Par Pacific Holdings Inc (PARR) 2010 Q4 法說會逐字稿

Hello and welcome to the Delta Petroleum year-end 2010 financial results conference call. (Operator Instructions). Please note this event is being recorded. I would now like to turn the conference over to Broc Richardson. Please go ahead.

Thanks, Amy. Good morning and thank you for joining us for Delta's fourth-quarter and year-end 2010 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 are 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 consider closely the oil and gas disclosures and the risk factors set forth in Delta's Form 10-K for fiscal year December 31, 2010, as updated by subsequent periodic and current reports on Forms 10-Q and 8-K respectively.

Today 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 call over to our Chairman, Dan Taylor.

Thanks, Broc. Good morning, everyone, and thank you for joining us today.

On this call, management and I will not just discuss the fourth-quarter and 2010 annual results, we will highlight the goals we set for Delta in 2010 and the accomplishments we achieved in the latter part of the year. We will also explain how we intend to carry these achievements forward in 2011 and what that means for our shareholders.

Contemporaneous with the appointment of Carl as our CEO in the summer of last year, the board outlines several objectives to be achieved through the remainder of 2010. We communicated them to you in our prior conference calls. There was a simplification of our asset base to the sale of non-core assets, the reduction of operating and overhead costs, the improvement of bigger areas per well reserves and economics, and the obtaining of a new senior secured credit facility. We achieved all of these objectives, and Carl and Kevin will take you through each of them. These accomplishments are noteworthy and of great value to Delta, particularly in the current gas price environment. Going into 2011, these operational improvements will have a very positive affect on Delta's direction, strategy and asset value.

For this year, our objectives are to maintain the cost improvements we achieved in the fourth quarter, to quantify any additional reserve upside in the deeper zones of the Vega area, to solidify our acreage position in the Vega area, to maintain an operational focus on our core asset, and to reduce our financial leverage and improve liquidity. The execution of these objectives will ensure that we realize our ultimate goal of continuing to improve our asset value in the current commodity price environment and creating value for our shareholders.

I'm sure many of you have heard or read the remarks of noteworthy CEOs of other E&P companies that have expressed their research views and forecasts of the North American natural gas market. While we generally share these predictions of the recovery of natural gas prices, we view it as our responsibility to have Delta prosper in the current natural gas market environment and not to simply survive until the recovery occurs. We have taken some meaningful concrete steps in that direction and will continue to do so in 2011.

Carl and the rest of the management team have shown the board that they are fully capable of achieving this strategic objective for 2011. The management team and the Company have the full support and backing of its largest shareholder, Tracinda Corporation. We are anticipating a promising year in 2011.

I will now turn the call over to Carl for his comments. Carl?

Thank you, Dan. We certainly recognize and appreciate Tracinda's continued support of Delta. I also believe 2011 will be a promising and transformative year for the Company.

With regard to the objectives we achieved in 2010, I will first address the simplification of our asset base, which now consists of the Vega area of the Piceance Basin and interests in other fields which are non-operated. This simplification allows us to retain a smaller workforce that is focused on one thing, the efficient management and operations of the Vega area.

An important element of this focus is the associated reduction in Delta standalone cash G&A expense as evidenced by Q4 2010, which was 43% lower than the run-rate in the first half of 2010. We remain focused on managing our G&A expense and will seek to implement further reductions in the future. Not only did we see significant reductions in our G&A expenses, but we also achieved meaningful 38% quarterly improvement in our lease operating expense in Q4, which is now at $1.09 per Mcfe for continuing operations. Much of this LOE savings is attributed to the reduction in water disposal costs.

We had substantial completion activity in the fourth quarter, and we are able to reuse our produced water in completions rather than having to pay for disposal. Going forward we anticipate sustaining our water disposal costs at their decreased level, even as completion increased activity decreases in the current quarter.

This is due in large part to a shift in water disposal methods to subsurface injection. We will be utilizing existing wells that have negligible or no production and which will be converted to water disposal wells. We expect to have three wells permitted in Q1 for water disposal and five by the end of Q2 to meet our anticipated water disposal needs.

