Par Pacific Holdings Inc (PARR) 2011 Q1 法說會逐字稿

Good morning and welcome to the Delta Petroleum first-quarter 2011 earnings conference call. 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. Please go ahead, sir.

Thank you, everyone. And thank you for joining us for Delta's first-quarter 2011 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 and forward-looking statements within the meaning of the Federal Securities Laws and are intended to be covered by the Safe Harbor protections. In that regard, you're referred to the cautionary statement displayed on Delta's website which is incorporated by reference with respect to the information provided for this call. Investors are urged to closely consider the oil and gas disclosures and the risk factors set forth in Delta's Form 10-K for fiscal year end December 31, 2010, as updated by subsequent periodic and current reports on Forms on 10-Q and 8-K respectively.

Today's speakers from Delta are Dan Taylor, Chairman of the Board, Carl Lakey, President and Chief Executive Officer, and Kevin Nanke, Treasurer and Chief Financial Officer. I will now turn the conference call over to our Chairman, Dan Taylor.

Thanks, Broc. Good morning, everyone, and thank you for joining us. As I'm sure many of you have noted, over the past few months there has been a renewed and increasing interest in the Piceance Basin driven by increasing recognition of the revenue from natural gas liquids and drilling success occurring in the deeper shale formations. In a recent report published last week, an analyst stated that the wells drilled by a nearby competitor rival Haynesville wells and provide indications that continued development of the Niobrara may dramatically change the economics of Piceance's development. The analyst noted that the Niobrara is located at shallower depths in the Piceance than in the Haynesville and thus the well cost is less, which combined with similar initial production rates, equates to better economics.

As Carl will discuss, the indications of our wells to date support this preliminary conclusion. We have initial production from the 2B well and expect higher rates from the 2C well, which has all the pay of the 2P well-- 2B well, plus an additional 2800 feet of gross interval to complete. I believe our strategy to dedicate all of our efforts and capital to the Vega area was the correct one and is being validated with the results, not just from our wells but from other operators as well.

As mentioned in our press release, we have decided to market for sale our non-operated properties in Texas and the DJ Basin in order to raise capital to drill 2 additional wells in the Vega area, targeting the Mancos and Niobrara shales. These 2 additional wells to be drilled are wells that will hold lease hold, so they will be accomplishing 2 objectives. First, to continue to quantify and confirm the reserves and economics of the shale formations. And second, to secure our acreage position in the Vega area.

It is always easier to have these conference calls on the heels of what I believe are solid financial results from the quarter. While our production increased over the prior quarter, it was slightly lower than expected due to our decision to delay completion dates so that we could focus on the deep shale wells. We anticipated completing all 5 uncompleted wells in our inventory but only completed 3 of them in the first quarter. However, while we missed our production guidance slightly, it was more than offset by lower than expected G&A. Kevin will discuss the first quarter's financial results in more detail. As I mentioned in the last conference call, I'm expecting a very promising year for Delta and what I've seen to date only heightens my expectations.

With respect to our capital needs, our primary goal is to create value for our shareholders. We believe our assets are tremendously undervalued by the markets today. To be sure, part of the challenge is to provide clarity on how we will recapitalize our balance sheet. But in order to maximize our access to the capital markets and to provide maximum value to our shareholders, we must also be able to present a clear picture of our resource potential in the deep shales of our acreage in the Piceance. We have much information today and have the time to gather and provide much more information before we will move forward with strategic alternatives for the Company. As a result, we will not take questions on today's call regarding our capital raising alternatives. Now I'd like to turn the call over to Carl. Carl?

Thank you, Dan. Good morning, everyone, thank you for participating. Delta did have another strong quarter, the focus on our core asset is being validated in the numbers. The improvement is related to numerous items which Kevin will share with other financial metrics shortly. As proud as I am of these financial results, I really want to share why we are so excited about our shale wells. As we've announced previously, the information we had gather to date continues to raise our expectations on the resource that exists in the shales below the Williams Fork. In fact we believe the resource will exceed that of the Williams Fork in our field, and based on our findings and other published information, perhaps across much of the Piceance Basin.

