Par Pacific Holdings Inc (PARR) 2009 Q3 法說會逐字稿

Hello and welcome to the Delta Petroleum Corporation 2009 third quarter earnings conference call and webcast. All participants will be in listen-only mode. (Operator Instructions) Please note this event is being recorded.

I would now like to turn the conference over to Brock Richardson, Vice President Corporate Development and Investor Relations. Mr. Richardson, the floor is yours, sir.

Thank you and good morning. Before we begin I would like to remind you we are conducting this call under Safe Harbor and that this call will include projections within the meaning of the federal securities laws and are intended to be covered by the Safe Harbor as credited thereby. In that regard you are referred to the cautionary statement displayed on Delta's website which is incorporated by reference to the information provided for 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 conclusive formation tests to be economically and legally producible under existing economic, and operating conditions. Delta may use certain terms in this conference call that the SECs guidelines strictly prohibit us from including in the filings with the SEC. Investors are urged to consider closely the oil and gas disclosures and Delta's Form 10-K for fiscal year end December 31, 2008, as updated by subsequent periodic, and current reports on Forms 10-Q and 8-K respectively.

Today's speakers from Delta are Dan Taylor, Chairman of the Board. John Wallace, President and Chief Operating Officer. And Kevin Nanke, President and Chief Financial Officer. With that, I will turn the conference over to our Chairman, Dan Taylor.

Thanks, Brock. Good morning everyone, and thank you for joining us on Delta's third quarter 2009 conference call. I will spend a few minutes with my comments before turning the call over to John. First, I will speak briefly about the Gray well in the Columbia River Basin.

The uneconomic results are certainly disappointing. Especially for a well that looked so promising during drilling activity. That said, it is important to note that it did not meaningfully jeopardize financial position of the Company. As we did not project production and cash flow to be generated by an exploration well given its risk nothing has transpired at the Gray well that was not already planned into our budget. And as mentioned in our press release the primary formation in the Columbia River Basin, the Rosalynn, still has not been tested and remains a very attractive target. We do not have plans to drill another well on the CRB, but we have not significantly impaired our CRB acreage either since we believe the Rosalynn provides meaningful option value for future testing.

Second, in regard to Delta's strategy we remain focused on what is our primary asset, the Vega area of of the Piceance Basin. We have been a beneficiary recently of improved realized pricing with higher gas prices and a much lower basis differential. Under current and projected gas prices the value of this asset is severely underestimated in my opinion. We've never drilled a dry hole at Vega, and we've proven our expertise as operators of this unique asset. Additionally, we've received and re evaluating earn-in proposals that would allow part of the Vega area to be developed by third parties which would not require a material contribution of Deltas capital. Lastly, in regard to our leverage position, I believe we've dealt with a large hurdle in the redetermination of our borrowing base and receiving two quarters of covenant relief. This eliminates doubt about our leverage situation for the foreseeable future. Kevin will comment further on this matter.

In conclusion, I hope that many of you participating on the call today will do some analysis on what you think are proved and probable reserves are worth in this environment, and given the current trading level of our storks I'm sure the value would surprise you. We remain committed to continue to improve our operations now demonstrated with two sequential quarters of increased EBITDAX on a producing base and natural decline. Delta still faces certain risks, not the least of which is natural gas pricing risks. But we have taken many important steps to mitigate these risks to what I believe are acceptable levels. I will now turn the call over to John Wallace, Delta's President and Chief Operating Officer, for his comments on operations. John.

Thanks, Dan. To begin, even though we were unsuccessful with the Gray well, the seismic information gained from the well has allowed us to make strides in seismic reprocessing and interpretation. Delta continues to believe that the Columbia River Basin holds commercial gas reserves but pinpointing those accumulation under the basalt section has been a challenge. Determining a reliable means to generate well defined structural prospects will only enhance the value of Delta's extensive acreage position. Over the ensuing year Delta plans to conduct few physical operations in attempt to locate structurally defined prospects.