While the improvement in our cost structure of both G&A and LOE have greatly improved the operational profitability of the Vega area, we have also been working on the revenue side of the property equation. We are excited to report both increased production and improved recovery of reserves per well. Our per well EUR is improved by 39% to an audited 1.6 Bcfe gross using the new Gen IV stimulation techniques versus the prior methodology. I believe the best indication of the significance of this change is that 16 wells or 8% of the total wells in the Vega area are now producing 39% of the field's total production. The incremental completion cost is approximately $500,000 per well, yielded a drilling and completion cost of $2.4 million per well, which we feel we can decrease to $2.1 million with a more continuous development program.

Delta net production for December was 21% higher at 38.9 million cubic feet equivalent per day than September 2010 net production. This increase was driven by the completion activity of the inventory wells using the new stimulation technique, which increased Vega production by 34% over the same period.

We are also pleased to share that we expect the production improvement to continue into Q1 2011 with an additional 4% to 7% of production growth. Perhaps most significant is that this improvement now points to an increase in total proved and probable reserves in the Williams Fork in the Vega area of a net 2.9 Tcfe, up from 2.1 Tcfe based on strip pricing.

As we mentioned in the third quarter's call, we began drilling a well targeting additional deeper formations, which had indicated to be productive in recently drilled wells by other operators in the Piceance Basin. In fact, there are now 62 active permits with the Colorado Oil and Gas Conservation Commission filed by our competitors in Mesa County and the surrounding three counties that target deeper formations, including the Mancos, Niobrara and Frontier. Multiple wells by other operators in Mesa County have reported initial production rate to the Colorado Oil and Gas Conservation Commission that are in excess of 6 million cubic feet a day. These production rates and volume activity in the basin are what interested us in testing the deeper formations. We reached a total depth of 13,300 feet in mid-December with that well. Technical evaluation and completions design work combined with a timing parallel cement cleanout and prepping of the well bore with clean fluids took us through January.

Stimulation activity started in mid-February through the availability of crews. Between the second and third fracture stages, a downhole wireline tool became stuck in the well bore. Much of that tool has been removed from the well bore, but efforts are still underway to retrieve the last components of the tool. There is always some risk associated with these types of events, but we feel that the plug will be recovered and that normal completion activity will resume shortly.

We expect that our completion activity will take us through most if not all of the month of May. The shows we experience while drilling in the electrical logs both indicate that we have 3700 feet of gross prospective interval in these deeper formations, but clearly nothing will be conclusive until production occurs.

Due to the information gathered from our well and other third-party wells in the area, we began drilling another well in the Vega area, which we will drill slightly deeper than the Williams Fork in the Mancos formation. The Mancos was one of the two formations in our deep test well that exhibited the best shows and appear to be the most prospective. Of course, our objective is to lower our per well finding and development costs by accessing more economically productive zones.

When combined with our lower lease operating expense, we hope to improve the profitability of the development and production in the Vega area. We will publicly disclose the results of the deep test well and the new Mancos well when it is appropriate to do so.

Dan mentions several goals for 2011 upon which management will be focused. One of those goals is to solidify Delta's acreage position in the Vega area as cost effectively as possible. I'm pleased to report significant progress has already been made in this regard.

At the beginning of 2010, Delta had 81% of its acreage held by production and 3600 acres that were at risk of expiration before 2013. Delta expects based on work already accomplished and the drilling of one leasehold well in May 2011 that we will then have 93% of acreage converted to HBP or held by production and only 740 acres under threat of expiration before 2013.

Taking collectively, our back to the basics approach to business has helped Delta lower its cost structure, increase production, improve per well recoveries, decrease finding and development costs, and has the yet unknown potential of improving on that further if the deep wells are proven productive.

In conclusion, we are pleased to present to our shareholders the results of an improved fourth quarter that demonstrates clear operational achievements and the resulting substantial improvement in our financial performance. Coupled with the plan for 2011, we believe we are well positioned to enhance shareholder value if we execute, and I am confident we will.

I will now turn the call over to Kevin for his comments on our financials.

Thank you, Carl. Good morning. For the quarter, we reported production from continuing operations of 3.35 Bcfe, which falls within the production guidance range we provided of 3.25 to 3.55 Bcfe and was a 7% increase from the previous quarter pro forma adjusted for the divestiture in July. EBITDAX for the fourth quarter was $10.4 million, a 20% increase from the third quarter. EBITDAX for the full-year 2010 was $36.5 million, an 85% increase from 2009 levels.

