Par Pacific Holdings Inc (PARR) 2008 Q3 法說會逐字稿

Hello and welcome to the Delta Petroleum third quarter earnings conference and webcast. All participants will be in a listen-only mode. There will be an opportunity for you to ask questions at the end of today's presentation. An operator will give instructions on how to ask your questions at that time. (OPERATOR INSTRUCTIONS). Please note, this call is being recorded.

Now I would like to turn the call over to Broc Richardson. Sir, you may begin.

Thank you. Good morning and thank you for joining us today on the call. On the conference call from Delta are Roger Parker , the Chairman and CEO, John Wallace, President and COO; Kevin Nanke, Treasurer and CFO, Ted Freedman, Executive Vice President and General Counsel, and Carl Lakey, Senior Vice President of Operations.

Before we begin, I need to read the forward-looking statement disclosure. This conference call will include projections and other forward-looking statements within the meaning of the Federal Securities Laws and are intended to be covered by the Safe Harbors credited there by. 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 true reserves that the Company has demonstrated by actual production or concludes their formation test to be economically and legally produceable 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, 2007 as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

With that, I will turn the conference call over to Mr. Roger Parker.

Thank you, Broc. And thank you for joining us for our third quarter conference call. As you have heard from many companies, especially energy companies, the significant and rapid decline in oil and gas prices have caused us to act in expeditious manner to be fiscally responsible and ensure that Delta Petroleum is situated to weather the current environment in the financial markets. With revenue streams cut in half over a 60 day period and credit markets being all but closed, immediate and definitive action was necessary and important. This has had an impact on drilling activity in all but our lowest risk and most predictable areas which are basically located in the Piceance Basin. It is not a reflection of the potential of areas like the Paradox Basin, rather, it is an acknowledgement that this Company will do everything possible to maintain adequate liquidity and to evidence real value of assets for our shareholders. In fact, I would like to note and emphasize many of the very important metrics that have been achieved and here to fore used to be the value drivers for an E&P company prior to the worldwide fallout of the financial markets.

Number one, we reported that unaudited proven reserve estimates at September 30, 2008 were 657 Bcf equivalent which represent as 75% increase over year-end 2007. Secondly, we reference that we experienced a 64% increase in quarter-over-quarter production growth. Number 3, EBITDAX increased 98% to approximately $43 million for the quarter. These represent what we are supposed to be doing and have been able to accomplish and the growth should not be ignored because ultimately it will matter again.

In addition, announcements were made last week which are supportive of value growth and should be interpreted and should excuse me should not be interpreted as [tantamount] to survivor moods. One the announcements we made was that our banks just this week conclude add new credit facility with a meaningful increase in the borrowing base evidencing good property valuation even in a declining commodity price environment and which is also suggestive of good liquidity. We also announced an effort to explore joint venture alternatives for our Piceance Basin assets. This is intended to be a value unlock as it relates to current company valuations along with prudent balance sheet management. We will only transact or it is the intention of the Company that we will only transact on a NAV positive basis.

With that, I am going to turn it over to Kevin Nanke, the Chief Financial Officer to reference a few of the financial metrics for the quarter and then we will have question and answers.

Thank you, Roger. Net income for the quarter was 49.8 million or $0.48 per diluted share compared to a net loss of 5 million or an $0.08 loss per diluted share in the third quarter of '07. Oil and gas sales from continuing operations were 49 million compared to 23.1 million in the third quarter of 2007. Continuing operations exclude our midway loop, Texas asset which is held-for-sale and generated over 9 million of cash flow in the quarter. We had realized oil prices during the quarter of $107.76 and realized gas prices of $5.97 an increase of 53% and 67% for the third quarter-- from the third quarter of '07 respectively.

Our net income was materially impacted by a 54.8 million unrealized gain on derivative instruments relating the significant decline of oil and gas prices at the end of the quarter, an 11.3 million realized gain on derivative instruments from the sale of certain derivative contracts on September 30, and $8.1 million in dry hold expense during the quarter. Total production for the quarter was 6.6 Bcfe, an increase of 44% compared to the third quarter of '07, which is at the upper end of our guidance. Additionally, we estimate 0.22 Bcfe in production was lost attributable to Hurricanes Ike and Gustav. Lease operating expense from continuing operations per Mcfe for the three months ended September 30, decreased to $1.26 per annum from $1.56 per annum in the third quarter of '07. The average LOE per Mcfe decreased due to a shift in production from higher cost, Gulf Coast properties to lower cost Rockies properties. The depletion rate also decreased to $4.28 per Mcfe for the three months from $4.35 per annum, in the early year period. This decrease reflects increased reserve additions and lower cost per well in the Piceance Basin Capital Development program along with the higher mix of production from Rocky Mountain properties. With that I will turn it back over to Roger.

