Par Pacific Holdings Inc (PARR) 2007 Q3 法說會逐字稿

Good day ladies and gentlemen. and welcome to the third quarter 2007 Delta Petroleum earnings conference call. I will be your facilitator for today's call. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded for replay purposes. This conference call will include projections and other forward-looking statements within the meaning of the federal securities laws and are intended to be covered by the safe harbors created thereby.

Any such projections or statements reflect Delta Petroleum's current views about future events and operating and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected included, without limitation, the volatility in commodity prices for oil and natural gas, including basis differentials and product pricing among different producing regions, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, unsuccessful exploratory drilling activities, lack of exploration, success competition, government regulation or other action, the ability of Management to execute its plans to meet its goals and other risks inherent in Delta Petroleum's business that are detailed in its Securities & Exchange Commission filings.

Delta Petroleum is under no obligation and expressly disclaims any such obligation to update or alter its forward-looking statements whether as a result of new information, future events or otherwise. Cautionary note to U.S. investors, the U.S. Securities & Exchange Commission permits oil and gas companies in their filings with the SEC to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally produceable under existing economic and operating conditions. We may use certain terms in this conference call that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the oil and gas disclosures in our form 10-K for the year ended December 31st, 2006, as updated by our subsequent periodic and current reports on forms 10-Q and 8-K respectively.

I would now like it to turn the call over to Mr. Roger Parker, Chairman and CEO. Please proceed, sir.

Good morning. This is Roger Parker. I am not sure that we have time for the rest of the call after the forward-looking statements. Actually, thank you for joining us for our third quarter 2007 earnings discussion. As you can see, we continue to make very good progress in production growth and operational efficiencies. We came in at the upper end of production guidance and would have exceeded guidance if gas volumes produced in the month of September in the Rocky Mountain region were the same as gas volumes produced in the month of August for the same area. As you have undoubtedly heard from numerous other companies, pipeline constraints on major trunk lines in the Rockies caused involuntary production restrictions for most producers in this area in the month of September, and we were no exception. We still experienced 44% growth in production year-over-year and 9% growth over the second quarter.

We have also guided to an additional 8 to 12% growth for fourth quarter of 2007 over third quarter numbers and 40 to 60% growth for 2008. So we're now achieving more consistent and predictable growth as we go forward. As a result, revenue and cash flow are also increasing. Revenue was up 22% year-over-year to $51.9 million, and discretionary cash flow is up 34% year-over-year to $20.4 million. In addition, hedging activities against the CIG differential allowed to us realize almost $6 million in revenue for the quarter, which increased total revenue by 12%. We are currently hedged at higher prices for the fourth quarter of 2007 and for 2008 as it relates to Rocky Mountain gas production and the CIG differential. Although we reported a loss of $6.4 million for the quarter, two items in particular make up more than the total loss. These items are $4.7 million in exploration expense, which is seismic activity related to our projects in Utah, Wyoming and Texas. In the second quarter exploration expense was only approximately $750,000, and fourth quarter should be $3 million to $3.5 million lower so the third quarter expense was really a timing issue, and therefore anomalous. The other item is a $3.9 million equity compensation expense which was non-cash. The combination of revenue and production growth and decreasing per-unit expenses allow to us expect a return to profitability as we enter 2008.

With regard to our important projects, I will first highlight the Piance Basin. As we have mentioned before, we're achieving real gains in drill time and frac efficiencies which translates to lower well costs and better initial production performance. As an example, the average number of days to drill wells in the Piance Basin area has gone from 18 days early in the year to approximately 12 days for the most recent wells drilled. In addition, per-well reserve recoveries are expected to increase as we have begun to drill the north Vega acreage, which has somewhat thicker gas column than wells drilled in the Vega unit. Average well recoveries are approximately 1.2 Bcf in the Vega unit wells, and north Vega wells are expected to be closer to 1.5 Bcf per well. As importantly, there are a couple of additional pipeline projects that are in process for increased capacity out of this immediate area. And the expectation is that there will be additional availability in the first quarter of 2008 and a total of approximately 450 million a day of available pipeline capacity when the projects are complete in late 2008 to early 2009.

