Par Pacific Holdings Inc (PARR) 2009 Q1 法說會逐字稿

Hello and welcome to the Delta Petrol Corporation 2009 first-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 of Corporate Development and Investment Relations. Mr. Richardson, please go ahead.

Thank you, Nicky. Good morning and thank you for joining us today on the call. Joining me today from Delta Petroleum are Roger Parker, the Chairman and CEO; John Wallace, President and COO; and Kevin Nanke, the Treasurer and Chief Financial Officer.

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 thereby. In that regard you are referred to the cautionary statement displayed on Delta's website which is incorporated by reference with 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 concludes their formation test 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 the fiscal year ended December 31, 2008 as updated by subsequent periodic and current reports on forms 10-Q and 8-K respectively.

Discussions regarding the Company's public offering of common stock will be limited to the information disclosed in our press release dated May 5, 2009 and the prospectus supplement filed with the SEC. With that I'll turn the call over to Mr. Roger Parker.

Good morning, thank you for joining for our first-quarter 2009 conference call. In a general sense we have had two very tough quarters, but the good news is we have made a turn for the better and we have many positive developments to focus and build on. Since it became apparent that the swift and deep drop in commodity prices was not going to correct in a short period, it became critical to reposition the Company on many fronts.

We have transitioned from preparing for substantial increases in CapEx in mid-2008 to eliminating almost 90% of our capital activities that were still operating at the beginning of the fourth quarter 2008. It has taken a serious and concerted effort on the part of our staff, our shareholders, our bankers and our management group, but it has been done because of a common belief in the value of the underlying assets of the Company.

All involved have contributed to assist in restructuring so that intrinsic values can be realized as we persevere through what has been the toughest period. Our focus has centered on significant cost-cutting, both at the field level and in the corporate headquarters, and we are seeing the benefit as of the beginning of the second quarter.

Certain nonrecurring lease operating expenses are down, general and administrative reductions have been implemented and will continue, and capital costs in the field have fallen to levels that are driving much better and economic rates of return for new drilling even in the current commodity price environment.

The other all-important aspect of repositioning is of course addressing the liquidity condition of the Company in a manner that provides for long-term survivability and growth. Recently we have been assisted by the positive outcome of our offshore California litigation and the government is preparing payment of initial proceeds which will be approximately $60 million. We also have another judgment for approximately $91 million that we are following through with as well.

Additionally, last might we announced the common stock offering to raise $225 million. The combination of these events will fulfill all existing bank requirements, current payables and will provide meaningful liquidity for future growth. We are optimistic about the future of our Piceance Basin assets where we have over 800 Bcf equivalents in proved reserves and approximately 2.5 trillion cubic feet equivalent in total reserves.

Economics of future drilling and PV10 values have increased meaningfully by virtue of lower capital costs. We are also continuing discussions related to joint venture possibilities on many project areas that include the Paradox Basin, Utah Hingeline and Haynesville leasehold positions.

Lastly, we expect to be at total debt very soon on our Gray No. 31-23 well in the Columbia River basin. We look forward to the testing of this very important well and we are of the opinion that the surrounding area has enormous resource potential.

The future does hold great potential and we look forward to the recovery and recognition of value underlying the Company's asset base. That concludes my opening remarks. Operator, would you please turn it over to the Q&A session?

(Operator Instructions). Joe Magner, Tristone Capital.

Just had some questions. The pullback in gas prices we saw from the beginning of the year, just curious what the impact that had on your estimate of any impairments or revisions to your reserves? I noticed there weren't any taken, but I'm just curious about how that was calculated?

The pullback in pricing had an impact on the depletion rate calculation, but obviously we did not have any impairment to reserves.

Okay. Was there meaningful enough offset on the future development cost or the service side of the equation that prevented that from taking place or how was that mitigated, I guess? I'm just curious about -- I know you didn't take one in the first quarter, but what's the risk going forward if things stay where they are?

It was a combination of lower capital cost, but primarily the forward strip. The forward strip certainly allows for economical development of the reserve base.

Okay. The DHS credit facility, just curious how that is treated? I understand it's nonrecourse, but it moved up from long-term to short-term and I'm just curious what the trade-off is there going forward now that DHS is in default or tripped some of their covenants on that facility?

Joe, there's really no impact on Delta. The financials are required to be consolidated, so they were moved up. But as you point out, the credit facility is nonrecourse to the Company and the collateral for the credit facility is the rig equipment owned by DHS.

I guess right now those kind of net one another out, the value less the accumulated DD&A, and then offsetting liability on the credit facility, is that an accurate assessment?

That's an accurate statement as of the current condition, yes.

Okay. It looks like the payables' balance came down about $20 million in the quarter. What's a comfortable level for those to be at going forward or where would you have to get in order for you to get back to a current position with all your vendors and creditors?

Joe, we're planning on using approximately $70 million to $80 million to pay down current payables which would -- or payables which would leave us in a current position.