Thank you, Kevin. Operator, we will open the call up to question and answers at this time. Thank you.

(OPERATOR INSTRUCTIONS). Our first question is from Tom Gardner from Simmons and company. Please go ahead.

Morning, guys. Concerning the capital spending, can you give us an idea of what it was for Q3 and full year '08 and perhaps an idea of what your growth guidance might be given the reduction insist '09.

Third quarter was what, Kevin?

120 drilling.

120, yes. Fourth quarter, is expected to reduce by approximately 25%.

Yes.

Many of the Tom, many the implemented drilling reductions were initiated in early October and obviously wells being drilled were being drilled to total depth before rig release. So half of the drilling rigs for half of the quarter will be released. With regard to I think, the other part of your question was, growth number in 2009, is that correct?

Yes.

Growth for 2009, currently we are expecting that we will experience production growth based on the CapEx guidance we put out that will range from 10 to 15% growth over 2008 levels.

Got it. Is there any incremental information on the tender offer being reviewed by the Board?

Not at this time. Although, the Board is in the process of reacting and there will be more information coming soon.

I think that takes me to my two. I will get back in the queue.

Okay. Thank you, Tom.

You bet.

The next question is from Joe Magner of Tristone Capital.

Good morning, can you explain the unwinding of your hedges to what could be a pricing in the Rockies next year.

Absolutely. Let me tell you we considered that for a number of reasons. I will take you back to the point in time in which we unwound those and unwinding those on September 30, the day of September 30, and continued over the course of the next couple of weeks. One of the concerns was for the unknowns related to everything that was going on with all of the banks in the markets. And having an unwillingness to try and determine whether or not there would be counter party risk once the hedges ultimately came into play. That was not the only reason. But the other reasons were, we were in a position to where we were able to experience the significant cash gain related to that effort. We booked approximately $20.5 million of cash gain by doing so.

And then lastly, we were paying very close attention to what had become significant number of large capital expenditure reductions that had been announced by numerous companies related to significantly declining oil and gas prices. We were and still are of the opinion that with the significant number of rigs that are being released at this point in time and continue to be released over the next three to six months that there will be an impact on supply ultimately that will be, begin to be realized probably in the 2009 time period and we think we will have the affect of having to stabilize especially natural gas prices a little bit better as a result. So, the available capital today, the concern for wanting to make sure there didn't need to be a concern for any sort of counter party risk. And also, the belief that prices will likely at least stabilize if not get a little bit better with supply disruptions, ultimately led to the decisions to do what we did.

Okay. Looks like the Haynesville position is growing. Plan to spud a rig or well soon, and just talk about your plans for '09, what the lease terms would look like on the new acreage and what percentage of the CapEx could be allocated to that effort.

Yes, if you look at the press release, what we announced is we will spud an initial well in early 2009. The plans in time are literally to drill a single well and get a single well result before making any further capital decisions related to the Haynesville, and we do believe that we put together a very good acreage position in the better parts of the play. We were very cautious as we went into leasehold acquisition. And did not rush into large and expensive acquisitions when everything was moving as quickly as it was in the April through July time frame. And the end result is that we have a very good across the board average per acre cost for the play and it is our intention that we believe that if we are patient on a go forward basis and obtain an additional acreage at very reasonable prices and the immediate intent is to drill a well. And get a result and then make further decisions based on that.

Last part of my question in terms of the lease terms. What sort of requirements do you have in drilling commitments?

We only have one drilling requirement forthcoming and that is, that will be taking care of with the well we spud in 2009. Other than that, we have lease terms that are on the order of three to five years for the remaining leasehold.

It is worth noting that the leasehold we are talking about is HBP.

Thank you.

Our next question is from David Heikkinen with Tudor, Pickering, Holt & Co. Securities.

Good morning, a question as you think about Greentown and the expected 2 Bcf for the well and remind me what you spend on the well?

Well, I think David, the better way to answer that is to tell you what we spent on the most recently drilled well. Because clearly, we have been in a process of doing a lot of work on lot of different wells in a lot of different ways and most representative expectation would be based on the Federal 11-24 that we just drilled. I will let Carl Lakey make a few comments in that regard.

Drill well cost at Suspended Point with casing included was $4.5 million and completed well cost to be $5.5 on that one, once we completed all the available plastics within the well. We think there is room to be able to work that downward. Perhaps another $500,000. Another 10%.

