Par Pacific Holdings Inc (PARR) 2010 Q1 法說會逐字稿

Hello, and welcome to the Delta Petroleum corporation first quarter 2010 earnings conference call and webcast. All participants will be in listen-only mode. (Operator Instructions) After today's presentation, there will be an opportunity to ask questions. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Broc Richardson, Vice President, Corporate Development and Investor Relations. Mr. Richardson, please go ahead.

Thank you. Thank you for joining us for Delta's first quarter 2010 financial and operating results conference call. 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 within the meaning of the federal securities laws and are intended to be covered by the Safe Harbors as credited thereby. In that regard, you will refer to the cautionary statement displayed on Delta's website, which is incorporated by reference to the information provided for this call. Delta may use certain terms in this conference call that the SEC's guidelines prohibit us from including in the filings with the SEC. Investors are urged to consider closely the oil and gas disclosures and Delta's Form 10-K for fiscal year end December 31, 2009, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively. Today's 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 will turn the conference call over to our Chairman, Dan Taylor.

Thanks, Broc. Good morning, everyone. As we announced in March, we have signed a letter of intent with Opon International to sell a 37.5% working interest in our properties in the Vega area of the Piceance Basin along with warrants to purchase Delta common stock for $400 million in total. We continue to work with Opon and their financing efforts and are working toward signing a definitive purchase and sale agreement. We cannot comment specifically on the details of the proposed transaction, but we are pleased that the process is going well and we will provide you further updates as expeditiously and prudently as possible. We cannot comment further, so we ask you to be mindful of this in your questions during the Q&A portion of the call.

During the quarter, we completed three wells in the Vega area and thus far are pleased with the initial results, which are better than we expected. John will discuss these completions in his comments. Our revolving credit facility borrowing base redetermination was announced at the end of April. We now have a borrowing base of $145 million, with capital expenditure limitations in place for the second and third quarter this year. Kevin will address the redetermination in his comments shortly. I will now turn the call over to John Wallace, Delta's President and Chief Operating Officer, for his comments on operations. John?

Thanks, Dan. For the first quarter of 2010, Delta engaged in only minimal development activity primarily in the Vega area. To date, our completion activity in Vega has shown very positive initial results. We completed three of the wells with the larger fracture stimulation design than we have previously used in the past. We will be using this frac design with all of our remaining completions and are optimistic about its impact to the field. As I am sure you are aware, natural gas prices have pulled back since the beginning of the year. This pull-back in gas prices is the primary reason for our decision to reduce completion activity in the Vega area. While the current gas prices and forward curve are more than adequate to provide solid returns on the completion capital, we must be mindful of our liquidity position. We believe that we are in a far better financial situation than we were a year ago, and the preservation of our liquidity is essential to maintain and improve our balance sheet.

Given the initial results to date, there is nothing our operating team would rather be doing right now than to re-start our completion activity. However, we are committed to maintaining our more fiscal -- our more disciplined fiscal approach to our capital expenditures with acute sensitivity to the current commodity prices and our liquidity. I understand that many of you would like to receive some guidance on our capital expenditure for 2010, and we know that that is overdue. As we have previously announced, we intend to provide CapEx and production guidance once our strategic alternatives process is completed. I am sure you understand that our expected capital expenditures and production for 2010 will be driven by the proposed transaction more than anything else. I will now turn the call over to Kevin Nanke, our CFO, for a discussion on the first quarter's financial results.

Thank you, John. Good morning. On April 26, we completed our credit facility redetermination. Under the agreement, our new borrowing base is $145 million, and we are no longer required to maintain $20 million of availability. So in effect, the borrowing base was reduced by $20 million. As of the end of the quarter, our borrowings were $93 million, with $52 million of availability based on the revised borrowing base. And we had cash on hand of $10 million. We have a CapEx limitation for the second quarter, which totals $20 million, and a limitation of $15 million for the third quarter. Because the credit facility matures in January of 2011, the debt is classified as a current liability in the March 31, 2010, consolidated balance sheet. We are currently in discussions with our lead bank on a new facility post the Opon joint venture. On April 1, 2010, DHS amended its existing credit facility with Lehman Commercial Paper. Under the terms of the agreement, DHS was required to reduce its principal balance by $20 million over the next year. Almost half of the required principal reduction was paid in Q2, and the remaining will come from current operations. DHS expects to have 10 rigs under contract by July 1. The DHS facility is nonrecourse to Delta.