An previously discussed, an overriding objective during the year has been to reduce our capital expenditure and operating costs. The third quarter's numbers are now the second sequential quarter of demonstrating the results of these stringent cost cutting efforts, and we fully expect this trend to continue. Other than the decreases in staff, operational cost reductions have come through releasing unnecessary equipment, lowering water disposal costs, and restructuring service contracts.

Regarding the potential divestiture of assets as discussed in prior conference calls, we have sold or have agreements to sell approximately $8.5 million of properties in the fourth quarter. Only a small portion of these sales are from producing assets. We are fortunate to now be in a stronger selling position with higher natural gas prices. This will allow us to sell noncore assets in a methodical manner and without undue selling pressure resulting from financial concerns.

The current gas price and forward strip is sufficient enough to resume drilling activity in the Vega area, but we are focusing our capital expenditures on a combination of the 23 previously uncompleted wells and based on the recent successes of our new enhanced frac technology of uppermost Williams Fork, there is now a number of producing wells that have not completed this section. The Company now has a large inventory of wells to concentrate its efforts on for the near future. The information gleaned from this new frac technology will be used in new well design and we believe that it will have a positive impact on initial production rates and ultimate reserves.

Now that the CB GS2 pipeline is completed and operational, the 212 water treatment plant is under construction and will handle increased water volumes, and the MVS compressor station is operational, and similarly will handle significantly increased gas volumes in the future. The Vega area is poised for full field development. Service costs have further decreased, and with the increase in gas prices with seasonal demand, the economics of drilling new wells in the Vega area have dramatically improved. We have received favorable farm-out proposals from many different sources and we are evaluating them in context of increasing our production and reserves while at the same time protecting our balance sheet.

I will now turn the call over to Kevin Nanke, our CFO, for the discussion of the quarter's financial results.

Thank you, John. Good morning. Last week we completed our bank redetermination. Under our current agreement, we have a complete waiver for financial covenants for both Q4 and Q1 2010. Our borrowing base was reduced from $225 million to $185 million, but we are required to maintain $20 million of availability under our credit facility until we project one year of covenant compliance after January 1, 2010. The reason for the maintenance requirement as opposed to a further reduction in our borrowing base was to provide the greatest flexibility to the Company at our next redetermination. In addition, we have a CapEx limitation of $10 million for Q4, $10 million for the first quarter of 2010, and $5 million for the second quarter of 2010. Actual expenditures may be carried forward to future quarters if not spent in previous quarters. Production for the quarter was 5.1 bcfe and in line with internal expectations.

We have begun completion activity on the 24 inventoried wells in the Vega area and eight inventoried wells on our non operated Garden Gulch properties that were previously drilled but not completed. These wells are budgeted to be completed throughout the remainder of 2009 and into 2010 while staying within our capital limitations under our credit agreement. The Company is slightly increasing our production guidance for 2009 to rang of 21 to 22 bcfe. These operating expenses were $1.47 per Mcfe in Q3 compared to $1.34 per Mcfe in Q2. Operating costs stayed consistent on an actual cost incurred basis but increased on a metrics basis as production declined. As discussed in last quarter's call we projected total G&A to be consistent with Q2 and cash G&A to approximate 6.5 million to $7 million for Q3. Both of these amounts were in line with expectations and should continue for Q4.

EBITDAX increased to $4.8 million in Q3 compared to $925,000 per Q2, but remain flat compared with Q2 after adjusting for a one-time executive severance arrangement. During the quarter, we recorded approximately $53 million in dry hole and impairments, $31 million related to our dry hole in the Gray well. A substantial portion of the $20 million impairment of our Columbia River Basin lease holds related to fringe acreage no longer deemed perspective. Although we have no plans budgeted in the Columbia River Basin in the near term Delta continues to believe in the potential of the project.

We feel better about our liquidity position since the variables that were unknown, the borrowing base redetermination and covenant relief are behind us. Minimal capital and time is required to complete the inventoried wells and add to our production. In addition, we have received offers to farm into our Piceance Basin acreage under favorable terms. These types of proposals help reserve our liquidity while generating production and income growth for our shareholders. With that we will open it up to questions.