David, this is John. Let me throw in here as part of this fiscal restraint and not drilling in Greentown area. We are focusing our efforts on the completion activities from these classic intervals up hole. They are meaningful, we tested them in both of the first two initial wells and had rates of 1.5 million a day 600 barrels of oil from some of upper zones. Addition wells drilled in the area several years ago had drill stem test rates as high as 5.5 million a day. We know they are hydrocarbon bearing. We will take the time and effort while we have some time, and focus our efforts on (inaudible) them and comingle production what we think will be from several different intervals that would include the 28-11. And we expect to have incremental reserve from up hole classic that would add to the 2 Bcf.

You don't expect to take impairments to the well or write that one up.

Right.

As you think of the Piceance Basin program that you have, and where basis is and the extension of delays, what are you building in for basis for 2009 in the Piceance economics.

What we note and pay attention to is what you can hedge the CIG differential at. If you were to do so which we have not. And you could hedge the basis differential at approximately 220 per Mcf across the board if you are willing to do so. We do use that when we prepare budgets and come up with capital budgets for the following year and looked closely at that.

At that differential what are the rates of return on the wells.

They came in 18 to 21%.

At that differential with current NYMEX price environment you are still in the upper teams.

We are looking at firm sales going forward especially with the new pipeline and our goal is to via firm sales to insulate ourselves from the Rocky Mountain differential down the road.

All right. That's all I had, thanks.

Thanks.

The next question is from David Tameron of Wachovia.

Couple of quick questions. Kevin, can you walk us through the 150 and 175, and how you get to that number and including what deck you are using?

Well, David, this is Roger. What we are using is the effectively the current strip. And the CapEx budget will be largely related to continuing drilling operation in the Piceance Basin. With as we referenced in the press release, a continuing and fairly significant amount of expected completion activities and attempts in the Paradox Basin and by virtue of our transaction in the Columbia River Basin, the expectation that we will have ongoing drilling activity up there throughout the year. Over and above those activities, there will be one off wells drilled in a couple of different areas. Like Haynesville and In the Utah over thrust and result in individual wells in those areas will dictate whether there is additional capital allocated during the year.

If I look at asset sales, how much of that 150 to 175 is asset sales and I know asset sales picked up-- assets held-for-sale and the balance sheet picked up by 20 million.

Yes. And it ticked up by 20 million related to additional wells being drilled in the interim. And the best thing to do would be to reference the balance sheet with regard to that number at that time.

The 150, so, of the 150, 175, to clarify, 86 of that, half of that is asset sales?

That's correct.

All right. Thanks.

You bet.

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

Yes, Tom, I guess we could have kept you on.

No worries. Just one last question. Going through Huskies 10-Q and noticed they acquired 50% interest working in 844,000 acres for $100 an acre and wonder if you could comment on this.

Well, sure. It is a transaction that we previously announced that we are in a relationship that we are very excited to have. We have a large company with very substantial balance sheet that believed in the potential for the Columbia River Basin as we do. And we have a stated intention of drilling at least three wells in the Basin. One of which is the well we are on, the Gray 31-23 and I think that one of the things that we are certainly interested in trying to do is obviously establish that there is gas in the Basin and gas in economical amounts and we will be looking at all parts of the Basin, especially parts of the Basin that have been drilled and evidenced good gas flows in the past. So, it a relationship as I mentioned that we are excited about. It does not change the Delta net acre position. We as part or immediately prior to the transaction, that you are referencing, we acquired the remaining leasehold ownership of EnCana and as such, by the time we closed the other transaction we ended up with the same number of net acres that we had prior to both of those transactions.

Thank you very much.

Okay.

Next question is from John Margolis of Spectra, please go ahead.

My question was answered already. Thank you.

Okay. Thank you.

Next question is from Joe Mahner of Tristone Capital.

I wanted you to fill us in on the plans or the destination of the two or three rig that is you were running in Greentown. Were those all DHS rigs?

That's a good question. Let me make a comment on the DHS rigs. They are DHS rigs. DHS has done a very good job of finding additional work for the rigs and what is clearly a tough environment. And so at this point in time rigs released by Delta are going to work for others. And when possible, the rigs will try to go to work for other operators in as close a proximity as possible to the areas where they have been released that will allow us to maintain flexibility going forward. It is beneficial to us to have a drilling company where that we own 50% of and where we have a first time or first call on all the rigs. Specifically so that we can stop and start much quicker than other companies are able to do.

Okay. Thanks. With respect to the Haynesville plant, can you give us more on the plans there and what needs to be seen before you decide to take the well deeper.

