Good afternoon. My name is Sarah, and I'll be your conference operator today. At this time, I would like to welcome everyone to the First Quarter 2012 Earnings Release Conference Call. [Operator Instructions] Thank you. Mr. Cassidy, you may begin your conference.

Thank you, Sarah. Good afternoon, everyone, and thank you for joining us for Apache's First Quarter 2012 Earnings Conference Call. This morning, we reported earnings of $778 million or $2 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results, totaled $1.2 billion or $3 per diluted share. Cash flow from operations totaled $2.6 billion for the quarter. On today's call, we will have 3 speakers making prepared remarks prior to taking questions. First, we will hear from Steve Farris, our Chairman and Chief Executive Officer; followed by Rod Eichler, President and Chief Operating Officer; and finally, Tom Chambers, Executive Vice President and Chief Financial Officer. We prepared our quarterly supplemental data package for your use, which also includes a reconciliation of any non-GAAP numbers that we discuss such as adjusted earnings, cash flow from operations or pretax margins. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussion may contain forward-looking estimates and assumptions, and no assurances can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thanks, Patrick, and good afternoon, everyone, and thank you for joining us today. The first quarter of 2012 continued Apache's strong growth in production, earnings and cash flow. Our daily production during the quarter was up 7% from the first quarter last year adjusted for divestitures. And I want to point out that this growth came despite having about over 10,000 barrels of oil equivalent a day off during the quarter due to production disruptions, and Rod Eichler will get into more detail a little later in the presentation. Our corporate production growth expectations for the year remains strong between 7% and 13% over 2011 with a capital program that, I might add, that lives within our cash flow. We are continuing to build production momentum, and I'd like to mention just a few of the highlights of the quarter before I turn it over to Rod who'll give you a more detailed operational report. In the Permian Basin, we entered the quarter with 26 rigs running. We now have 31 rigs running, going to 34. We have had good results in the Wolfcamp horizontal and the lower Cline plays, and we continue to accelerate as we get after a Permian drilling and resource portfolio that is really second to none. In the Mid-Continent liquids play, we entered the first quarter with 6 rigs running and currently operate 22. We continue to have attractive and consistent results across a number of liquids plays from the Granite Wash, the Tonkawa, the Cleveland, the Marmaton, Cherokee and the Canyon Wash. Our drilling inventory in the Mid-Continent is very comparable to that in the Permian, and we are more than tripling our activity in order to translate that activity into production and cash flow today. Importantly, we have the asset strength to do…

Thank you, Steve. We had another solid quarter of growth, and we're really just getting started. I'll begin with international as the bulk of our new volumes in the quarter came from the North Sea, where we completed the acquisition of Mobil North Sea Limited's Beryl and other fields at the end of last year. Production is up 67% year-over-year and 41% sequentially with plans in motion for continued growth. Apache assumed operatorship on December 31, including taking onboard 184 staff members from the previous organization to bring with them a wealth of experience and ideas for adding value. These fields had largely been in decline due in part to minimal investment from the prior operator who focused primarily on maintenance and compliance. As we did at Forties, we expect to reverse the direction of the production curve by acquiring and processing new seismic data, drilling wells and continuing workovers and other value-adding activities. Overall, the general infrastructure and platforms are in good shape, although we're dealing with obsolescence in certain areas, which isn't unusual for mature offshore assets. We recently drilled a new well from the Beryl Bravo platform, known as the BBP prospect, that we're currently completing and should have online later this month. Our team in Aberdeen is very excited about this one because we found virgin reservoir pressure in 2 of 3 zones containing more than 300 feet of net true vertical pay. This should be a very robust well and opens up further development opportunities. A 1,500 square kilometer 3D seismic survey is scheduled to commence during the third quarter, and we expect this program will significantly supplement the backlog of drillable locations on these newly acquired assets. This will be the first 3D acquired over the Beryl area licenses since 1997, and we are…