Yes, sir. (Operator Instructions) The first question we have comes from Jin Luo of JPMorgan.

This is actually Joe Allman.

Good morning.

In terms of asset sales in the second quarter call you talked about selling at least $70 million in asset sales, maybe more that. I heard I heard 90 million to $100 million. Could you give us a status on, do you still expect to sell that amount of assets, and would kind of timing are you looking at, and is that mainly a 2010 event, or are you hoping to get more done by year end?

This is Dan. We're still comfortable that we can sell that level of assets if we so desire. We have credible offers on some other assets here, producing noncore assets. However, given the fact that we're reviewing a number of alternatives for our 2010 plan, we decided to hold off on accepting any of those offers until we've reviewed all of our alternatives.

That's helpful. Then in terms of the Eagleford JV and asset sale, any update on that?

We're continuing to talk to companies, both the Haynesville and the Eagleford. We've got a lot of interest in those specific areas within each play, and there's been some new activity in close proximity to both -- well, one of our Haynesville positions and definitely our Eagleford position. We're continuing to review proposals that have been made to the Company. So they are in play but we have not concluded a deal yet with anybody.

That's helpful. In terms of production growth for 2010, what are you thinking about for production growth year-over-year for 2010?

Well, 2010, we haven't generated any guidance. We're still working on that. We have a large inventory of uncompleted wells, and more importantly, we've got a number of producing wells that have the upper interval -- uppermost interval of the Williams Fork now available to us based upon recent successes we've experienced. Of course, we need that success to continue, but that allows the Company a large inventory of wells to recomplete. So we're, at this point, formulating our plans for production growth, or what our production will be for 2010, and we haven't comment on it yet.

And actually that was my next question. On that upper interval, the uppermost of the Williams Fork. What kind of incremental EURs do you think you might get from that, and what's your ability to sort of pursue that? How many could you potentially perforate in 2010?

Well, we've got a lot of wells that had this interval still yet to be completed. It's really too early to comment on the specific reserve increases. I will say that this new frac technology that we're employing now is about the 5th generation of meaningful frac advancement here over the last five or six years and will affect, we believe, if we can continue on this path, will affect ultimate reserves for the entire Williams Fork section. But we need more than a handful of wells before really ready to comment on it, but so far it's been consistently very successful in what we've done so far. So we're pleasantly surprised. I can't guide you to reserve, new reserve numbers, but when we feel comfortable at that point we will then begin to speak on it.

Just to follow up, could you comment on any incremental plus, and what's the cost that you're seeing to do that completion?

The cost is fairly insignificant. And that's partly due to cost structure coming down in the basin and partly because these are not expensive additives to the frac design. I will point out that this particular design has been used throughout the basin and has been -- proved very successful in other parts of the basin which is one of the reasons why we have such confidence in the ability to increase not only uppermost Williams Fork but the entire Williams Fork segment where we are in the Vega area.

And incremental production from these?

It's meaningful. I'll comment when I really have a good handle on that.

Got you. Very helpful.

The next question we have comes from John Freeman with Raymond James.

Good morning. The first thing I was trying to get a handle on is when I'm looking at the 24 drilled but uncompleted wells, the last at least guidance on what you all gave for the completed portion of those wells would be was like $800,000. Is that still in the ballpark? Is it a little lower?

No, it's lower than that, John. And again, I can't point to an exact number, because this new frac design, we need to fully understand the merits of continuing forward with it. But so far we're very excited about the flow rigs that we've seen from the wells that we've done so far. But it's significantly less than what you're modeling.

Okay, good, that's mainly what I was looking for, is just directionally if it's at least lower than that?

It's worth pointing out that where the strip is now and where the Rocky Mountain differential is now, these are very robust economics, these recompletions.

Okay. And then just the last question I had on the borrowing base that was recently redetermined, did that already reflect any sort of issues with the gas price and potential like negative price related revisions, or is that something else that we have to keep an eye out for at the end of this year?