On properties currently owned by Delta, we expect to achieve gross daily rates of 150 to 200 million cubic feet of gas per day out of this area within the next couple of years. We would also note that similar positive results are being achieved at the non-operated Garden Gulch field also in the Piance Basin. Moving to the Paradox Basin, specifically our Greentown project, there has been incorrect rumor that our recently drilled federal 35-12 well was plugged and abandoned as a dry hole. This is not the case. In fact, we successfully contained a potentially unsafe situation and will drill the well deeper to its primary objective formations at a later date when conditions allow. In the meantime, we have moved the rig to another location, the federal 36-24 and are drilling that well with the expectation that it will be at total depth within 30 days. We are also drilling the federal 28-11, which is near our federal 32-42 discovery well and anticipate being at total depth within two weeks. This play remains very exciting and holds tremendous potential, and we expect to have additional public comment around the end of this month.

In our Utah hinge line play we have spud the federal 23-44 on our para 1 prospect in the second week of October. This well should be through the first primary objective in about two weeks and at total depth by mid to late December. Onto the Columbia River Basin project. Contrary to a recent incorrect publication, Delta has not yet drilled any wells in the basin, but we're currently working toward that goal. In addition to the discussion in our press release this morning, we have a new slide on our website, which is the last page of our investor presentation materials that identifies the depths achieved and the formations encountered by the EnCana wells drilled over the past couple of years and the Shell wells drilled 25 years ago. In short, the play concept has not been adequately tested, and additional drilling is warranted given past results and continuing expectations for large potential recoveries. We are currently working with other industry companies to participate in the drilling of our Bronco prospect. We are hopeful that we will be in a position to spud the grade 33-23 well in the first part of 2008. In an effort to get to the Q&A session, I have not addressed other areas of activity, but we will do so during the Q&A. With that, let's go ahead and turn it over.

(OPERATOR INSTRUCTIONS) Our first question comes from the line of David Tameron with Wachovia Securities. Please proceed.

Thank you. Good morning.

Good morning, David.

Question for you. You mentioned it briefly in the Piance Basin you're saying, so you have 1.2, you have a mix of 1.2 to 1.5 EURs going forward.

1.2 to 1.5, yes. In fact, most of what we will drill going forward will be on the higher end of that because most of the drilling activity upcoming is going to be north of the area that we're -- where we've experienced the 1.2 Bcf type of average recovery.

Okay. What are wells running now with the reduced drilling days?

I am sorry?

What's the well cost running?

Well cost. I am going to let Carl Lakey our Senior VP of Operations answer that question.

We're down 38% from a year ago 2006 average to the current quarter's actuals.

Okay.

And 18% quarter on quarter from the last quarter to the current quarter, and we're going to see some diminishing returns as we go forward. We're not there yet. We expect further savings from where we are today.

I think in terms of absolute numbers, we've we've been at approximately $2 million per well recently, and it is our expectation as we go into 2008, we'll be able to bring that down to an average of $1.8 million per well.

Okay. Fair enough. And then two other questions. Wind River, you said you kind of evaluated and drilled another well or two perhaps. Can you talk a little bit about that?

Yes, we've -- what we're doing there is we're drilling three wells that are spaced approximately three miles apart from each other. We have drilled one well to total depth, recently run production casing, experienced very good shows while drilling. The second well is currently being drilled, and then the third well will be drilled immediately behind that. We expect to have results from -- completion results from all three of those wells beginning around the end of of the year, and the results of those wells will go a long way toward determining what a 2008 drilling program would look like in that area.

All right. Okay. Good. And then so few months off?

Probably -- yes, probably year end for more information on the Howard Ranch.

Okay. Last question and I will let somebody else take Wind River Basin, but regarding the article I think you alluded to, or you did allude to, could you talk a little bit about financing for '08, any guidance on CapEx, just give us a snapshot of where you guys see things over the next twelve months?