The 2B well drilled through a portion of the Mancos formation reached a total depth of 10,700 feet. We've completed roughly 1,200 feet of gross pay in the upper Mancos and Corcoran formations only. This represents only 30% of the shale pay identified in the 2C well. Gas production began on April 24, and the well was flowing 3.3 million cubic feet a day by April 29. Through May 9, sales have averaged 1.8 million cubic feet per day. It is early in the cleanup process as load recovering from the frac stimulation is only 27%. The well has had the opportunity to produce [activity] for only the last 4 days. The Williams Fork section in this well will not be completed until more production information is gathered from the Mancos and Corcoran formations. While still very early in the life of this well, it seems clear that Delta has a discovery in the upper shales.

With respect to the rest of the shale, the well drilled on pad 2C has resumed normal completion activity, with 6 additional frac stages scheduled for the later this week targeting the Niobrara and lower Mancos formations. The well has already flowed at a rate of 2 million cubic feet a day and produced 30 barrels of condensate over merely a few hours with 6700 psi wellhead flowing pressure from 2 stages in the Frontier and the lowest 20 feet of the Niobrara. This pay represents less than 10% of the 4,000 feet of gross hydrocarbon bearing interval identified in the well. The static bottom hole pressure is 10,900 psi. As shown as our website presentation, the logs and the appendix show approximately 600 feet of Niobrara pay with a signature suggesting condensate, of which only the 20 feet of the Niobrara that has already been opened has produced condensate. We are obviously very excited about the potential for meaningful liquids production from the shales. Kevin will speak directly to the economic importance of these liquids on our financial performance in his comments.

Well density for vertical wells in these intervals has been established to 10 acres by at least 2 other Piceance operators. We continue to use think the resource in our field based on vertical gross pay thickness of 4,000 feet and bottom hole pressure of 10,900 psi vastly exceed the potential of the substantive activity that we are aware of elsewhere in the basin. This potential best lends itself to vertical well development. Others in the basin have already proven horizontal potential. This technique is available to Delta if we think it necessary, we have permitted a number of contingency locations to test this potential if the vertical wells prove unable to deliver what we think they are capable of.

Our capital plans for the remainder of 2011 include the drilling of an additional well in section 6 of 9 south 92 west of the Frontier formation, the newly formed Sheep Creek-- federal Sheep Creek Unit. This well will spud in the coming 2 weeks and is programmed to a measured depth of 13,500 feet. It is targeting the same intervals identified in the 2C well. This well will also hold the unit of 2715 acres and raise our total secured acreage to 93% across our entire acreage position.

As Dan mentioned earlier, our results are validating our strategy of focusing on the profitability and future potential of our core assets in the Piceance Basin. Divestiture of our remaining non-operated assets will allow further investigation of the shales and additional portions of our acreage position to be secured. In anticipation of a successful sale transaction, we have initiated work on a fourth well that tests the shales in the Vega area. This well as planned will spud in Q3 in section 17 of 9 south 93 west and will also test intervals from the shales below the Williams Fork. We expect the 4 wells collectively will demonstrate a productive cross-bearing section across our acreage position of roughly 5 miles from west to east. We believe based on internal studies that a similar cross-section of production the shales can be demonstrated in north-south orientation also. I will now turn-- ask Kevin to expound on the financial metrics which validate another successful quarter for Delta's business.

Thank you, Carl. Good morning. EBITDAX from continuing operations increased to $8.8 million, an increase of 19% from Q4 2010 after adjusting for the one-time benefits of $1.2 million in Q4 related to a production tax true up and transition fees earned on the sale of properties. The EBITDAX increase is primarily the result of higher commodity prices, increased production and a continued focus on maintaining cost control on our core asset. For the first quarter, we reported production from continuing operations of 3.5 Bcfe, an increase of 4% to Q4, both slightly under what we had expected. During the quarter, we completed 3 of our 5 remaining Williams Fork inventoried wells. We anticipated completing all 5, however, with limited frac crews and a focus on the shales, we decided to leave the 2 completions for a later date.