No, we don't have any issues with that.

Okay, great, thank you.

The next question we have comes from Greg Brody of JPMorgan.

Good afternoon, guys. Just following up on the borrowing base I was just curious of the amount, the redetermined amount. Is that a fully conforming or is there a non conforming?

No, that's a fully conforming number.

You had mentioned that -- banks wanted to keep at $20 million of liquidity cushion going forward in preparation for the possible redetermination in March. Could you explain what you mean by that?

Yes. What is required, if you want to maintain a specific borrowing base, you need a percentage of the vote to maintain that. And by using a cushion instead of reducing the borrowing base, I will need less of my bankers to approve that going forward.

Okay, that makes sense. And is the March date to be determined, is that when originally you expected to be redetermined, or was that accelerated because of the redetermination?

No, that is the original redetermination.

Appreciate that. And then just on the JV, you mentioned you're looking at opportunities, some people have come to you. Can you give us a sense if there are strategic bidders involved or private equity, then maybe some timing?

It's a combination of all of that. I'll say it's not one or two, it's several. And right now we're trying to -- we're analyzing where we are with our balance sheet and what looks best for the company and how he we can most effectively grow production reserves for 2010. So we have a lot of options available to us in that scenario.

Do you have a sense of timing around that?

Well, we have some now. We're getting some more coming in, in the next week or so. I really can't tell you. It will be whenever, as a Company, we believe it's best for our shareholders, whenever we think it's the right thing to do.

Then the other asset sales which involved some of your inventories?

Again, one plays off the other.

So you will make the decision. All right. Is it fair to say by the next redetermination you may have made a decision, or is it--?

I think it's safe to say.

Thank you, guys.

The next question we have comes from Joe Magner of Macquarie.

Just a little bit more on the borrowing base. It looks like in addition to the $20 million cushion you also have capital investment constraints for the next three quarters. Didn't look like you had anything outstanding on that facility at the end of the third quarter, which would imply that you have more liquidity. Can you just explain, do you really have access to that at this point, or will you need the next redetermination process to take place before you can start to draw on that again?

No, we still have liquidity available today, enough to spend, you know, within the capital limitations that we have, sure. We have $123 million under a credit facility outstanding at the end of the quarter, so there's still availability, yes.

Okay. Couple of other questions have been asked about the cost to complete some of these wells that are in inventory. Granted, there's some variability with this new frac design, but can you just walk through with the capital constraints in place, expected cash flow in the next several quarters what kind of activity can you undertake in addition to the completions, how many new wells do you think you can participate in over the next three quarters?

Well, that all depends on he reconciling our balance sheet, but I will tell you that it's economic to drill new wells in the basin, and the joint venture proposals that we're getting involve new wells, but then again, I will tell you we have a large inventory of wells yet to be completed. Some of them have a different cost structure because they haven't been completed at all. Some of them have just the upper section to be completed and they're a lot less expensive. The cost ranges anywhere from 300,000 to $600,000 type range. But that's obviously for completions of existing drilling -- wells that have been previously drilled. New wells are expected to cost around $1.5 million if that helps you with any of your analysis.

Okay. And can you talk a little bit more about this new frac design and sort of what it entails and how it's going to improve either efficiencies or lower costs?

Really I hate to say this but these new frac designs, there are advantages that companies can use, and it seems like we've invented two of them of the last five, now somebody else has invented this newest generation, and the frac companies themselves advertise the success rates, based upon work that they've done. It's not anything completely revolutionary, but it's just small tweaks on existing frac designs that allow us to get more production reserves. And it's been demonstrated in other parts of the field. So I don't think it would really be pertinent to you what is in the frac design itself. You just look at more for the results, and the results were there. Just one last question.

Looked like DD&A went up quite a bit in the quarter. I imagine that had something to do with the midyear reserve report. Can you talk about what the limited drilling that's taken place throughout 2009, significant portion of your year-end '08 reserves were, PUDs largely in the Rockies, can you provide any thoughts on how your year end reserve is going to look and what if any impact there could be on that PUD component because of your reduced activity this year, what might change?