For the first quarter, we reported production of 5 Bcfe, a decrease of 20%, when compared to the first quarter of 2009, and flat to last quarter. The production decrease from first quarter 2009 was mostly related to anticipated production declines in the Rockies that have not been offset by additional drilling. For the first quarter, E&P revenue increased 55% to $34.5 million when compared with the first quarter of 2009. This was due to a 125% increase in oil prices and an 87% increase in natural gas prices. EBITDAX increased by approximately $11 million over the prior-year quarter, and discretionary cash flow increased to $3.9 million. As John mentioned, we will announce our capital expenditure budget production guidance upon the conclusion of our strategic alternative process. With that, we will open it up to questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) At this time, we will pause momentarily to assemble our roster. Our first question will come from Michael Pena from Simmons & Co. Please go ahead.

Good morning, guys.

Good morning.

I guess first question, for you, John, with respect to the Piceance, could we get a current cost estimate for completions since you guys have about 16 wells to complete there?

Well, cost estimates are moving around a little bit as you do these completions in a one-off basis. And we're experimenting with design, and I don't think our current past quarter cost estimates are realistic for estimates in the future. When we begin drilling, hopefully subsequent to a joint venture, we believe that this additional frac completion cost is going to be about $500,000 to $750,000.

Any sense as to how that could -- whether stabilize production or increase production throughout the year with the remaining uncompleted wells?

Well, it depends on what the timing is and when our completion efforts, although 16 wells, when we really complete those wells, but having said that, we're very, very encouraged about what we see in the field, and the sooner those wells are completed, the more meaningful impact it will have on production. Subsequent to the finalization and closing of the joint venture, that would be the first order of business is, to complete those wells, and that would have a meaningful impact. Which is a little bit why we're not commenting on CapEx and production guidance because it is going to be very much related to the timing of the joint venture and the closure of it.

Right. I understand that.

-- have a better indication.

Okay. Great. And then I guess the issue with LOE, just trying to get a feel for what the cost savings could be. I think you guys highlighted it could be $0.27 per Mcfe for the installation of water disposal infrastructure. Do you guys have kind of a timing as to when we could start to see that roll through?

You know, the water disposal costs are directly related to drilling and completion activity. That is, when we're completing wells, we actually use produced water in the completion process, and have very little if any saltwater disposal costs. So unfortunately, that is also tied to our CapEx and production forecast, which have not been finalized yet, but having said that, that cost savings is real when we're in active completion process.

We actually brought down our costs per M to approximately $0.86 when we were under a full four-rig drilling program in 2008.

Great. That's helpful. That's exactly what I was looking for. And then I guess just a question on G&A, how much of the $8 million in cash G&A for the quarter was recurring G&A and how much of it was related to the strategic alternatives?

I think we had a 7% increase over our previous quarter. I don't have the exact figure on how much related to the strategic alternatives, but I would say almost the entire 8% increase was related to that.

Okay. And then any means to further reduce G&A? I know you guys may be ramping up CapEx to maybe $75 million soon, but just any thoughts on that?

As far as G&A, especially personnel here at the company, we have all the available people that we need to initiate and execute on this joint venture, so that should not have a meaningful effect on G&A.

Okay, great, Thanks, guys.

Our next question will come from Andrew Shapiro from Lawndale Capital Management. Please go ahead.

Thank you. Good morning. I'm trying to get a handle here on whether -- on your approach to risk taking and how you approach things. Presently, you have a bunch of derivatives that lock in the price. And I believe most, but I'm trying to understand if all of it, is tied to what is mandated by the lenders, and what management's philosophy and approach to forwards and locking things in is or would be absent the lender mandates.

Andrew, that's a good question. And one worth noting, because the Piceance Basin and our Vega assets are very price sensitive in their development. Management has a long-term view that natural gas hedging will be a very meaningful portion of our risk analysis going forward. And we will look to do probably longer-term hedges than we've done in the past. In the past being, I don't know how familiar you are with the company or your history with it, normally 12 to 18 months and we would probably look for a longer time period, three years plus. And the reason being is guaranteeing the economics and getting these wells through a payout process is very important to understand the execution risk of the development program like we're contemplating right now. So I don't know if that answers your question, but I would like to be thinking along the lines of 60% to 75% hedged, for long-term contracts.