Our natural gas liquids currently represent approximately a third of our revenue from the Vega area. To put this number in context, the extraction of the NGLs from our gas stream only reduce our MMBtu content by approximately 15%. And the current prices of the NGLs are far in excess of what the revenue would be if kept within the gas production. This is evidenced by our realized price per Mcfe. In the first quarter, our total realized revenue before hedges for the Vega area was $5.55 per Mcfe, whereas the average Henry Hub spot gas price for the quarter was only $4.18. Moreover, our realized price was reduced by the differential of the Henry Hub to Colorado Interstate Gas, or CIG, of a negative $0.17 for the quarter. In essence, our liquids and condensate combined to provide us an equivalent price for our productions that was roughly 38% over the CIG benchmark for the quarter.

Our lease operating expenses per Mcfe from continuing operations were $1.33 per Mcfe. This is an increase from the $1.09 per Mcfe for the fourth quarter of 2010, and is primarily a result of higher operational and expense work over costs in our non-operated assets in Texas and offshore California. Piceance operations continue to remain in line at [sub] $1 per Mcfe. We maintain G&A at $6-- or excuse me, $6.6 million for the first quarter, of which $2.3 million was non-cash equity compensation. This equates to a Delta standalone cash G&A for the first quarter of proximally $4.3 million, which is slightly lower than cash G&A guidance of $4.5 million per quarter given.

The marketing effort of DHS continues to move forward. DHS is working with a potential buyer who has provided a full company and multi-rig bid. Either outcome, if completed, would be beneficial to the shareholders of DHS and its management. DHS continues to work with its lender during this due diligence process. With DHS assets classified as held for sale, Delta's financial statements more clearly show Delta's standalone results.

As Dan mentioned, we're beginning the marketing process of our non-core Gulf Coast assets. The proceeds of these assets will allow the Company to expand the validation of our shale potential. Further validation will strengthen the overall value of the Company and allow us to address our long-term liquidity profile. In conclusion, we are pleased with the first quarter and look forward to updating you with our progress going forward. With that, we will open it up to questions.

We will now begin the question-and-answer session. (Operator Instructions) Joe Allman of JPMorgan. Go ahead, please.

Thank you. Hi , everybody.

Good morning.

In terms of the deeper wells, the B and the C, could you give us the cost of those wells and what's your expected cost going forward?

On the 2C well, we're expecting still around $10.5 million. The 2B well is AFE'd at just under $5 million. We believe in subsequent attempts, including this well we're about to spud in Sheep Creek Unit, that we'll go all the way to the depths experienced in the 2C well that we can see that AFE come in and around $8 million is what we're targeting.

Okay. That' s helpful. And then in terms of the feet of pay you're seeing, I know you gave gross feet, I think, could you give us the net on the 2B and then on the 2C? I know you've only drilled some of that, but of what you've drilled, what's the net to gross there?

Really, when you look at these shales on the logs, the entire section is hydrocarbon bearing, and really the net to gross is just almost 1 to 1. I mean we're not high-grading the shales to any material degree based on log signature. All of it seems to have hydrocarbon and it. Al l of it seems to be attractive. Some of it has better rock mechanics properties than others, but all of it seems to be hydrocarbon bearing. So, when we go to stimulate, we're intending to basically stimulate the entire section.

Okay. That' s helpful. And then in terms of the EUR per well, what are your expectations there with what you've drilled already and going forward?

Still a little too early to say. Obviously, once we've established decline curve off these wells, we'll have a much better indication of what that looks like, but it's a little premature to say. There is some public data out there on other wells that competitors have drilled in the basin where EURs could be established from that. I'm not prepared to talk about their wells here, but suffice it to say, we think they're encouraging.