It should be noted that our EBITDAX increased over third quarter and full year, despite production declines from asset sales.

Our lease operating expense per Mcfe from continuing operations decreased 38% from the third quarter. The significant decrease is primarily attributed to lower water disposal costs in the Vega area due to the completion activity we performed in the quarter as Carl mentioned. While our completion activity is scheduled to finish within the next several weeks, we anticipate maintaining these lower lease operating costs utilizing water disposal wells.

Transportation costs increased in total dollars and on a per unit basis by approximately 20%. This increase was primarily due to our increase production in the Vega area where we extract the liquids through a processing plan providing us with favorable pricing. Our natural gas liquids or NGLs currently represent approximately 20% of our revenue from the Vega area.

To put this number in context, the extraction of the NGLs from our gas stream only reduces our MMBtu content by 10% to 15%, and the current prices of the NGLs are far in access of what the revenues would be if we kept within the gas production. This is evidenced by our realized price per Mcfe or, excuse me, per Mcf.

In the fourth quarter, our blended realized price was $4.66 per Mcf, whereas the average Henry Hub spot gas price for the fourth quarter was only $3.80. Moreover, our realized price also included the differential of Henry Hub to CIG of that negative $0.40 for the quarter. Subsequent to year-end, we entered into new NGLs hedges. With those hedges in place, we anticipate this favorable pricing to continue.

Production taxes in fourth quarter were unusually low as a result of updated prior period estimates and are not reflective of our expected run-rate of 4% to 5% of oil and gas revenue. We reduced our G&A to $7.8 million for the fourth quarter, of which $2.7 million was non-cash equity compensation and $1.1 million was G&A for DHS. This equates to a Delta standalone cash G&A for the fourth quarter of approximately $4 million.

So while the quarter's total G&A was lower in the third quarter by 25%, the cash component of G&A for Delta standalone was lower by 33%.

It is worth noting that the G&A in the third quarter did include nonrecurring items such as severance costs associated with our personnel reduction, as well as a $1.4 million DHS bad debt write-off that was discussed on our last conference call. We are pleased with the reduction in overhead we have achieved to date. Our credit agreement requires us to stay focused. We project Delta standalone cash (inaudible) to approximate $4.5 million a quarter for 2011 and hope to improve on that.

We are currently marketing DHS for sale. We believe we have sufficient access to rigs and that the sale of DHS will not affect our Piceance development.

As detailed in our press release yesterday afternoon, we announced our 2010 reserves, which shows the improvements in our EURs and lower operating costs. Total proved reserves at December 31, 2010, were 134 Bcfe using SEC pricing requirements, an increase of 17% from the prior year proved when adjusted through the 39 Bcf sold in the third quarter. 91% of our reserves were natural gas, which include related natural gas liquids and were 92% proved developed. Our production replacement rate totals 218%.

I think it is important to place our proved reserves in proper context, so I would like to provide you with a couple of price sensitivities. Using the pricing from the natural gas forward curve as of year-end and limiting ourselves to locations that meet the five-year drilling requirement and a four rig drilling program, our proved reserves increased to 767 Bcfe with a standardized measure of 528 million. With an additional dollar per MMBtu increase in natural gas price, our standardized measure increases to 873 million. Total estimated recovery from our Vega area asset is now 2.9 Tcfe. These reserves do not consider additional potential from deeper formations beneath the Williams Fork section that we are currently testing.

Earlier this week we announced our credit agreement with Macquarie. The amendment provides for nearly $19 million of additional liquidity under the term loan portion of the credit facility. The new facility removes the development plan approval process and mandatory cash flow suite repayment requirement. With full access to the $25 million term loan, we have sufficient liquidity for 2011 to evaluate the deep potential beneath the Williams Fork. We also project full covenant compliance for the duration of the facility.

Our 2011 drilling and completion capital budget for the Vega area has not yet been determined beyond the two exploratory test wells, lease preservation well, and five drilled but not yet completed inventory wells. Once we have sufficient results from the exploratory test wells, we will update our 2011 capital budget.

In conclusion, we are pleased with the progress we achieved this quarter and fully expect to maintain these financial improvements and translate them into a solid trend going forward.