Okay. And it looked like CapEx budget -- drilling CapEx budget unchanged at $52 million, and comments that the drilling side of the equation in the first quarter was around $27 million or $28 million, but there was another $20 million or so of other costs. When you look at everything included -- infrastructure, drilling and other equipment needs -- what would your total CapEx budget for 2009 all in look like?

Well, we haven't disclosed that, but let me answer the question by saying that the run rate for the first quarter is significantly higher than what the current run rate is and that's primarily a function of shutting down existing drilling operations that continue through the end of the year.

As an example, in the Piceance Basin we did not shut down the last drilling rig until mid February. And currently one of the things we've evidenced is that the April run rate is quite a bit lower than the $52 million annual run rate. And that includes additional drilling activities at the Columbia River basin. So as we finish drilling that well and finish completing that well, the go forward run rate will allow us to bring the capital budget back into the $52 million range by year end.

Okay, I guess I'm just trying to piece together in addition to the needs to pay down the debt facility, the payables, what short of shortfall there's going to be on the CapEx side given where production is and pricing expectations. At $52 million we have quite of a bit of a shortfall factored in, so I'm just trying to get to an estimate there. But we can follow up later, if that's necessary.

The CRB well, have you provided or can you provide an estimate of the cost there? And then what is left in terms of the drilling process? And then any estimate of the time or cost of the completion?

Yes, we haven't provided any numbers related to the total cost of the well. Suffice to say that going forward it is the opinion of the partners in the well that future wells can be drilled in significantly less time, knocking off easily 50% of what it's taken to drill this well. And we are very close to total depth and are of the expectation that we are going to begin completion operations during this quarter.

And completion operations we haven't put a total number on either, but suffice to say related to the previous announcements that we've made and information that we've provided in our 10-K earnings filing, we have a significant number of potentially gas bearing zones to attempt a completion in. And the likelihood is that we will have on the order of at least 30 to 60 days of completion efforts and testing.

Will you need the pipeline in place for that testing to happen? And then also, what is the schedule for that pipeline and the cost estimated to build it?

We do not need the pipeline in place for the testing period. We do have a very active effort going on for the permitting of the pipeline and the acquisition of the rights of way necessary to do so. The actual distance between the well and the main trunk line is only 6 miles.

Due to topography and other things the line will actually end up being approximately 9 miles, but the cost associated with laying that and the time associated with constructing that are actually expected to be fairly minimal once permit approvals have been received. We would expect that a pipeline would be hooked up and operational within six months and maybe sooner. But that will not hinder the ability to go forward with testing in the interim.

Okay. You mentioned that completion costs have come back in the Piceance. Do you have an estimate of what those costs are running right now and then a schedule or a plan going forward to complete the 31 wells that have been drilled?

Yes, we have in a general sense total costs; both drilling and completion costs have come down a solid 25% in the Piceance Basin. And in certain situations, and primarily related to the ability to have quicker payment, discounts will be even greater than that. And in fact, we think that it is not unreasonable to expect that total cost can come down on the order of 30% to 35%. That is a meaningful amount especially for an area like the Piceance Basin and really allows for much greater rates of return even with current commodity prices.

Okay, and just one last one. You mentioned in the Q that there were some liens from some of your vendors that have been filed that also affected the covenants. Under the forbearance agreement that doesn't apply, but what happens when the forbearance agreement terminates? What's the impact of those liens on the credit facility covenant?

With regard to any liens that have been filed, the liens that have been filed are -- any liens that have been filed are currently in dispute. And there are no liens that have been filed related to undisputed invoicing at this point. So we're not in violation of forbearance agreements or anything else at this stage.

Okay, I thought there was some text in the Q that stated that there were some covenants that have been affected. But I'll take another look at that. That's all I have for now.

Okay, Joe. Thank you.

Joe Allman, JPMorgan.

Thank you. Good morning, everybody. Roger, in the Q it indicated that the cash flow from investing was $48 million or so. And your CapEx restated in the release is $29 million. So what's that like $19 million Delta?

Yes, this is Kevin. That's just the timing of the payments of the payables relating to CapEx that was incurred in prior quarters.

Okay, great.

Our occurrence was really only like around $26 million, $27 million.

Thank you. And then on the Columbia River Basin well, I know it took longer than you originally thought. Just in layman's terms, what were some of the issues you encountered? Was it basalt or could you just describe the issues?

I'll let John make a few comments here as well, but I'll remind that, among other things, we experienced gas flows very early on in the well last summer that actually created for an unexpected and unsafe situation at the rig floor level where we had a fire that injured a number of people on location. Fortunately there were no fatalities related to it. But that is absolutely something that probably added a minimum of a month's worth of time to fix and repair related to rig equipment, that's just one example.