Yes, what we have done in drilling the well to the concern depth, we encountered a drilling break at the very bottom the well. This could mean many different things. We are hopeful it means the present of the thrust fault we have been searching for and running a VSP or vertical seismic profile to image what is below the current TD and image seismically from down deep in the well boards from a picture and to show us if there is indeed a thrust fault there and it might show us what the geometry of the rocks below the thrust fault are and what age they are. It is critical for us to figure out what it looks like below us. We are encouraged that we may have found the fault and it will take us three or more days. A day to shoot the VSP and a couple to interpret it and then we'll know what it looks like below us.

Okay, thanks. Then back on the Columbia River Basin, anything whether you saw the Basalt on that?

No, we have not referenced any of that information at this stage of the game, our desire is to drill the well to total depth and make comments there after.

Thank you. One last one. Any color on the cost of the individual clastic completion that is will be done in Greentown.

Depends on the frac and the frac design. Or 200,000 per interval and each one of the wells has 15 plus intervals to look at and we will complete all 15. But all the wells had significant shows in upper intervals that we have drilled.

Okay. What is the average thickness of those classic intervals and there was earlier challenges on fracturing the wells and affects from the salt with the fluid used is there any concern of keeping them within zone.

No. One of the benefits of the salt. It is a first class Frac barrier and it is contained in the salt and with salt redeposition is related to gas expansion in the reproduction phase and being careful with how hard we pull the well and providing periodic fresh water flushes to keep the salt below the saturation point in the water we are able to mitigate the problems. We will feel like we are well positioned to hand that.

One of the problems we had in the past was collapse casing and that would be stronger pipe that is normally used for the well. But the current casing design has extremely strong or high collapse strength pipe and so far we are in and out the wells all the time and having no problems whatsoever. We have a lot more confidence in completing multiple zones and comingle that production than we once did when we were completing the initial wells in perforating several different intervals. And as far as the classics themselves. They vary in thickness. And some are thicker than the OZONE or the -- Cane Creek and some are the same in thickness. All the wells drilled have net classic intervals about a 1,000 feet in total and the OZONE makes up 70 feet of that. There are numerous intervals and a lot of classic to go.

That's all I have, thank you.

Thank you.

Our next question is from John Freeman of Raymond James.

Good afternoon.

Hey, John.

I am trying to go back in time in the Paradox Basin and see what kind of thought process. How it changed from the start. Earlier in the year, the vertical wells, the biggest issue is the decline was a lot steeper than you all anticipated and it was just mentioned a second ago, is that once the water treatment started doing the fresh water treatments, they were much better and figured out that part of the decline curve and vertical basis these wells were going to work and we ended up going to the horizontals and have had some completion issues and walk through maybe when we were originally looking at this play earlier in the year, what is changed between now and then.

Go ahead.

Talk for a minute. And then let Carl throw for a second and low in his two-cents. You are very astute in the fact that our ability now to Frac and further away from the well bore in a vertical world makes the drilling much more appealing. I will tell you if you look at this part of the world, the only known sustainable production is from the Cane Creek interval and southeast of our production. We are not developing the Cane Creek horizontally here. We had an issue with a bottom seal. With the ability to Frac long distance from the well bore and the fact that this pipe is proving to be collapse resistant, we really feel like we can target this in a multiple zone completion mentality not too dissimilar than all the other plays we chase. It is an evolution of technology. It is not an abandonment of one to the other. Carl and his group, you can walk through the Frac designs you have done. But it is an increase and ability and effectiveness of the Frac that let us believe we can do this vertically.

It is a case of comfort. The other thing as John allude to one of the things that drove us towards the horizontals in the first place was value capture from the Cane Creek interval. Which was the proto-type in the basin. As we went through the process in Cane Creek we had a problem with the bottom seal and didn't see it. With that said, we are finding the vertical completions in intervals other than the Cane Creek seem to work just fine and we are quite happy with them and continue to exploit that.

Thanks. Then, just shifting over to the Haynesville, can you give me a ballpark number of the 16,000 net acres and how much of that is in Cattle Parish,.

They are very close to Cattle Parish. Is the majority of the acreage.

Thank you.

We show foe further questions at this time. I would like to turn the conference back over to Mr. Parker for any closing remarks.

Thank you for joining us for the third quarter call.

Thank you. That does conclude today's conference. To access the digital replay for this conference you may dial 1-877-344-7529 or 1-412-317-0088 beginning at 2:00 p.m. Eastern Time today. You will be prompted to enter a conference number which which will be 424757. You will be prompted to record your name and company when joining. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.