With that, we will open it up to questions.

(Operator Instructions). Andrew Shapiro, Lawndale Capital Management.

Good morning. Could you give us or update us a little bit more on the status of the sale of DHS, like the expected milestones and potential timing of those milestones? And is Delta -- how much influence and control does Delta have over the sales process? I'm not sure exactly on your ownership percentage of DHS.

Yeah, we just engaged Macquarie to help us with that process. We did that, I believe, a couple of weeks ago. It is fairly early into that process obviously, but we don't believe that it will take a long period of time to get through it. Delta owns 49% of DHS, so we obviously have a significant influence of the outcome of that transaction.

In addition, I would like to point out our partner, Chesapeake Energy, and DHS fully supports this process as well. And we will be working closely with Macquarie to move it forward quickly. You should be aware that we do not expect to receive meaningful proceeds from the sale of the Company; however, all of the nonrecourse debt that is currently reflected on our balance sheet will disappear as part of this transaction.

Right. And now that led me to this follow-up question regarding this. On the balance sheet of Delta which you, I guess, do you consolidate DHS into this?

Correct.

And if so, what is the negative net worth that has been consolidated into DHS or the positive shareholder equity in that number that is consolidated into Delta's balance sheet?

Well, as we sit today, we actually have a negative equity position in DHS. So if you would assume that you would have zero value for this transaction, we would actually still report a gain once we close this particular transaction.

Right. And as of December 31, what is that negative net worth? What would that in a sense that gain be if you sold it for 0 for Delta?

Approximately $2.5 million.

Okay. And last question, separate issue. With increased environmental concerns from frac drilling and your mention here of a new water disposal method, could you just clarify or explain the new water disposal methods, and then to the extent that this is a riskier or less risky method of disposal with respect to -- I think it is mostly water pollution concerns from frac drilling?

Certainly. The water -- subsurface water injection -- is actually a very well time-proven technique broadly used across industry to dispose of produced water. The oversight of that is provided by the Colorado Oil and Gas Commission which permits and monitors those activities with strict compliance into subsurface aquifers that are not related to aquifers that supply drinking waters or fresh water for agriculture. So there is no mixing or blending of waters that would be used for beneficial purpose. And so, therefore, we feel very comfortable with the risk profile associated with that.

Okay. Thank you much. I may have more questions, but I will back out into the queue and let others ask.

Mike Martino, Wedbush.

Can you give us some clarity on the deep well testing? Any idea on the IP or the EVR and the value it would add?

Mike, certainly the value question is difficult to ascertain yet from our well given that we don't have production rates to surface yet. Probably the best analog I can provide for you is that that has been published in public documents with the Colorado Oil and Gas Commission where we have seen IP rates in the 6 million and 7 million cubic feet a day in neighboring areas in Mesa County published by other operators. We are certainly encouraged with what we have seen, but we cannot comment yet on what the expected value would be or what our rates will be until we have them.

If they are successful, does it translate to the entire area?

We believe it will translate to the area, yes.

Okay. Thank you.

Joe Magner, Macquarie.

Just a little bit more on these deep wells. Can you go into the cost comparison to your Williams Fork wells?

A Williams Fork well is roughly we have talked about $2.4 million and under a continuous development scenario being able to get that down to about $2.1 million. Our current deep well we expect we will spend about $10 million on, and we would expect on a forward case given what we have learned and the amount of that well had a tremendous amount of science in it and a lot of learning on our part. We would expect to be able to get down in the $7 million or $8 million on subsequent attempts.

Okay. So I guess -- and then what is the typical IP right now under this new frac technique?

In the Williams Fork, the new frac technique, these things tend to IP between 1.7 million and 2 million cubic feet a day.

Okay. So I guess it is about a 4 times improvement in the rate for a cost that is roughly 4 times your current cost? Well, if you are using the 2.4 versus the 10 million comparison, is that --?

Well, I think we are perhaps mixing projects here. The rates that I just quoted are for Williams Fork wells, not for the deeper shale wells.

No, I understand. I'm just comparing -- you are saying 1.5, 1.6. And then that compares to some of the IP rates that have been seen by some offset operators of 6 to 7. That is what I was --

You have mixed zones. I'm sorry, I don't believe that is accurate.