Which would basically be --

Now I can't tell you for sure, because it changes from time to time, if we will hedge that on the NYMEX forward curve or the CIG forward curve. It is all dependent upon what we believe and our perception is for the Rocky Mountains differential aspect. Currently, the Rocky Mountain differential has shrunk to I believe currently around $0.30. And long-term contracts can be secured for numbers just in excess of that. So that would lead me to believe that we ought to consider the CIG basis differential, or basis curve, and it is something that we look to lock in, in the future. Having said that, if we do any firm commitments with volumes on specific pipelines, we have a lot of options right now of all of these new pipelines coming on, out of the Piceance basin, and new ones that are planned. We would then probably look to hedge against the NYMEX forward curve.

Now, this amount sounds like it is above and beyond what would be mandated by your lenders. Is there an estimate or a timing as to when you would start looking to do these more lengthier lock-in futures?

Well, it is going to be a little while. And it is subject to the joint venture. We need the bank-mandated hedges to roll off.

Okay.

So you really are talking about from 2011 on.

All right. Now, understanding that we can't get an estimate really of what kind of new production goes into place from your CapEx yet, because that is not out, just assuming we're at the current nonactivity and just looking at the recent historical activity, are oil and gas quantities for you, for Q2 and going forward, somewhat predictable based on certain elements of your current Q1 financials? Is there a basic formula of run-off half-life type of situation from your particular sources of oil and gas?

Well, one of the unique and appealing aspects of the Piceance Basin is these gas wells perform very predictable on type curves, and based upon our current production, of what we -- how we used to complete wells, that was very, very predictable. What we're doing now in this field with our new completion technology is far in excess of what we've seen in the past, and I can't tell you for sure what the curve shape is going to look like exactly. But having said that, it ought to behave very similar to the type curves that are well established. It would just be at a higher rate and hopefully at higher reserve figures. So I'm not trying to be elusive to your question. As far as what we are producing now, most all of the wells have been completed with owner frac technology. It is very predictable and our margin for error, if you will, is nominal.

Okay. And we could talk offline about how that works, and obviously we're new to this investment.

Sure.

Okay. You paid out a lot of money on a liability associated with the offshore litigation receipt of money that you had. You can explain the basis of that liability, who it was payable to, whom and why? Because again, we're new to the investment and want to understand all of the instances of money going out and obviously that was one we couldn't explain or understand.

Let me try to walk you through that. We paid a significant amount to the platform owners where we own the leases out there, and that was required to be paid to in essence keep the leases in place during the litigation. We also paid some royalties to a number of investors that loaned the company money, more than, what, 8 to 10 years ago, and they took an override underneath that arrangement. And those were primarily related to a couple former executive officers and a couple outside investors.

And then that liability and those payments have been fully paid off now?

They sure have, yes.

Okay. So we're done with them. One or two more questions if you don't mind. Can you explain the difference, in calculating your total shares outstanding, we look at your balance sheet and your 10-Q and I see $275 million, but in the weighted average shares outstanding, we're dealing with $282 million. So there's a decent amount in there. Are those -- do you have options given how low our stock price, do you have options and other diluted instruments that were issued while things were even lower?

No.

Just stock price.

There were no options, we haven't granted options over a number of years. The weighted average is just based on the length of -- shares issued later in the quarter would have a larger effect on the weighted average calculation.

In Q1, there was an issuance.

There was an issuance at the end of December that was material. I don't -- I'm not -- I don't recall --

I think that's when it went up to $275 million. We will go through that with Broc.

There were some grants to the directors at the beginning of Q1.

Yes, but I don't think that explains the --

Not material, no.

How do we best understand your short-term and long-term restricted deposits, and why each remains at $100 million on your balance sheet as such? What are those for?

We're required to make a $100 million payment relating to an acquisition that we did with EnCana, and each November 1, we're required to pay $100 million. So as we make that payment in November, you will float from a long-term liability to a short-term liability. So the total obligation is still $200 million, of which $100 million is due November 1, 2010, and the remaining payment is due on November 1, 2011.

And a four-year term on it, and it is about halfway through.

Okay.

Approaching the third year.

And lastly, and I appreciate that you -- two questions. You're limited in what you can say, but you did say that the process on the big sale here is going well. Can you at least explain why you feel and say that the process is going well?

No, at this point in time, and you have to appreciate, Andrew, our sensitivity until this thing is closed, but we really think it is prudent that we not comment at all.

All right. I mean because you had put the little spin on it that it was positive, so I was trying to get support for that.