Yes. We expect that we will be at approximately the upper end of the numbers that we have reguided to for 2007. And then in that same press release, we had indicated that 2008 would be flat to 2007, and we do expect that at this point. What I would say in a general comment related to that is we have a much greater percentage of the CapEx related to low risk developmental drilling activity in 2008, which gives us the expectation of very predictable production growth and therefore cash flow growth and in addition to that the probability of borrowing base growth. As we sit today, we are very comfortable that with anticipated cash flows and availabilities under our credit facility, we will be able to fully accommodate our 2008 drilling CapEx program.

That's good. Thanks. Thanks for the color.

You bet.

You our next question comes from the line of Larry Busnardo with Tristone Capital. Please proceed.

Good morning, Roger.

Good morning, Larry.

Hey, I guess on the Paradox based on the federal 35-12 well, can you talk a little bit about what you've seen so far in that well? Obviously you had the high pressure, but then what -- how do you think that translates into when you get back on that location and you end up deepening the well?

Larry, this is John. On the 35-12 well, this was a shallow interval, and obviously the press release I think clearly states what we found in the shallow interval, to kind of restate our belief in the Greentown area and the Greentown structure, the predominantly -- the most significant intervals of interest are deeper than this particular interval. This interval does not affect our belief in the ultimate producibility of these lower intervals, and we really believe that nothing that we found in the 35-12 makes us believe that this won't be ultimately a fairly large field.

In regards to the previous two wells, what kind of pressure was encountered in those wells when you went through the zone, and what leads you to believe what you found here is more compartmentalized, as you said in the release?

That's a good question. There is ten wells in the area, and some of the older wells we don't have pressure information. At least our two wells had very similar pressure gradient in that first interval of about 0.7 BSI per foot. What we did find in both of our wells is, more importantly in the 36-11, was significant hydrocarbons were flowing from those intervals and effectively no water. The 1.1 pressure gradient is abnormally high. In fact, it is hard pressed to find a pressure gradient that high anywhere in the Rocky Mountains, so we believe it is compartmentalized. None of the other wells in the area have a similar characteristic, being either water bearing or pressure graded to 1.1, so that's why we feel this is really an a anomalous event and we don't expect to see that going forward.

Which zone is this?

The very first interval in the salt section at about 5,100 feet.

What's the name of it?

We haven't really named it. It is just the first interval.

Larry, this is Roger. I would also interject there that when we ran intermediate casing in that well and moved the rig over, we moved it a mile to the east. If we had significant concern that this was not come compartmentalized, we would have moved further away.

What's being done to bleed off the pressure? I think you said here that it's producing out, is it gas being flared, is it gas water, or combination?

Larry, right now we're reviewing the exact procedure because this is high pressure, and we to want make sure we're in a safe environment, but ultimately we will set up a series of frac tanks or storage tanks to be able to handle the water. So we're not currently producing or bleeding off the pressure at this point, but we are coming up with a design which we plan to do in the near future.

Do you think you get back on this location fairly soon after maybe one of the current wells are drilling or do you think it is farther off than that?

Hopeful, but again we need to really satisfy ours we're able to decrease the pressure, so the timing of when we get back on the 35-12 is unknown at this time.

Larry, I would say most most importantly we will be in a pattern of getting continuing results. We are drilling two wells in the Paradox, Greentown project right now, and we will get results from those wells and continue with additional wells thereafter, whether it is the 35-12 or others.

Okay. Can you give us an update on the pipeline? I think last check you were looking at spring time. Is that still on track?

Yes. We conducted all the NEPA work necessary which is the time-consuming environmental work necessary to write environmental assessment. It is in the hands of the BLM. We're hopeful that a permit might be issued later this year or early '08. Construction phase once the permit is issued, is expected to take four to five months, so I think we're in line with what our previous projections have been.

Okay.

End of the second quarter.

Okay. Just one more quick one. Over in the Vega unit and looking at the pipeline there, can you just give me an update on where that stands, the current take-away capacity, what the upgrade is going to be and bring on in capacity early next year, and then where that will lead you in terms of where production could go from current levels to the first part of next year?