Thanks, Rod. Good afternoon, everyone. As you've seen by now, we reported earnings of just under $780 million and $2 per diluted share. These numbers tend to mask our underlying financial performance, which continues to provide a platform for long-term profitable growth across our region. I'd like to emphasize what was mentioned previously both by Rod and Steve, in that we continue to grow our business, achieving record levels of production this quarter averaging 769,000 barrels of oil equivalent a day. Coupled with record oil prices, our revenues were the best ever at just under $4.5 billion for the quarter with oil revenues costing $3.5 billion, accounting for 79% of the total. More importantly, these factors resulted in continued strong cash flow with cash from operations before working capital items of $2.6 billion, up 18% from the prior year quarter and in line with last quarter. Our continued ability to generate significant amounts of cash flow from our asset base has enabled us to fund our robust E&D capital program across the globe. And getting after our capital program is critical in realizing the opportunities we have gained through our recent acquisition activity. We've been able to sustain this cash flow despite increasing pressure on North American gas prices, particularly in Canada. As in past quarters, our balanced portfolio has allowed us to benefit substantially from our oil position and the fact that oil currently sells for about 43x the price of North American natural gas. In addition, our international gas portfolio has also provided balance, helping to mitigate a 22% decline in North American natural gas prices from the year-ago period. First quarter 2012 international gas realizations were 17% higher than a year ago and 7% higher than the last quarter, driven by our new sales contracts in both…

We will now open the call to questions. Operator?

[Operator Instructions] Your first question comes from the line of Arun Jayaram with Credit Suisse. Arun Jayaram - Crédit Suisse AG, Research Division: Yes, I wanted to talk firstly, just trying to set the baseline where guidance is set on the production side. I know you had some asset sales late in the year that maybe impacted Q1 in terms of growth. But I just wanted to better understand what the baseline of the 7% to 13% growth is based on.

It's the beginning of the year trend [ph] sale basically. So I think you heard it pretty much throughout the presentation. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. So we're basically just taking your 2011 growth, backing off the...

About 11,000 barrels of oil, yes. Arun Jayaram - Crédit Suisse AG, Research Division: Okay, okay. That's fair. And Steve, I just wanted to see if you could talk about your confidence perhaps in the middle part of the range. You are starting off a little bit of a lower starting point. Just give us a sense of your confidence to reach perhaps the middle point of that range.

Well, let me put it this way. I feel very comfortable we're going to be ahead at the low end of that range. Arun Jayaram - Crédit Suisse AG, Research Division: Okay. And what do you think would you have to see to get to that middle part of the range in terms of your overall portfolio?

Well, the results that we're going to have in the second quarter are going to be important, obviously. As you move out, the wells you drill in the first 2 quarters are really what sets the stage for your overall production growth. So I'm hopeful we show some added growth in the second quarter and certainly in the first part of the third quarter. We've got a very active drilling program going on right now, most active we've been in some time in North America. Arun Jayaram - Crédit Suisse AG, Research Division: Fair enough. One quick question in terms of Egypt. The gas price, I just wanted to get a little bit of color around the decline of the gas prices. I do know next year contractually, the gas price goes down just because of an expiration of a contract. But I just wondered if you can talk about that quarterly swing and the dips in gas prices.

This quarter, we had an adjustment in the gas price. There was some gas that was booked at that old gas price that wasn't that. So you saw a reduction in the gas price to make up for that error last quarter. It was a onetime quarter deal.

Our next question comes from the line of Doug Leggate with Bank of America.

If I could try a quick follow-up on the Gulf question. Steve, when you say year-over-year, you've obviously had the Beryl acquisition and the Cordillera acquisition. So is the growth target organic growth target or total growth target?

It's a total growth target.

Okay. I just wanted to clarify that. Getting into the details a little bit, can we talk about the outlook for Australia this year? Because obviously, with Coniston scheduled to come onstream, I guess, in a year or so time, there's still I guess some debate over what you're going to do with the FPSO down there. So could you give us an idea as to what the expected downtime will be.

Yes, Rod?

Well, we have a combined Coniston, Ningaloo Vision, which is the name of the FPSO rectification project, which is sort of working both a subsea development in tandem with the repairs and modification. These are making them both. So the -- excuse me, [indiscernible] significant servicing work in early part of 2013. I forget the exact amount of days or weeks that it will be out of service before returning to the field later that year to be able to commence production for the combined Coniston and Van Gogh. I'm sure Patrick can get back with you with that number after the call.

