us to go forward in the current commodity price environment. That was, as you might expect, important to both the combination of our banks and our largest shareholders, both of whom continue to support the effort and the assets that the Company owns at this point.

Okay. If if I just got my model, Roger, I show a deficit this year, relative to that 50 million CapEx. What kind of numbers do you guys expect for cash flow and what are you guys showing internally or -- .

I would -- the one thing, I guess, I would bring up at this point, David, is that I think we probably are going to be more aggressive in our expectations than you are with regard to cost reduction. As mentioned earlier in the call, we are looking very hard at G&A cost reduction of levels that will be on the order of 50% of what they were in 2008. And behind that and related to the other comments we have made about capital cost reduction, that will flow through to your lease operating expense as well. So, we do not have a deficit in our models for 2008.

Okay.

Excuse me, I'm sorry, 2009.

So you show yourself generating $50 million of free cash flow, excluding the rights offering?

Or the CapEx.

Yes. So you generating -- your models show you are generating cash flow equal to CapEx for '09.

Essentially, yes. Okay. All right, one more question, I promise, last one. Not a problem.

Acreage, you mentioned somewhere in the K that some leases have to be drilled, I believe, by June. Is that the Haynesville well and can you correct me, is that the right timing on that.

July 1 for one Haynesville lease.

One Haynesville lease, so you just have to drill one well, or is there -- what is the drilling obligation associated with that.

Sorry, David, can you repeat that, please.

What is the drilling obligation? You have one lease that expires, is it one well on that lease or do you have a drilling obligation, what's your obligation No, we have a drilling obligation and to the extent that we don't begin drilling activity, we will either need to negotiation an extension, which we think is very possible, or alternatively allow the lease to expire.

All right. That's all I got. Thanks for taking my call. Okay, thank you.

The next question comes from Shannon Nome of Deutsche Bank. Please go ahead.

Thanks, good morning.

Morning, Shannon.

A couple of reserve-related questions. Did the ten acre spacing down spacing reserve adds show up in the revisions or was that, which category did that show up in?

That's in revision, Shannon.

Okay.

Let me make another comment in that regard as well. We would note on your 10-acre spacing there that we now have 158 producing wells and with that we have been able to prepare extensive petrophyisical and geological information that confirm similarity of rock across the -- our entire leasehold, but in reality across a very good portion of the basin center in the Piceance Basin. So, in any case, I think that's worthy of note related to the ten acres.

And can you just aggregate, I'm presuming that that -- just given the increase in your future development costs, that the actual growth upward revision was quite a bit higher than the whatever, 166 fees that you showed. Can you just aggregate what the gross upward revision was and what the net downward presumably revision was for pricing?

Yes -- .

The corporate components of that.

Yes. Hold on just a moment. Yes, the, Shannon, the upward, the upward revision as mentioned was essentially all related to 10-acre spacing. There were downward revisions of approximately 35 bcf.

Okay.

And the 35 bf equivalent extended across a number of properties, but primarily south Texas.

Okay. And then were the upward revisions 100% PUD category?

Virtually all, yes.

And then which geographical areas were the extensions and discoveries booked, then you had a pretty healthy booking there too.

Yes, that was also primarily Piceance Basin. We did have four rigs running virtually the entire year last year, all of which was a 100% successful program. So that is where that comes from.

Great. And then other question I guess going back to your, one of your opening comments that your PDP or your total PV 10 is actually less that the PDP PV 10 and I guess just to clarify what the booking rules are, how, like how can you book a reserves for a location that have negative PV 10. Is that allowed under the booking rules or do those not have to square up or how does that work?

No, it is allowed and it is not a negative PV, it is a negative PV 10. So -- and I'm sorry but I'm speaking off the top of my head at the moment. I think you had the equivalent of approximately a PV 8 for most of your puds, which gives you the negative PV 10, but certainly a positive PV. And the requirement is that you have positive PV.

I see and you are using 8% as a cost of capital or what's the 8? Why use something other than 10, I guess.

We are not using something other than 10. I am telling you that that's what the calculation came out to. The SEC rules are to book a PV 10, obviously -- well, the rules are that you need to report related to SEC PV 10 and because the puds did not qualify for PV 10, they actually show up as a negative number in spite of the fact that they have a positive PV. And the positive PV, I believe, is on the order of PV 8 for the puds.

Okay.

Using year-end pricing and historical costs. That's why I made the comment that if you were to run these same reports based on the current strip, all categories would have a positive PV 10 and the PV 10, total proved PV 10 would be substantially higher than it is as reported in the 10-K.

Although it seems year-end pricing -- gas prices have actually dropped, but you are saying because the curve is upwardly sloped that you would actually get a higher number now.

That's correct.

Okay. And then do you think since you're spending $52 million trying to keep production flat, is that a descent go forward estimate for where you think your maintenance CapEx is.

For 2009, yes, but you have to take into consideration that we do have an inventory currently of 35 wells that have been drilled and not yet completed.

Right. So (multiple speakers).

So additional wells, additional wells for future years will need to be drilled.

So those 35 wells ostensibly will be exhausted by year-end then.

That's correct.