And just what would you consider the main difference is between sort of the geology where you are versus nearby industry activity?

Well, to be fair, as we look at our intervals, we just have not been able to see any place else in the basin where the section is over pressured and hydrocarbon saturated from the top of the Mancos all the way to the bottom of the Niobrara. So, we think we just have more pay than anyplace else we've been able to identify. We have seen some logs in other areas and other portions of the basin that suggests a little lower pressures or hydrocarbons that are more productive or more suggestive of production than in the deeper parts of the Niobrara, but not across the entire section like we have.

Okay. All right, very helpful. Thank you.

Gregg Brody of JPMorgan.

Hello, guys.

Good morning.

You made mention that the borrowing base would potentially-- would decrease if the asset sale was completed. Could you give us a sense of how much of the borrowing base those potential-- those assets represent?

Gregg, we don't have that information yet. We're still working with Macquarie, and we'll identify that here once we move down the path with the transaction.

The one thing we'll point out is obviously we believe we will improve our liquidity as a result of the transaction based on our estimates of borrowing base impact.

Okay. That's helpful. Do you happen to have a production or reserves for those assets?

Year end roughly around 11 Bcf and current production, Kevin do you have that?

I'm going to get you something here in 2 seconds. We had about a half a Bcf produced for the quarter.

For the quarter. Okay, is that mostly gas?

No. That's mostly oil in the Gulf Coast.

Probably on the order of 70%, maybe a little higher than that, that's oil.

That's very helpful. And then just one follow-up question. I guess the acreage that you're identifying that's perspective for the deeper zones? How much acreage do you think is -- kind of fits that potential?

Well, our Vega acreage position in its aggregate is about 22,000 net acres, and we believe all of it is perspective for the deeper shales. In fact, those 4 wells that I mentioned earlier in the call will basically stitch a cross-section demonstrating productive shales east to west across our entire acreage position. We feel confident that we can do the same thing north or south. It just so happens that acreage holding dictates that we'll drill in an east/west orientation first to secure our acreage position.

That is very helpful. Thank you, guys.

Andrew Shapiro of Lawndale Capital Management.

Hi. A few follow-up questions off your script and this prior question. Or first off should we expect further reductions in standalone cash G&A from Q1s levels, or are we at a stabilized base or should we expect increases?

Andrew, I believe the second half of 2011, you can see some decreases in our G&A. I think for second quarter, we'll still come in at below $4.5 million for the quarter. But hopefully, we can make some improvements on the latter half of the year.

Okay. And then regarding the newly announced the sale of properties in Texas, and you call it the DJ Basin, where is this asset, by the way, would these assets be sold together with the Texas assets?

Okay. There' s actually 3 distinct properties that are part of the package. 2 of them are in Texas, 1 called Midway Loop in Polk County. The second is in the Newton Field in Newton County, that's a Wilcox oil field. Then finally, a smaller property we call Golden Prairie in the DJ Basin in Southeastern Wyoming.

Okay. So that's far enough away that might not go in the same sale?

We expect it probably will, but certainly we'll let the bidding process and offers dictate how that goes.

How long of a process do you envision for this asset sale? I mean, are these complex, thus requiring a lot of time to sell?

Yes, this is before the end of June is what we're targeting.

Okay. Then, regarding the DHS sale, as a 49% shareholder, to what extent are you involved in the acceptance of the price that they choose to monetize it? And based on last quarter's call, the process started March 1 or earlier. Where does that process stands and what are the bidding milestones left and expected timing of determining the winning bidder on the DHS sale?

Andrew, this is Dan, I'm going to address your global question first, and then Kevin can talk about the specifics at DHS. It was only recently that we actively moved forward on this process, and there have been a number of different structures that we've considered. As Kevin mentioned during his comments, there was a multi-rig bid as well as full Company asset profile bid. Those have evolved and we've got people looking at these assets. We also have to deal with our lender in connection with these assets as well, because as you know, we have a forbearance agreement in place on our loan. So, the goal here is to now finish the process in a rather efficient manner. We think we've seen all the opportunities and our lender is working with us on this.