It will take us -- that pipeline capacity -- this is Carl Lakey talking -- will raise us up to about 60 million take away for Delta Petroleum and that's expected to stream in the first quarter.

What's the current take away capacity?

Right at 42 to 45, what we've got available.

Okay. Of the 40 to 45 million a day that you think you'll be at by year end, is that actual production or I guess you'd max out the pipeline that point, correct?

We would maximum out our own compression capabilities at that point in time, so, yes, we will be capped at those levels until sometime in the first quarter when the pipe will be expand to do the 60 million a day number that Carl was referring to.

Thanks for the update, guys.

You bet. Thanks, Larry.

Our next question comes from the line of Eric Kalamaras with Wachovia. Please proceed.

Hi. Good afternoon. Question regarding -- you spent a lot of capital in the past couple years, at least on the exploration side and the development side as well, and just curious if projects in Columbia River just don't go as planned or any of the higher risk projects, would you consider monetizing some of the capital that you've already spent in terms of acreage at the tail end of '08 or '09?

Well, I think it is too early to tell exactly that. What I would say is that one of the things that you can see that we're doing at the moment is discussing with other industry participants the idea of jointly drilling in the Columbia River Basin and that is likely to be something that we will focus ongoing forward. With regard to our other areas of exploration, specifically the Utah overthrust play and the Paradox Basin area, we're very comfortable with what we're experiencing in the Paradox Basin. In the Utah overthrust play we will likely make decisions after the next two wells have been drilled as to how to go forward with that project area. If we don't have success in the near term, I think that probably does lend itself to the idea that it would be a good time to talk to other industry participants about joining.

Can you refresh me on what is the cost on well in the overthrust?

Well, if we go to total depth of 14,000 feet, it is going to be approximately $5 million.

Okay. And in that context, related to the balance sheet, how do you think about that going forward into '08? You've got certainty more than enough liquidity to handle these all the way through '08. How do you think about the balance sheet going forward?

I think that, as you point out, we're very comfortable with 2008. And then exploration results are going to have a big impact on decisions from -- for future years. I will also say that we have every expectation, and rightfully so, that if you have exploration success on some of these things, you're going to be talking about a significantly different looking company.

Absolutely. Okay. Thank you.

You bet.

Our next question comes from the line of Brian Kuzma with JPMorgan. Please proceed.

Hey, guys. Good morning.

Good morning.

Could you talk a little bit more on the Piance Basin and like how many wells do you guys have awaiting on completion, and how many wells you'll have waiting on completion for when that pipeline comes online in '08?

Well, what I would steer you to is the -- what we put in the press release, which is the expectation that we'll have approximately 60 wells completed and producing by year end. Under our current CapEx program for 2008, we expect to drill between 125 and 150 wells in 2008, and we'll be in a situation where you have wells being completed on a fairly consistent basis throughout the year. I will note, though, that once we achieve the 60 million a day levels that we had discussed earlier, we will be -- production will essentially be capped at that for the middle part of 2008 while these pipeline projects are going through their construction phase.

And what do you think the timing will be like on this pipeline expansion?

Well, the expectation is that the significant additional pipeline capacities will be available and operational by year end 2008. We are not planning on having additional capacity until the end of the year. I think there is some hope that it could be before the end of the year, but the end of the year is a safe bet.

Okay. And then back over at Greentown, are you talking about the compartmentalization of this high pressure region, what are the implications for the -- for saying that some of these zones are continuous across the Greentown prospect, which I think was -- is part of the reason why you guys were so encouraged by it?

Well, I still believe that. These classic intervals are -- well, I would say that based upon the wells that we've drilled and the wells in the area, we can map these particular classic intervals over a fairly large area. The one thing that we will want know until we have further developed the field is the degree of fracture or faulting in this particular field. I will suggest to you that the 35-12 has three wells north -- excuse me, not north, south, east and west within a mile to two miles of the 35-12 that none of those demonstrate the degree of overpressuring. The zone is there. It is just not overpressured. In fact, in those other three wells -- excuse me, those other three wells it appeared to be hydrocarbon bearing, so while I think the intervals extend over a large area, as evidenced by the well control, the pressure regimes appears to be localized to the 35-12, so I don't know if I answered your question, but the intervals extend over a larger area, the pressure is just different in this one particular section.