Okay. And final question, what is your -- you disclosed I think your gross acreage in the Haynesville, what's the net number.

The net number is approximately 11,000 acres at this point. It is 11,000 with, with conditional agreements that would allow that number to grow to 17,000 if we were able to drill in the latter part of 2009, which is not currently in our CapEx budget.

And the lease that expires in July, how large is that? Can you say.

It is approximately 4,000 acres.

Okay. Great. Thank you, Roger.

Okay, Shannon. Thank you.

The next question comes from Greg Brody of JPMorgan. Please go ahead.

Good afternoon, guys.

Afternoon, Greg.

I was curious for the cash flow expectation that you are forecasting, what is the pricing you are using in differentials you are assuming?

Current differentials and current NYMEX strip. I think that at last look, the CIG differential at this point is probably an average of about $1.60 for the remainder of 2009 and lower than that for '10.

And with the DHS, how many rigs are currently operating?

DHS is kind of fluctuating between 3 and 5 rigs running full time at this point.

Do you foresee any more coming any way down over the next several months or -- ?

I think that they are reasonably confident they will be able to keep that level in operation. There was, there was, obviously, a dramatic and swift decline from between the beginning of December and the end of January. Virtually all the rigs were running through the end of November, which was 20 rigs. And by the end of January they were down to a level of four or five.

Okay. My final question, if you wouldn't mind just providing some color as to how you think the basis will play out over the next year, if you see anything, any indications of improvement, reduced supply, et cetera.

The gas price basis differential.

Yes.

Yes, we are, we are of the opinion that as the Rockies Express eastern leg becomes operational you are going to have a reduction in differential in the Rocky Mountains and that that in combination with El Paso's announced and recently reconfirmed intent to go forward with the Ruby Pipeline to the west coast, is going to bring down differential, Rocky Mountain differentials in a pretty significant way over the course of the next two years. So, the expectation is that we could get into a much better differential environment over the course of next 12 to 24 months.

Is it your expectation that Ruby will still be on-line sometime in 2011?

We can only go off of El Paso's public comments, which were released and reconfirmed only a few weeks ago. I believe that that's what they said.

Thank you very much.

Thank you.

The next question comes from David Tameron of Wachovia. Please go ahead.

Hi, one follow up.

I thought you already asked all of your questions.

Oh, no. I have got a list longer than anybody wants to hear. Just quick question on the Piceance, the 10-acre spacing, what reserve, what reserve are those booked at compared to the 20s, as far as URs.

I believe it is, no, hold on just a moment, Dave. Dave, let me -- we are getting the answer for you right now, but let me also make a comment with regard to the, to the properties that Delta has out there, which I think is reasonable to point out and discuss at this point. We have a, a thickening gas column across the leasehold that Delta owns substantiated by already drilled wells.

Most of the wells that have been drilled on the property and are in production today are on the southern half of our leasehold, which is the thinner gas column portion of our leasehold and the expectation is, as a result, that as you move forward and drill the northern part of the property more than the southern part of the property, your average per well reserve recoveries are coming up pretty significantly over what has been experienced thus far. Now having said that and for reserve booking purposes, we are obviously using -- what you have got is essentially a blended average, if you will. But most of the unbooked reserves that the Company has are going to be in the thicker gas column portion of our leasehold ownership. So that will give you some indication of what we expect on a go forward basis.

All right. Okay. Thanks. If you get that number while we are on the conference call, if you don't mind just throwing it out, appreciate it.

Okay. All right. Thanks.

Thanks.

The next question comes from Joe Magner of Tristone Capital. Please go ahead.

Thanks. Just wanted to -- there was a question asked a little while ago about the current borrowing base and the conforming borrowing base being lower. Assuming you move ahead with the Piceance JV, what could be the impact to the calculation of that borrowing base.

If you were to assume that you did a transaction where you sold off a portion of your PDP reserves as part of a transaction on a JV situation, then undoubtedly you would have a further reduction of your, of your borrowing base related to that. But I guess I would respond to that by saying in the event that that were to occur, theoretically you will get a valuation that will be significantly in excess of what you would need to do to reduce your borrowing base further.

But there's a proceed you would generate you would be able to -- .

Yes, exactly. You would. In fact, there's -- I mean clearly there's no reason to do it unless you were in that position where you could pay your borrowing base down further.

Okay. And then assuming the majority of the $35million to $40 million you plan to spend in the Piceance is used on completion work, what are your thought about being able to convert puds or how your reserve mix may shift between the end of '08 and the end of '09?

On a percentage basis I'm not sure that I have got enough information to give you that right now. Certainly we'll probably have some increase in the PDP percentage simply because we are completing wells that would have been in the pud category at the end of the year. But in terms of -- I guess the one thing I would do is say we have got 35 wells to complete and I belief that we had approximately 150 wells producing at year-end in the Piceance Basin area. So while it is probably not a direct correlation, it will give you some sense of what you might get in terms of pud conversion to PDP.

Okay. Thank you.

I would like to turn the conference back over to Roger Parker, CEO, for any closing remarks.

Okay. Thank you all for joining us today and we will talk to you at the next earnings conference call. Thank you very much.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.