Okay. So the downtime is next year, not 2012?

That's correct.

Okay. Second one for me, Steve, again, just I want to get back to you just again. Unfortunately, it still comes up as an issue, an overhang in terms of the uncertainty over there. One issue I wanted to get some clarity on is the risk of devaluation of the Egyptian currency. How does that affect your business? And I'll leave it at that.

Well, Rod might wanted to jump in there too. In terms of -- we get paid in U.S. dollars. In fact, we export the biggest bulk of our crude production, and that's based on dollars. And the gas sales to Egypt you see are based on U.S. dollar equivalent. So we really shouldn't have any impact based on the dollar side other than maybe a little higher op costs just because they're paid in Egyptian pounds. Egyptian workers are paid in Egyptian pounds.

Your next question comes from the line of John Freeman with Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: Focusing on sort of the weakness we've seen on NGL pricing, especially sort of in the Mid-Con region. I believe you've got like a pricing contract that's coming up pretty soon that's due on the technical side. Just sort of how you are thinking about it, maybe various options that you're considering to maybe address what's going on in the NGL pricing.

Well, actually, there's an awful lot of work going on in the industry around that in terms of pipelines, and we're not excluded from that concept. And this is a little longer-term view of life. And it's quarter-to-quarter, but a little bit like we're facing in the Permian Basin. With the resource potential both in the Anadarko Basin and the Permian Basin, the easiest thing to pick is infrastructure, frankly. I mean, it's an industry we're facing that in the Permian, and it's -- those things are going to get built. It might be a quarter late, and everybody wants to project in their numbers. And I don't have any specifics associated with it. I'm just talking a little bit like Crosstex and our step there. In all truthfulness, I don't worry about infrastructure if the wells are good enough. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. If I just shift over to the Permian. Of the 31 rigs you got at the moment, you mentioned 6, right now, are focused on horizontal. I'm trying to get a sense of, around the end of the year, what you would envision that split looking like in terms of horizontal versus vertical.

Well, it's an interesting situation in the Permian. Actually, it's unlike what's happening in the Anadarko Basin. We've got 22 rigs running in the Anadarko Basin. 21 of them are horizontal. In the Permian, that's a much lower number than the industry. In 2010, the number of horizontal wells in the Permian Basin was less than 10%. In 2011, it was a little bit more than that, which you're going to see in the Permian Basin. The same thing is happening in the Anadarko Basin, and the majority of them are going to be horizontal as we get into the future. Right now, I think we're projecting something like 700 wells, of which about 100 of them will be horizontal this year. A little over 100 of them will be horizontal.

And that number is actually weighted heavily on the Deadwood side because over 300 of those wells that are in Deadwood this year, and those are almost all vertical wells, structural reservoir, targets deeper.

And we've got a couple of Cline horizontal wells in there, and we will drill more of Cline horizontal wells in the future. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And just a final question for me. On New Zealand, I believe the first of the 4 wells that you all had planned there was going to spud during the second quarter. Is that still the case?

Yes, it's either the second quarter or the first part of the third quarter. We just -- Rod and I just reviewed that.

Your next question comes from the line of Michael Hall with Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Just curious, as you kind of step back and kind of look at Canada and the opportunity there, kind of in unconventional liquids in particular, I guess how would you characterize that and its lifecycle relative to the U.S. And sorry if I missed it, but did you identify kind of how many, let's say, horizontal unconventional liquids targets you have up there this quarter?

Well, the first question, I will tell you, it's in infancy. What some of the things we're doing on our acreage in the Provost in that area, actually, we've got a huge acreage position there that we're just now beginning to exploit. And that's shallow oil. That's 3,500 to 4,000 feet. And actually, we've had very good success there. Some of the other stuff that you -- the Cadomin and that kind of stuff over to the West, that's a little further along. In fact, what happens in Canada is it's late in coming. I mean, I'll be real honest with you. If you look what happened to gas prices. Everybody was a gas player in Canada until we saw what's happened over the last 18 months on gas prices. So we're not the only ones making that switch. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Sure. Okay. And then just on, the interruptions that we're seeing during the quarter, if I heard that right, I think about 10,000 barrels a day offline. Did those come fully back on in the second quarter?