I guess what I'm trying to ascertain is just the driver of what is taking you away from your bread and butter of Williams Fork, 2.9 Ts of probable upside activity that could drive some production and cash flow versus spending $10 million of liquidity that is pretty dear at this point on a deeper exploration target. That is what I'm just trying to --

Well, I think obviously we believe that there is the chance of lowering our F&D costs even further by the time you get done with bolting on that deeper production to potentially a Williams Fork well. And that is the driver is to understand if we can do that.

And these are zones that you think could be co-mingled over time?

Certainly our expectation on the second well that we are doing is trying to do exactly that to either comingle or dual complete.

Carl, why don't you mention the costs underneath just the second deep, which is considerably less than --

Yes, the second deep, which is targeting the Mancos, is right now at about $4.8 million.

Now remember, for the cost of both of those wells, that is total costs, not incremental costs over what it takes for the Williams Fork.

That is correct.

Okay. So there would be some incremental completion costs for the Williams Fork if you were to drill deeper, but it would not be a full-on, new --?

No, the $7 million to $8 million would be all-inclusive.

Of the Williams Fork completion as well?

Correct.

Okay. And a question on -- you highlight the 2.9 Ts of probable upside, and then it looks like in your future development capital category, you're only assuming about two years of development? Did I read that correctly? I'm just curious what -- is that a capital limitation mainly, or what would I guess keep you from putting more development capital into your assumptions and expectations, if you do have that 2.9 Ts of probable upside in the Williams Fork?

You are right. We are not limited in the amount of capital we could spend or someone else could spend. What we provided was a sensitivity that really kind of stayed within the SEC drilling five-year drilling rules, which we assumed a four rig drilling program and just the number of wells that we could possibly drill within those five years.

I think equally important that within that period of time, you still only really made a dent in that total of 2.9 Ts. You have not fully developed it at all.

Right. No, I appreciate that. I was just curious what the driver was, but I guess it is a --

We felt the most reasonable approach was to assume that we would ramp up to four rigs over time in doing those calculations. Obviously that could vary considerably depending on conditions and the economy and everything else.

Okay. Just one other quick one and I will jump off. But could you provide us anymore information on the Gen IV frac? Has that evolved from the other improvements you have made over the past, I don't know, 18 to 24 months, kind of what the main characteristics of what you are doing now are?

Okay. Well, the Gen IV frac just to provide a little bit of clarity around it and I would just as soon not get into a tremendous amount of public details because obviously it is something we are proud of and don't necessarily need replicated, it is a larger frac. It is done with slick water, produced water, and it uses very low sand concentrations, higher rates and staging designed to increase fracture complexity.

Okay. All right. That is all I had for now. Thanks.

Evan Templeton, Jefferies.

First of all, just another follow-up on the deep well. Do you anticipate seeing -- will that be dry gas, or do you think -- expect a fair dose of liquids associated with that also?

I think our expectation going in is dry gas. We would not be disappointed at all to see some liquids out of it, if that is what ultimately comes, but I think you would have to say the expectation is dry gas.

Okay. And then just the second point. I was hoping you could maybe help me understand, in terms of the reserve additions this year, the extensions category, so is that basically just a result of applying the increased IPs, increased recoveries from this Gen IV frac to your inventory?

In a word, yes.

And how many wells have you applied the Gen IV frac to so far?

I think it was 16 is what we quoted. Yes, sir.

[Jeff Davies], Waterstone Capital.

Sorry if I missed this, but what is the full-year CapEx budget?

We have not provided a 2011 CapEx budget at this time.

Okay. And then can you just remind me in Vega what you have for processing and pipeline capacity?

Okay. Multiple answers here because there is what Delta has in its equipment. We have currently on the ground compression equipment able to move 60 million cubic feet a day into the pipeline. The pipeline is -- the sales pipeline, midstream pipeline, is a 24-inch line that has the capacity ultimately to move 600 million cubic feet a day of gas between us and our neighbors, Occidental and some other smaller operators in the Valley up to the Meeker plant. So there is ample takeaway capacity out of the Vega area. Our compressor station at 60 million a day is permitted and able to bolt-on additional compressors to move that number to a 120 million cubic feet a day with permits we already have in hand.