Yes.

And lastly, this big transaction is part of the strategic alternatives process. And you had mentioned a new facility, the debt facility, would be resolved after the joint venture deal was resolved. And that's understandable. But there are costs that are associated with the strategic alternatives process. Other than this joint venture there, and the refinancings, there are other things the alternatives process is looking to do. You have other assets. Do you have a handle or an estimate as to milestones and the timing of the conclusion of the strategic alternatives process and its costs, as well as when other items get presented to the board? For example, when does the board next meet or when is the next strategic alternatives process presentation?

Andrew, this is Dan Taylor. As we already commented, we can't go further into the strategic alternative process. Obviously, it continues to move forward. And you know, we are looking to get successfully to a close. But in terms of timing and specifics, we cannot comment further.

Fair enough. Thank you very much. That's all.

(Operator Instructions) We will pause momentarily to assemble our roster. Our next question will come from Brett Brody from JPMorgan. Please go ahead.

Hi, guys. It is actually Gregg Brody. Just one question for you. On the revolver, the recent termination at the end of the quarter, what is driving that? Is that the process of the strategic review? Or is there something else there?

No, that is pretty much it. They obviously want to look at our facility post the joint venture with Opon and just want another look at it at that time.

Okay. And then just one question, operationally, just from your -- from the rate business, and just in general, what are you seeing in terms of drilling costs, in terms of price pressures, across the different aspects of drilling?

Well, in the Vega area, because we're not really -- we don't fully understand that, but having said that, the Rockies in general are not seeing the increase in drilling activity that some of the other shale places have seen, and I think there has been a further reduction in third-party service costs in the last six to nine months. I don't think it as is meaningful as we saw in 2009, but I think if you're asking, are we expecting well costs to increase, the answer is no. We expect, because there is -- the shale plays are generally requiring specific types of drilling rigs, and specific types of third-party services, those that are remaining in the Rockies are basically pretty hungry looking for work. So we think that it is a good environment for drilling. Having said that, we're not monitoring other parts of the -- of our asset base because that is the only focus that we have right now, is drilling and developing the Vega assets.

And does the DHS -- you said you were up to 10 rigs, are you on the verge of selling any more rigs there or are you relocating any?

We will be up to 10 by July 1, is what I said. We've had a pretty good run here in the last couple of weeks on getting some things under contract. We continue to look at selling a number of our rigs to pay down our debt, but really we haven't been able to be very successful in that yet.

Okay. Thanks for the time, guys.

Operator, do you have more questions?

Yes, we do. Our next question will come from Kevin Templeton from Jefferies. Please go ahead.

Hi, it is actually Evan Templeton.

Just curious, just looking through capital expenditures for the period, it was about $10 million on oil and gas properties. It sounds as if your actual completion activity was pretty limited, so can you give me a breakdown of where that spending was allocated?

Well, we had roughly a third of that in the Garden Gulch deal which is operated by Berry in the Piceance Basin. Very similar to Vega in its makeup. And then about a third of it was spent on the completions, and then about another third of it was spent in infrastructure costs in the Vega area, in preparation for the joint venture.

Okay. And also, based on current pricing, what sort of returns are you seeing out of those Vega wells that you drilled? What are you anticipating?

Well, you mean flat price basis?

Yes.

I mean strip going forward --

Actually both, if you have a comment on both, that would be helpful.

I could just have a generic comment, but I can tell you that it is not as price sensitive as you might think, given that the Rocky Mountains differential has decreased so far. But having said that, $4 NYMEX or $3.75 CIG is profitable but relatively tough. But we can make money at it. The forward curve and the forward CIG curve has fairly robust economics over time. And because of our new contract renegotiation and now we have a large portion of our liquids that we retain out of our marketing contract in the Vega area, that has significantly increased our profitability and actually we have seen -- we have seen revenues that equate to the CIG curve, for all-in costs. So the forward curve looks great. Current prices are fair.

Okay. And it sounds as if you're being helped by then additional liquids --

-- it is extremely profitable for us right now.

Great. Thank you.

This concludes today's question-and-answer session. I would like to turn the conference back over to management for any closing remarks.

I thank you guys for listening in on the call. Obviously, we are hopeful that we will have more meaningful news concerning the joint venture process in the near future. And hopefully at some point in the future we will be able to comment more on the completion activity and the results therefrom in our Vega completions in the future. So thanks for joining us. And have a good day.

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