Well, the ESP work, part of it will be -- we had the turnaround at -- I think it's Bravo on Forties. The ESPs, we've got a rig that we're going to try to pull out there and do some recompletions and pull those pumps on the ESPs. Those may not all be done this year -- I mean, this quarter. But we also have a couple of other good things happening. That Beryl well that Rod mentioned is maybe the best well drilled in Beryl in the last 20 years. And I'd say that, we haven't gotten the test on it yet. So the best thing about it is we haven't tested it yet. It looks fantastic on the logs. I mean, it's virgin pressure. It could be the best well in the Beryl field in the last 20 years.

This is Roger. Then there was 1,500 barrels a day in the Central region, which from a plant downtime, assuming another plant doesn't go down, that would be back online. And then typically, it isn't cyclone season.

We're done with the cyclone season now. We're out of it as of this weekend.

So that's 4,000 barrels a day. So most of it ought to be back online.

Your next question comes from the line of David Tameron with Wells Fargo.

I have to ask, Egypt, can you just give us an update on anything since your last update as far as progress there and the new government and kind of where we stand on that?

Yes, and then again, Rod probably has some comments, too. I will -- Rod and I were in Egypt about 1.5 months ago. I think what you...

Because of the very large concession, because we have a sizable resource. Likewise, the 8 recompletions I referenced and the 5 new drills, those will be focused, for the first time our drilling will be focused in the oil window portion in areas that were very similar and adjacent to like VF and other companies' activities that have had press releases. And we're very encouraged by that outcome. They're on our core concession areas. We had some of our principal productions in the Neuquén Basin, and it's -- we'll have probably more to say about that on our June 14 meeting.

Yes, I think it's safe to say we've gotten some cores. We've done some recompletions down in the oil window, which gives us very good encouragement to drill at least 5 or 6 horizontal wells in the Vaca Muerta shale oil.

That shale is much shallower in those areas compared to the 2 concessions I referenced.

Excellent. Excellent, I appreciate that color, and very quickly on the North Sea, looks like you guys -- the activity's paying off there. How sustainable do you see the rates there for this year that we're seeing out of the North Sea for you?

Well, I think it's early times. I will tell you, the Forties will, we will get that back, and that will be pretty steady. The good thing about the well that we just drilled is we really anticipate having more resource potential there than we thought we did going into it, frankly. I mean, in all honesty, this well found pay but it found much more pay than we thought it would. So it gives us added hope that, that resource potential there is bigger than what we had evaluated.

Your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Your U.S. gas volumes quarter-to-quarter down about 48 million a day. Is that because of the divestitures?

Well, you bet. It was actually the divestitures were a little more than that. So that...

50-plus.

I think it was almost 50 million a day. So you're looking at numbers that are comparable to last year. Pearce W. Hammond - Simmons & Company International, Research Division: And Steve, have you seen your gas volumes start to level off in the U.S. or actually decline? Or are they still growing?

Well, if you look at whether it's us or anybody else, when we talk about all of these liquid-rich plays, the Marmaton well that Rod mentioned is making over 800 barrels of oil a day. It's also making 10.5 million cubic feet of gas per day. And we've got 90% of that well. We've got a -- the Marmaton is going to be a good play. We've got -- it's not nearly as continuous as all those plays, but we've got, we've picked up a very big acreage provision from Cordillera in that play, and that's the second or third well drilled in the Marmaton, only second or third well drilled, so, so far, that's -- but you're going to see a lot of gas besides the liquid side of it.

If I might comment, we've got 60 rigs running in America now, and 58 are targeting liquids-rich and oil. So to the extent -- we're a lot like everybody else, dry gas, we're just not drilling for. The other thing that might have gotten lost in the numbers is our gas production was up 3% sequentially. Well, it's because even though we're down in North America by about 40 million a day with the property sales, we're up 110 million abroad, which is, as Steve pointed out, we've got $4.02 during the quarter. It rose $0.27 from the prior quarter. Internationally, it's the first quarter where we're seeing our international prices higher than our North American prices. So our revenues are climbing internationally on the gas side. Pearce W. Hammond - Simmons & Company International, Research Division: Great point. Great point. And then just one follow-up. If you could provide an update on Kenya.