Okay. And I can appreciate you guys clearly focusing on operations. It is good to see the LOE number is coming down here a little bit. So congrats on that. But operationally it is good to see the focus, but financially you still have a couple of looming maturities. I'm just kind of curious what your thoughts are on specifically the convert put next year?

Well, clearly we recognized that the put is out there. The results of the deep test will, I guess, provide us with additional information to refocus on how we are going to take care of that, and we probably will not comment on that until we have the results from the deep test.

Okay. So not to put words in your mouth, but your hope is you can prove that up and monetize --

Yeah, just to provide some additional color, obviously Carl, Kevin and the team successfully completed an amendment to our credit agreement, which gives us runway for the rest of 2011. That will give us plenty of time to find out what we have in these deeper zones.

Conversely with the improvements that we have made in the existing asset, we believe that there is shareholder value that has been created during this process, and we believe that the Company will have options regardless of the outcome. But we have time to evaluate and make sure that we maximize those options.

Agreed. I would add just one other thing. I think that certainly the deep wells are something that could be accretive, but we have not lost sight on the fact that our bread and butter is still Williams Fork, and we have made meaningful improvements there that add value to our shareholders and do create additional options.

Okay. But I guess in the press release you talk about G&A being lower because you are no longer in the strategic review process. But, at some point, you're going to have to pick up an advisor again here to explore some of these options I would assume?

I think all options are still on the table for us right now, yes.

(Operator Instructions). Andrew Shapiro, Lawndale Capital Management.

Just a little follow-up here on the financing. Can you go through or just summarize here the current state and quantity of the financing as recently amended, their upcoming maturities, any spring inputs, etc.? And I think coming from that is a follow-up question, which is, if you have these puts on the converts in the middle of 2012 and the current senior debt is due in the early 2012, do you feel it is necessary to deal with the converts or have something refinancing on those converts in order to get a new senior debt deal in January?

I will go through the current credit agreement and answer those questions. We are not in a position to discuss anything relating to the converts at this time. I think we have made that fairly clear.

The current credit facility is -- I guess where we sit today, we have a little over $25 million and I think it is like $26.5 million of liquidity under -- as we sit today under our credit facility. The trigger points, there really are no trigger points as long as we stay focused and don't violate the agreement and go into default, which we project that we have no issues with that going forward. And then I think that is pretty much what you asked.

With respect to the puts coming due in the middle of next year and our current credit agreement maturing in January of next year, as we said, we are considering many options, and we believe that we have plenty of time to execute successfully, and we believe that whether or not these new wells come in, we will execute successfully. We are just not prepared at this time to be discussing those options.

Gregg Brody, JPMorgan.

You mentioned you were not providing a 2011 CapEx budget yet. But I was wondering if you could give some details around the wells you said you were going to drill this year in terms of the completion, how much that would cost, and just on the five wells you are planning on completing?

Okay. This is Carl, and I will try to walk through what I will call our base case for CapEx. And this is really the activity that is either in process or currently contemplated. Of the five inventory wells we had at the end of the year, we have actually completed three of them already. We have two yet in front of us to complete, and those completions should run somewhere between $1.2 million and $1.4 million per to do the fracs and the Gen IV and the facility hook up on the Williams Fork wells.

We also have the deep well that is all the way down at 13,300 that we have to complete, as well as the Mancos test well in front of us to complete.

And then finally, we have a lease preservation well that we will be drilling in May to help solidify some acreage up in the Northeast part of our leasehold. And that really concludes the bulk of the currently contemplated activity. Obviously results of those could create changes in our capital expected beyond that, but at least right now, that is what is currently on the plate.

Most of that sounds like first quarter and some second quarter. Is that right?

Yes, that is correct.

And then just the cost of drilling the water disposal wells, how much would that cost you?

Well, the conversions of the disposal wells are going to be about $250,000 per, and we are going to do four of those. We may or may not drill -- have to drill a disposal well. And if we did, it would not be -- (multiple speakers). Yeah, $1 million is a reasonable number. It could be less, but that is a good number.

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

Thank you very much for attending our conference call. As you can see, we are pleased with the operational performance that Delta is showing, and we look forward to speaking with you again. Thank you.

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