I would say that the other drilling time additions that we experienced were related to drilling in the basalt itself. And there was stage at which the well was required to be plugged back and sidetracked, and that sort of activity creates additional time but is also the type of thing that can easily be planned for on the go-forward basis.

So it's the opinion of all involved, not just Delta but our partners as well, that the learning experience here has provided a lot of information that will allow for a much more streamlined drilling activity going forward. And probably also a different hole design. We have a very large diameter hole at the surface of this well and that may not be completely necessary on a go-forward basis.

Okay. And how deep is total depth on this one?

We haven't determined what actual total depth is going to be on this one as yet.

Okay, can you just give a rough number?

Actually right at the moment, no, I can't give you a rough number.

Okay, okay. Very helpful, thank you.

John Freeman, Raymond James.

Good morning. On the last call I believe the only area where you all were dealing with lease expiration issues was in the Haynesville. And if memory serves, I want to say about 4,000 acres are of the roughly 11,000 acres you had at the time -- to not lose that you'd have to drill a well or negotiate an extension by, I think, July 1. Can you give me an update on that?

Yes, and let me clarify on that for you, John. That is actually not in the -- it is in Louisiana, it is not a Haynesville play. And we are in discussion to try and create extensions related to that. And I think there remain good possibilities in that regard at this stage.

Okay, so just to clarify -- on the last call when it was mentioned you have 11,000 net acres in the Haynesville. It's still 11,000, but when 4,000 was cited as expiring, that was just -- that wasn't right?

Yes, that's correct. It was Louisiana leasehold and probably incorrectly referred to as Haynesville. With regard to the Haynesville, we still have 11,000 acres of leasehold at this point, net leasehold.

Okay. And there's no lease expiration issues this year? I mean, I know I think you said like 25%, 24% of it needed to be drilled in the next couple of years, but is anything due this year?

That's correct, John. There is nothing due that is required this year in the Haynesville.

Okay. And then moving on to the CRB, without going into -- trying to get the cost on the Gray well, just I guess longer term, like a year ago when you were talking about these wells and what you thought ultimately when this was in development mode what these wells could get done for, you all had mentioned like $15 million. I'm just trying to get a sense of whether or not that number is still in the ballpark?

Yes, we certainly think that is and I would answer that by saying that it's the expectation of all involved that we can very likely drill new wells and more in the range of a five-month to six-month period of time as opposed to what we've experienced on this well.

Okay, that's helpful. And then just the last question I had. On the G&A -- last quarter you all talked about that being reduced by about 50% this year. It looks like second quarter it will be down to about 25% lower. Is the 50% still the right number to think about -- for the year?

Yes, I would say that the run rate for the second half of the year is likely to be closer to 50% of the 2008 levels, but we are in a continuing process of getting it down to those levels as we speak. So all in for the year of 2009 it will probably be higher. Or I guess I should say not as much as a total of 50% reduction from '08 to '09, but the run rate as you get into the second half of '09 should approach those levels.

Okay, great. Thank you all.

Michael Bodino, SMH Capital.

Good morning, guys. Just a quick follow-up. I know that you all had some packages, sales packages out in the market. What's the status of any of that? Are they off the market? Are you all proceeding with any of them?

Michael, in a general sense we have discussions going on on many fronts and really related to virtually all of the project areas within the Company. We are having discussions related to Paradox Basin, Utah Hingeline, Haynesville acreage, Piceance Basin acreage, and we're of the opinion that there is significant interest in each area.

And I think that we will be very well served to fix our liquidity position here. And then on a go-forward basis be in a position to actually transact and go forward to hopefully allow for additional activities in each of these areas.

Just another question, on the other part of the California litigation settlement, the $90 million, what is the process there? What is holding that up if anything?

We had -- it was part of the initial and is part of the initial litigation for all other leases that we are now being paid on. The government separated one lease in particular and claimed that there was potential drainage on that lease due to drilling activity on other leaseholds adjacent to that lease.

We actually went to full trial related to the drainage issue and on February 25 of this year the judge in that case, which was also the same judge in the other case, came down with a 91-page opinion establishing that there was essentially no drainage and therefore reaffirming Delta's $91 million judgment against the government.

Clearly based on what just occurred with regard to their decision not to appeal to the Supreme Court, that does help in limiting the amount of time that the government can appeal and extend payment related to that particular lease and it is our expectation that because of that we are in a position to probably be able to work something out related to that amount as well.

So this is a Delta specific part of the litigation and not with the rest of the Amber plaintiffs?

Well, it is a lease that is part of the Amber -- the original Amber litigation, but this particular lease is 100% owned by Delta.

Okay. I guess I needed some clarity on that; I didn't quite understand all that. But that explains a lot of it. All right, Roger, good luck with everything and I'll catch up with you soon.

At this time I would like to turn the conference back over to Roger Parker for any closing remarks.

Okay, thank you all for joining us this morning; we look forward to speaking with you on the next conference call. Thank you.

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