Kenya should spud in the latter part of July. We've secured a rig. In fact, Rod and I reviewed that a couple of days ago. We should spud that well in the latter part of July.

Your next question comes from the line of Matthew Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick follow-up questions for me. Along the same vein on the U.S. gas production, could you provide any additional color on potentially how that could trend over the year if you're expecting kind of a steady increase or at some point, we'll see that leveling out? And then within Canada, as there has been historically a little bit more gas-focused, should we be thinking about those volumes declining and any potential risk on shut-ins?

We just quickly looked at our outlook. I would suspect if our outlook is correct, our gas from the U.S. is pretty well flat, maybe a little up. In terms of -- what was -- the other one was about Canada? Yes, shutting in production is if it covers operating costs, there's no economic reality to it. And I don't anticipate us in any of our gas deals to get to the point where we shut in gas because the operating costs are higher than the price we're receiving. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just to follow-up on that, I guess within Canada, and this might be an unfair assumption, but I'm assuming there's a little bit less liquids-rich drilling activity at the moment from you guys. Should we think directionally your Canadian volumes should start to decline at some point this year on the gas side?

Well, you'd presume that, that would be the case with virtually no wells targeting dry gas up there. I wanted to clarify one thing on Steve's point. When he said flat, he's really, I think, thinking from this day forward with Cordillera built in because we're, of course, picking up quite a bit of gas there. So we ought to be able to have U.S. volumes flat to rising somewhat through the balance of the year.

Your next question comes from the line of Brian Singer with Goldman Sachs.

On the LNG side, we've seen a number of LNG contracts signed for U.S. LNG here year-to-date. Can you give us an update on how you see the strength of the market, particularly the Asian market? And then given your advantageous geographic position at Kitimat to serve the Asian market, can you refresh us on what the key constraints are to an announcement on Kitimat? Is it the FID that gives you confidence in the greenfield costs or some other reason?

Well, we -- and Rod again could do this a lot more in detail. But we are pretty much done with the FEED. I mean, I can't tell you enough that the real bottom line for Kitimat or any of these projects, what's happening in the U.S. is an anomaly. It's not a greenfield development. So what you're looking at, whether it's us or Shell, I read this morning that Imperial's thinking about getting in the business, all of those contracts are going to have to be oil-based contracts. And we truthfully are in the throes of negotiations for a very, very -- a tenant that could underpin that development. But we're not there until we're there. So we're continuing to negotiate. We're also continuing to declare right-of-way for the pipeline, and we're working towards the construction of the LNG facility. It's not a cost, as much as it is -- of course, they're, like anything, cost and price, are synonymous. I mean, it's -- but we haven't seen great increases on the cost side as we move through FEED.

Okay. And my follow-up is, can you just refresh us post-Cordillera acquisition, what we should expect to see your corporate CapEx run rate to be as we go through the rest of the year?

Yes, we're going to stay within our cash flow. I don't know where our capital budget was for this first -- I mean, I know, but round numbers...

9.5 is what we said.

Yes, and it's 9.5 to 10, honestly. We're going to have cash flow, usable cash or spendable cash around $10 billion for the year. And that's -- whatever we have is going to go on the ground.

Okay. But no other changes beyond, I think, a slight point you made on Argentina?

No, no, I mean, we're going -- we increased it $50 million to drill those Vaca Muerta shale wells. So it's not a huge bump.

The way we look at that, you heard about the increases in the rig count in the Mid-Continent or Central region, Anadarko Basin, also in the Permian. And if cash flow holds up, then we'll just keep that many rigs or more running. And if cash -- if prices come down, then we might cut that back later. So that's kind of how we jigger it to live within cash flow.

Your next question comes from the line of Leon (sic) [Leo] Mariani with RBC.

Just looking for a little bit more clarity there on Kitimat. Do you guys still think you'll make a decision to potentially build over the project by the middle of the year?