So even though the interval extends, we don't think they're necessarily pressure continuous, they're not --

Exactly.

Do you think that they're not actually continuous formations or are there is some stratographic barrier?

No, I think they're continuous formations. I do. I think it is just a unique situation in this one upper zone in the 35-12. I will tell that you that based upon our two wells drilled to date, and again those wells are just under seven miles apart from one another, the pressure regime in individual intervals was very consistent across that seven-mile region. And while the pressure varied dramatically from one interval to the next, it was very, very similar to that same interval in a well seven miles away, so that's why I believe what's happening at 35-12 is so localized.

You think it is primarily isolated to this top interval at least for now?

I do.

And then when you're designing wells going forward out here, is there a way that you guys can just come up with a super robust design that -- to drill these wells regardless of pressure and regardless with super thick casing or sandwiched casing, concentric casing design? I mean like how much do you think it would cost to drill a fool-proof well out there?

Let me -- Carl has been working on this for months, so let me let Carl answer that question.

Okay.

I think the first part of the answer is we do have a robust design and why we're successfully able to contain the pressures. I don't think that should be underestimated. The second part of the answer is, the safe way -- if we are not able to deplete the interval, the safe way to progress the well deeper is to set pipe across it, and we can do that. The reason we didn't do it while we were on the well is because we would have had to compromise the casing design that we had to be able to withstand the collapse forces in the salts as we go deeper. That was an unacceptable trade-off at the moment, so we're designing an alternate design that will give us one more casing string of flexibility in this thing to be able to progress the well deeper.

Okay. So you just --

-- collapse forces that we're designing versus what we originally drilled.

That's fair. I think in the first few wells the pipe that we ran had roughly 7,000 PSI collapse resistance. What we're intending to run is roughly 13,000 PSI of collapse resistance with the ability to run a smaller concentric string and further strengthen the primary long string. So that concentric string as we did research at other salt provinces around the world and in the Rockies we've never found an example where that design has failed. We think the 13,000 PSI long string will be sufficient. We will have the ability to strengthen that further, and that was what we were afraid we would have to give up if we had to set pipe across this top interval at that moment.

Okay. Because like if you had to try to do both, set an additional intermediate casing and be set up to run that dual casing down below, then it just becomes absurdly expensive or --

We were faced with the prospect where we sat of choosing one or the other, and that wasn't the choice we wanted. We really wanted to be able to do both.

Again, Brian, this is John again. This really is a localized event. There is ten wells out here. None of them have this degree of overpressuring, so we really don't think that we need to allow going forward to continually have to deal with this upper zone with sacrifices in our casing design.

Okay. So you guys are not going to plan for running into this similar type pressure interval going forward?

I think our design that we've got sea satisfactorily plans for what we see and I don't think -- back to your point on costs, I don't think that's going to be a material concern either.

Okay. So what would the AFE look like for the design you guys are running right now?

About $3.5 million per well.

Okay. That's it for me, guys. Thanks.

Thanks.

Our next question comes from the line of Michael Bodino with Coker & Palmer. Please proceed.

Good morning, guys. I had a couple questions. Actually, have a question -- couple questions for Carl Lakey on the Piance Basin. Carl, could you comment a little bit on what's going on with the initial production rates since you all have changed the frac design a little bit? Looks like the initial recoveries are a little bit better.

That's correct. We've spent a lot of time modeling frac and fine tuning our hydraulic fracturing procedures. The fracs are certainly bigger than they have been in the past. We're also more selective in what we choose as pay, and what we complete. So yes, we're very pleased. We made gains in really all the material areas. We're improving on costs, and we're improving on productivities at the same time, and also on speed. We're getting them on faster.

Is the initial production rate materially higher than it was previously?

Yes.