Yes, Andrew, the process-- the due diligence process is underway. They have spent some time out in the field looking at all the rigs. We're going through that process right now. I think they'll come back to us over the next couple weeks and give us their final assessment. If they move down a smaller rig package, we do have other groups that are interested in the remaining rigs. And like Dan said, we are working with our lenders during this process.

Okay, and a final question. You've talked about a little bit of this last quarter as well, but you can maybe give us an update and also if these new deeper wells have any implication? What's the status of your water disposal permitting activity and your water disposal capacity as you were starting to, I guess, put the water in used up wells and such?

Sure. Andrew, this is Carl. We've got 2 wells taking water right now at about 3,500 barrels a day, that's against our total water production of about 4200. So, we're essentially at breakeven right now. We expect 2 additional wells for conversion to be permitted by the end of the second quarter, and we'll bring those online, which will push us over the top to be able to handle all of our produced water through sub-surface injection of our inventory wells.

And does your demand for this activity increase with the new deeper well drilling you're doing?

No, it does not. In fact, it goes down. What we're seeing out of the shales is that these-- the shales relative to Williams Fork are very dry in terms of produced water from the formations. So we'll expect to see less water production going forward as our Williams Fork wells that were completed in the fourth quarter and first quarter produced some of their load back. They're still having residual load and that water production will decrease as we go forward.

Great. Thank you.

Joe Allman of JPMorgan.

Thanks again. Just on the-- in the Vega area, your lease expiration, could you just describe the acreage that you've got held already and how much is not held and what's the time table of the expiration for that?

Really, we've got out of the 22,000 acres, we've got 2 blocks that we're considering holding together this year that are material. The first is we formed a federal unit called the Sheep Creek Unit late last year on the northeastern flank of the acreage, it's about 3,700 acres. And the BLM has agreed with us that if we spud a well in May, that will hold that acreage together. So, that's first and foremost when we'll begin spudding that well next week. That's well in progress.

The second piece of acreage that we have that was going to expire this year is in that section 17 area kind of in the West-central portion of the field, and it's not nearly as much, I want to say it's about 480 acres, something in the neighborhood. So, it's not nearly as substantive of an acreage position, and it's expiration would be in September of this year. So, we're targeting potentially spudding that fourth shale well in August.

And then what's the status with the expiration of the other acreage?

Most of the other acreage is really not too bad. We're going to be in good shape. By the time we get done with the Sheep Creek Unit, 93% of that acreage position is-- will be held by production or held by unit. And it strings out over the next several years for the remaining bits and pieces.

Okay. All right, that's helpful. And then in terms of infrastructure, so if you do produce oil or condensate here, do you have the infrastructure in place to handle that? And if not, what do you need to do to provide that?

No, we're well positioned. In fact one of the nice things about the shale play is the infrastructure was already laid in place for the Williams Fork, and by using that infrastructure to move the gas, we're well positioned to handle it. So, from an infrastructure standpoint, it's almost a bolt-up.

Including the higher pressures that you may be seeing from the deeper--?

The higher pressures are handled with wellhead equipment and separators and chokes very near the wellhead. That's not the largest part of the infrastructure piece. In fact it's relatively modest piece.

That's helpful. And then just on the prior question, what's the timetable on those 2 new water disposal wells?

We'll certainly have one of them going in the second quarter, and the next one, it's kind of -- we expect to have the permit back whether the well will be injecting in the second quarter remains to be seen. But certainly on or about the end of the quarter we'll have the second one online.

Okay. All right. Very helpful. Than k you.

This concludes our question-and-answer session. I would like to turn the conference back over to Broc Richardson for any closing remarks.

I'll turn the conference of over to Carl for last closing remarks, please.

Thanks so much for attending our first-quarter conference call. You can see why we're excited and we're very pleased with our performance and we look forward to sharing more with you in the future. Thank you.

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