I can't -- I don't think I can be more -- we're going to make a decision when we have all of the Is dotted and Ts crossed, and the most important I dotted and the T crossed is to have an MOU that is good enough in order to -- on the sales side, in order to take this project forward in an economic basis. And if that comes in the middle of the year, it will be middle of the year. If it comes in the third quarter, it will be in the third quarter.

All right. Can you guys comment on the big onetime D&A expense this quarter?

Again, Leo?

You had a big onetime D&A expense this quarter like $520 million. Can you...

Yes, that was the Canadian write-off.

Okay. Got you...

That was total in cash.

Got you. And can we get some more color on the discovery you made in Australia you talked about earlier?

Well, Tallaganda is a project that's about 100 kilometers southwest of our DeSoto discovery from 2011. As I indicated in my remarks, it covers about 190, 160 feet per day [ph]. But the well is operated by BHP. We really have to defer our comments to the operator. Right now, we're evaluating the results of the well to see the forward path on future development. But we have to follow BHP's lead.

Got you. And do you think that's oil or gas?

Well, I think I'd defer to the operator. I hope based on whatever press releases they've had out there, which is I don't think they've had much the way it's...

Your next question comes from the line of John Malone with Global Hunter Securities.

On Australia, it looks like CapEx was down a bit quarter-on-quarter. Is that just the general lumpiness of projects? [indiscernible] a trend there? And also on that, when do you start to see LNG spending really start to kick in?

Well, yes, quarter-on-quarter, they may be just a little bit behind, but I fully expect them to achieve their targeted CapEx amount for the year. We've reviewed this on a monthly basis on our call just 2 days ago. As far as the LNG, we have some of the initial LNG-related. Some expenses are beginning late last year and throughout 2012. But the really big spike in those expenses will come in late 2013 and 2014 when the subsea is opened. It gets in place in fabrication and the central processing plant form and the gas plant begin in earnest.

Okay. And then just going over to Egypt for a second, I think you mentioned it before, but what was the gross production would have been without the PSE effects?

Growth production was up 1% on a BOE basis, and our gas, oil prices were up 16%, which is basically on a PSE basis, we get less product in order to get the same cash back. So our oil was down about 4,500 barrels a day on a net basis. But it's -- on an overall gross uptick basis, it was up. So you'll see that turn around again next quarter.

My simple way of describing that is if you got $100 of costs to recover and oil is selling at $100, then you've got 1 barrel. And if you have $50 oil, then you get 2 barrels. So when prices go up, it works the opposite of that.

Okay. And then just on Egypt, you were talking about the politics, just I know you can't extrapolate, as to what you think Egyptian politics are going to do, but how do you think it affects your gas prices if subsidies were eliminated or curtailed?

Well, they've been talking about curtailing subsidies for at least a decade. I guess the good news in that is they actually made it a very transparent part of their budget about 7 or 8 years ago that we actually see the big elephant that is in the room. The subsidies or energy budget gas and oil refined products is probably going to run 115 billion Egyptian pounds in the coming budget year from what I read, which is significantly a lot lower than it was a few years ago, which is about 70 something-billion pounds, about $10 billion. I don't think that the subsidy issue is going to be resolved anytime soon. I mean, we may see some effects on the refined products like gasoline. But to give you an idea of just how extreme that subsidy is, 92 octane gasoline, I just read this morning, the subsidy sells at the equivalent price of $1.09 U.S. per gallon. The people who burn 92 octane are people with nice cars, not poor people or farmers with tractors and use lower octane fuels. So that's a pretty healthy subsidy for people who could afford to pay a regular price. I think the near term, what we're going to be faced with, at least for the next 5 years, I would expect to see the same contractual gas price on our gas sales agreements, which is tied $2.65 per million BTU. Unfortunately, we have very rich gas that we get more than that, $3 to $4 per Mcf basis, and oil price, of course we receive the world price based on our export volumes on the Brent market.

At this time, there are no further questions. Presenters, do you have any closing remarks?

Yes, Sarah, I do. Thank you for participating in our first quarter earnings call. I do want to acknowledge that we've been just made aware of some technical difficulties with the sound. So I want to apologize to those who were listening or will be listening to the playback. We will have the playback on our website within 1 hour. And thank you again for your participation.

This concludes today's conference call. You may now disconnect.