Can you quantify?

Roughly, from the original first generation wells at Vega -- and I am talking about it at about a 30-day interval after the wells have stabilized and had gotten off their first transient piece, we're well over 40% higher than where they were in the first generation at that 30-day point.

Okay. And question, would the new frac design, is the new frac design that's generating higher ultimate recoveries or are you getting better recoveries or are you getting more access to more reservoir in terms of aerial extent or all of the above?

I think the short answer is really all of the above.

Okay. And question on the -- not to belabor the Paradox Basin but one other question is, are you planning on drilling any wells outside of the Greentown area this year interesting into next year and what's the timing and status of that?

Right now we're just focusing on the Greentown area, Michael. This is John.

As we move into 2008, we are planning on trying to get a well drilled in the Gypsum Valley prospect also. That is something that we've been working on but do not yet have permits for.

Okay. Well, I am going to let somebody else get on, and I will follow up later with other questions.

Thanks.

Thanks, Michael.

Our next question comes from the line of Ron Sanchez with Spencer Edwards. Please proceed.

Yes, gentlemen, I was just wondering in regarding the Midway, I know that first well you brought in there was kind of the Austin chalk, was a very good well. I think it was about 20 million cubic feet or 2,400 barrels a day. I just wonder, what is the production from that well now? How much has it fallen off and do you have any comments about the current well and how many more wells you plan to drill there?

We have -- with regard to current activity, we have two wells drilling as we speak. I think the expectation is both of those wells will be on this quarter. We are trying to determine and have not made a determination yet as to what our 2008 drilling program will be in the chalk. The best Kennison well, I think maybe the best way to answer your question about what is the well making today, I think most importantly, the things to point out about these large initial production volume wells is they are also very economic. We have a couple of wells, the best Kennison well and the Simmons well, that are going to make an average of about 12 Bcf equivalent we per well, and when you look at even high drill costs of approximately $10 million per well, your economics are extremely good. The best Kennison well has been producing now for almost two years and I think is still producing at meaningful daily rates on the order of 2.5 million cubic feet of gas and a couple hundred barrels of condensate per day.

Okay. Are you still on the next two wells or are you expecting both to be horizontal wells as well?

They are horizontal, yes.

And you can't say, thus far you haven't encountered anything that you can -- like they'll be successful?

Yes. We are -- they're located in very close proximity to other good wells, so our expectation is they will be good wells and that they will both on at some point during this quarter.

Okay. Thank you, sir.

Uh-huh.

Our next question comes from the line of John Freeman with Raymond James. Please proceed.

Good afternoon, guys.

Good morning, John.

First question on the 2008 production guidance next year. How much of that guidance includes contributions from areas outside of the Piance Basin.

Not a whole lot.

So Wind River, DJ Basin, Paradox, it's minimal, like at a 40 to 60% is it 40 -- is it 60% if you get a contribution from Wind River and 40 if you don't? In terms of magnitude, can you kind of clarify a little?

Virtually all of the production gains anticipated for 2008 in our production guidance are coming from the Piance Basin.

Okay. And next year will you have at least one rig in Wind River?

Well, as we mentioned earlier in the call, the results of these three wells that we're drilling right at the moment are going to determine what our drilling program will be in the Howard Ranch area next year. I think the best way to put it, John, is to say that we've experienced very good shows in the first well while drilling and we're very hopeful that the next two are going to exhibit the similar -- are going to exhibit similar type of situations, and then that would put us in a position of being able to have a more continuous program next year if that's what we experience.

Okay. Thanks. Just one other question on the Vega unit, what's the split in acreage between Vega and North Vega?

In terms of net acres?

Yes.

Net acres in Vega is approximately 4,000. Net acres in north Vega is approximately 6,000.

Great. That's all I had. Thanks.

You bet, John. Thanks.

This concludes our question-and-answer session. I would now like to turn the call back over to Roger Parker, Chairman and CEO for closing remarks.

Thank you for joining us for our third quarter call. We'll have other information to relay soon, probably by the end of this month. Thank you.

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Good day.