Sure. I don't think we'll probably comment on reserves on the call. Bear in mind that we have new reserve reporting rules that are going to go into at the end of the year. We are just starting our analysis on how that's going to impact Delta. Obviously they have the rules include average pricing throughout the year, which is less than the current price environment. That will impact reserves on a negative basis. However, we do plan on showing you with increased pricing how those reserves will come back in favor.

I guess just a reminder, at '08 or the end of '08 what sort of development program, or haw many years of drilling did you assume when you came up with that PUD percentage, and how will that change, or how could that change looking forward, given the makeup and the shifts of some of your capital allocation?

I'd have to go back and review the drilling pace that was used for the 2008 program and compare that to the 2009 program, but it's all based upon rig count. If we were to go in with some of these joint ventures that we're entertaining right now, there's a possibility that you could even have accelerated drilling. So it's too early to tell at this point in time. I will tell where you that where we sit right now, today, those PUDs are economical to drill at today's gas prices and today's cost structure. Now, there's been different way that the SEC looks at pricing for the year, but where we sit, the most important thing is what are your PUD reserves worth now. And they're economic to drill all the PUD and the probable reserves as we sit today.

Okay. Thank you.

The next question we have comes from Jack Aydin, with KeyBanc.

Hi, guys.

Hi, Jack.

Most of my questions were answered, but I have two. What percentage of your CRB acres was impaired with that $20 million?

There's about approximately 30 to 40% was impaired.

Okay. All right, thanks. The other question I had was how many of those 24 Vega wells you expect to complete by year end?

Probably eight or nine.

Okay. Thanks.

The next question we have comes from [Jeff Davies] of Waterstone Capital.

Is there any update on the government litigation payable?

We're currently participating in court-ordered mediation, so it's safe to say that settlement discussions are ongoing right now.

Any guess on timing on that?

I don't guess on the Federal Government.

I was going to stay, $8.5 million asset sales for the fourth quarter is that leases? What kind of assets?

It's a combination of pipe, some nonoperated properties.

Auction-rate securities are going to be sold.

Auction rate securities, it's a combination of smaller things.

What's the reason for the drop in the CapEx limitation from 10 to 5 in second quarter '10?

It's really irrelevant. We'll have a new redetermination in March, so that really doesn't come into play. There was really no reason for that. That was just the amount that we mutually agreed to.

Okay. But I guess you have $123 million outstanding today, excluding any asset sales or the payment from the government, the waiver through March, at least the way I see it, you're going bust the covenant again in June.

Our covenants are actually an annualized leverage ratio going forward from an EBITDAX standpoint. And based on the sales that we already plan to conclude in the fourth quarter and ones that we can conclude if we want to we think we'll be in compliance with our covenants going forward.

Was that a change with this amendment?

Yes, it was.

And I guess even if you get -- you basically free cash flow negative right now, have been for the last few quarters. Certainly that may change here in the future. But again, the borrowing base presumably is going to go down again early next year. Where's liquidity come from? Has the Company thought of debt for equity swaps to remove some of the interest burden, issuing more equity I mean, I kind of take exception to the comment that the leverage issue has been solved this is a Company that's 10 times leveraged and going higher.

Clearly at these stock prices, equity issuances are not something that we would seriously consider. However, as we've mentioned, wavy number of alternatives that we're reviewing here, the combination of which we believe will carry us beyond the March 1, redetermination date. It's just too early to tell you what the mix of those alternatives will be.

I'll hold my breath on execution. Thanks.

And we show no further questions at this time. I would like to turn the conference back over to management for any closing remarks.

Thanks for participating on the call today, and to all the shareholders, stay tuned. We think that we're going to be with the increasing gas prices, we think things are turning around for us. Thanks very much.

Thank you, gentlemen. The conference is now concluded. We thank you for attending today's presentation. At this time you may disconnect your lines.